william j. andrews...2020/05/04 · bcsea final argument may 4, 2020 bc hydro f2020-f2021 rra page...

of 1

William J. Andrews Barrister & Solicitor

1958 Parkside Lane, North Vancouver, BC, Canada, V7G 1X5

Phone: 604-924-0921, Fax: 604-924-0918, Email: [email protected]

May 4, 2020

British Columbia Utilities Commission

Sixth Floor, 900 Howe Street, Box 250

Vancouver, BC, V6Z 2N3

Attn: Patrick Wruck, Commission Secretary

By Email: [email protected]

Dear Sir:

Re: Re: British Columbia Hydro and Power Authority,

F2020 to F2021 Revenue Requirements Application,

BCUC Project No. 1598990

B.C. Sustainable Energy Association Final Argument

Attached please find BCSEA’s Final Argument in this proceeding.

Yours truly,

William J. Andrews

Barrister & Solicitor

Encl.

cc. Matt Ghikas

mailto:[email protected]

BRITISH COLUMBIA UTILITIES COMMISSION

British Columbia Hydro and Power Authority F2020 to F2021 Revenue Requirements Application

BCUC Project No. 1598990

Final Argument

of

BC Sustainable Energy Association

May 4, 2020

William J. Andrews, Barrister & Solicitor 1958 Parkside Lane North Vancouver, BC, V7G 1X5 Phone: 604-924-0921, Fax: 604-924-0918 Email: [email protected]

mailto:[email protected]

Contents PART ONE: INTRODUCTION AND SUMMARY ............................................................. 5

A. FINAL ARGUMENT OF BCSEA .............................................................................. 5

B. BCSEA’S INTERESTS IN THE PROCEEDING ....................................................... 5

C. HIGH-LEVEL SUMMARY ........................................................................................ 6

D. ORGANIZATION OF ARGUMENT .......................................................................... 7

E. RESPONSES TO PANEL’S THREE QUESTIONS .................................................. 7

F. BC HYDRO’S INTRODUCTION .............................................................................. 8

PART TWO: LEGAL FRAMEWORK AND SCOPE OF THE PROCEEDING ................... 8

PART THREE: PROVIDING SAFE, RELIABLE AND COST EFFECTIVE SERVICE, COMPLEX ENVIRONMENT ........................................................................................... 9

A. CONTAINING CONTROLLABLE COSTS ............................................................... 9

B. DEMANDS ON BC HYDRO .................................................................................. 10

C. ADDITIONAL INVESTMENT AFTER THE TEST PERIOD .................................... 11

PART FOUR: LOAD AND REVENUE FORECASTS ..................................................... 11

A. INTRODUCTION ................................................................................................... 11

B. SNAPSHOT OF THE OCTOBER 2018 LOAD FORECAST UNDERLYING THE EVIDENTIARY UPDATE ........................................................................................... 12

C. LOAD FORECAST METHODOLOGY ................................................................... 12

D. TEST PERIOD LOAD FORECAST ....................................................................... 12

E. THE CONFIDENCE INTERVAL AROUND THE MID FORECAST ........................ 12

F. THE JUNE 2019 20-YEAR LOAD FORECAST UPDATE IMPACTS THE YEARS AFTER THE TEST PERIOD ...................................................................................... 13

G. THE OCTOBER 2018 LOAD FORECAST, ASSUMED FORESTRY SUB-SECTOR DECLINE ................................................................................................................... 13

H. THE LOAD FORECAST AND THE PORTION OF THE CLEANBC “UPSIDE” POTENTIAL THAT CAN BE ASSESSED AT THIS TIME .......................................... 13

I. REGULATORY ACCOUNTS TRUE-UP VARIANCES FROM THE LOAD FORECAST ............................................................................................................... 14

J. REVENUE FORECAST, INDUSTRY STANDARD, PAST PRACTICE ................... 15

K. CONCLUSION AND REQUESTED FINDINGS ..................................................... 15

PART FIVE: FORECAST COST OF ENERGY .............................................................. 15

A. INTRODUCTION ................................................................................................... 15

B. FORECAST INCREASE IN THE COST OF ENERGY DRIVEN BY EXISTING EPAs, FOR WHICH COST RECOVERY IS DIRECTED ............................................ 15

C. BC HYDRO, STEPS TO MITIGATE IPP ENERGY COSTS .................................. 16

D. FORECAST COST OF ENERGY, HOW BC HYDRO OPERATES THE SYSTEM 16

E. BC HYDRO, HERITAGE ASSETS ........................................................................ 20

F. VARIANCE ACCOUNTS, CUSTOMERS PAY ACTUAL COST OF ENERGY ....... 21

BCSEA Final Argument May 4, 2020 BC Hydro F2020-F2021 RRA Page 3 of 74

G. CONCLUSION AND REQUESTED FINDINGS ..................................................... 21

PART SIX: OPERATING COSTS .................................................................................. 21

A. INTRODUCTION ................................................................................................... 21

B. OPERATING COSTS SNAPSHOT: COST PRESSURES WITH OFFSETTING TEST PERIOD SAVINGS .......................................................................................... 21

C. BCUC’S RECOMMENDATIONS AND COMMENTS ON OPERATING COSTS .... 22

D. BC HYDRO BUDGETING, GOVERNANCE PROCESSES, COST CONTAINMENT EFFORTS .................................................................................................................. 23

E. CONTROLLABLE COST PRESSURES WITHIN EXISTING BUDGETS, INCREASES AND UNCONTROLLABLE COSTS ...................................................... 23

F. MEANS TO CONTROL COSTS AND ABSORB NEW UNCONTROLLABLE OPERATING COST PRESSURES ............................................................................ 25

G. FTE NUMBERS, WORK ON SITE C, AND INSOURCING .................................... 26

H. OPTIMIZING POWER SYSTEM MAINTENANCE ................................................. 26

I. BRATTLE REPORT AND INDICATIVE COMPARISON, BC HYDRO’S OPERATING COSTS ...................................................................................................................... 27

J. CONCLUSION AND REQUESTED FINDINGS ...................................................... 29

PART SEVEN: CAPITAL EXPENDITURES AND ADDITIONS ...................................... 29

A. INTRODUCTION ................................................................................................... 29

B. BC HYDRO’S EVIDENCE SUPPORTING CAPITAL FORECASTS, AMOUNT, CAPITAL FILING GUIDELINES ................................................................................. 29

C. CAPITAL PLANNING PROCESS .......................................................................... 30

D. REDUCED CAPITAL FORECAST, AFFORDABILITY, SYSTEM PERFORMANCE AND RISK.................................................................................................................. 30

E. DELIVERY OF CAPITAL PROJECTS, EFFICIENCY, EFFECTIVENESS ............. 30

F. BC HYDRO’S CAPITAL MANAGEMENT PROCESSES, ENDORSEMENTS BY THIRD PARTIES ....................................................................................................... 31

G. AMORTIZATION OF CAPITAL ADDITIONS REGULATORY ACCOUNT, CUSTOMERS ONLY PAY ACTUAL COSTS ............................................................. 31

H. EXPENDITURES ON RIPRAP FOR W.A.C. BENNETT DAM ............................... 32

I. VARIANCE OF DIRECTIVE 3, MINETTE TO LNG CANADA PROJECT ................ 32

J. SPECIFIC ISSUES RAISED .................................................................................. 33

K. CONCLUSION AND REQUESTED FINDINGS ..................................................... 38

PART EIGHT: REGULATORY ACCOUNTS.................................................................. 39

A. INTRODUCTION ................................................................................................... 39

B. BC HYDRO’S REGULATORY ACCOUNTS, ACCOUNTING STANDARDS AND BCUC GUIDELINES .................................................................................................. 39

C. MERITS OF EACH REGULATORY ACCOUNT, NUMBER OF ACCOUNTS ........ 40

D. BC HYDRO’S REGULATORY ACCOUNTS, BENEFIT TO CUSTOMERS ............ 42

E. AUDITOR GENERAL’S CONCERNS ABOUT REGULATORY ACCOUNTS ......... 44


F. BC HYDRO MANAGEMENT OF REGULATORY ACCOUNT BALANCES ............ 45

G. BC HYDRO’S PROPOSED CHANGES TO REGULATORY ACCOUNTS ............ 47

H. FORECAST FOR REAL PROPERTY SALES ....................................................... 49

I. CONCLUSION AND REQUESTED FINDING ......................................................... 49

PART NINE: OTHER REVENUE REQUIREMENTS ITEMS ......................................... 49

A. INTRODUCTION ................................................................................................... 49

B. TEST PERIOD REVENUE REQUIREMENTS, DEPRECIATION RATES .............. 49

C. FORECAST FINANCE CHARGES ........................................................................ 49

D. INTERGROUP’S RECOMMENDATIONS REGARDING BC HYDRO’S FUTURE RETURN ON EQUITY ............................................................................................... 50

E. CONCLUSION AND REQUESTED FINDINGS ..................................................... 50

PART TEN: TRANSMISSION REVENUE REQUIREMENTS ........................................ 50

A. INTRODUCTION ................................................................................................... 50

B. TRR AND OATT RATES ....................................................................................... 50

C. THE OATT RATE DESIGN ................................................................................... 50

D. CONCLUSION AND REQUESTED FINDINGS ..................................................... 51

PART ELEVEN: DEMAND-SIDE MANAGEMENT......................................................... 51

A. INTRODUCTION ................................................................................................... 51

B. MODERATION APPROACH, ENERGY SURPLUS ............................................... 52

C. BC HYDRO’S TRADITIONAL DSM PLAN, BCUC DIRECTIVES, GOVERNMENT PRIORITIES, AND DSM REGULATION .................................................................... 54

D. DIRECTIVE 61 REGARDING ALLOCATION OF PORTFOLIO COSTS, RESCISSION ............................................................................................................ 62

E. TRADITIONAL DSM, UCA, CLEAN ENERGY ACT, AND DSM REGULATION .... 63

F. THE EXPENDITURE SCHEDULE EXCLUDES THERMO-MECHANICAL PULP EXPENDITURES ....................................................................................................... 67

G. LOW CARBON ELECTRIFICATION EXPENDITURES, PRESCRIBED UNDERTAKINGS, COST RECOVERY IS MANDATED ............................................. 67

H. BC HYDRO MANAGEMENT OF TRADITIONAL DSM AND LCE INITIATIVES .... 71

I. CONCLUSION AND REQUESTED FINDINGS ....................................................... 72

PART TWELVE: IMPLEMENTATION OF RATES AND CONSIDERATION OF NEW INFORMATION ............................................................................................................. 72

A. INTRODUCTION ................................................................................................... 72

B. BC HYDRO’S RATE IMPLEMENTATION PROPOSAL, INTERESTS OF BOTH CUSTOMERS AND THE COMPANY ........................................................................ 72

C. UPDATING EVIDENTIARY UPDATE INPUTS ...................................................... 73

D. CONCLUSION AND REQUESTED FINDING ....................................................... 74

PART THIRTEEN: CONCLUSION AND ORDER SOUGHT .......................................... 74


PART ONE: INTRODUCTION AND SUMMARY

A. FINAL ARGUMENT OF BCSEA

1. This is the final argument of the intervener B.C. Sustainable Energy Association

(BCSEA) in the Commission’s proceeding regarding the BC Hydro Revenue

Requirement Application for F2020 to F2021.

2. This final argument responds to BC Hydro’s April 1, 2020 Final Argument.1 It also

addresses the three topics on which the Commission Panel requested submissions.2

B. BCSEA’S INTERESTS IN THE PROCEEDING

3. BCSEA is a registered charity and a non-profit association of citizens, professionals

and practitioners committed to promoting the understanding, development and

adoption of sustainable energy, energy efficiency and energy conservation in British

Columbia. BCSEA supports the province’s transition to a lower-carbon economy.

BCSEA has four chapters across B.C. and approximately three hundred individual

and organizational members (including businesses, NGOs, community

organizations, local governments). BCSEA represents individuals and organizations

in BC who care about energy sustainability and climate change mitigation, and who

want the energy they purchase and use to be sustainably produced and transported.

4. Members of BCSEA are ratepayers of BC Hydro. BCSEA’s interests in this

proceeding are as a non-profit public interest energy policy organization, and as a

representative of its members’ interests as ratepayers.

5. BCSEA’s interests in the proceeding are indicated by their participation in related

BCUC proceedings including:

a. BC Hydro’s F2017-F2019 Revenue Requirement Application and Demand-

Side Management Expenditures Schedule,

b. BC Hydro's 2015 Rate Design Application, and

c. BC Hydro Regulatory Oversight of Capital Expenditures and Projects.

6. BCSEA has participated actively in the current proceeding.

1 https://www.bcuc.com/Documents/Arguments/2020/DOC_57721_2020-04-01-BCH-

FinalArgument.pdf. 2 Exhibit A-31.

https://www.bcuc.com/Documents/Arguments/2020/DOC_57721_2020-04-01-BCH-FinalArgument.pdf

https://www.bcuc.com/Documents/Arguments/2020/DOC_57721_2020-04-01-BCH-FinalArgument.pdf


C. HIGH-LEVEL SUMMARY

7. BCSEA supports approval of BC Hydro’s F2020-F2021 Revenue Requirement

Application and acceptance of BC Hydro’s traditional DSM Expenditure Schedule for

the Test Period, subject to the specific reservations and comments set out in the

argument below.

8. BCSEA would strongly prefer a more ambitious traditional DSM spending envelope,

and a more ambitious amount of energy and capacity savings, in the Test Period. In

BCSEA’s view, the amount of low-carbon electrification needed for B.C. to meet its

legislated GHG reduction targets under the CleanBC Plan will put BC Hydro into an

energy and capacity deficit planning position sooner rather than later. BC Hydro will

then require all cost-effective traditional DSM savings. Despite BC Hydro’s

assurances, BCSEA is concerned that the “moderation approach” jeopardizes BC

Hydro’s ability to ramp up conservation and efficiency savings when they become

urgently needed. In addition, BCSEA is concerned that the decision not to achieve all

cost-effective energy and capacity savings during the Test Period will create “lost

opportunities” by allowing inefficient assets to be locked-in for the long term.

9. In BCSEA’s view, BC Hydro’s budget for low-carbon electrification is far too low.

BCSEA encourages BC Hydro to develop a comprehensive long-term plan for low-

carbon electrification measures across all sectors that will meet quantitative GHG

reduction objectives in order to achieve B.C.’s legislated GHG reduction targets.

10. BCSEA specifically supports the proposed increase in funding for the Low-Income

and Non-Integrated Areas DSM programs.

11. BCSEA strongly opposes BC Hydro’s decision to acquire biomass power from

contaminated retired rail ties under an EPA with Atlantic Power in Williams Lake..

12. BCSEA urges the Government to move expeditiously to allow BC Hydro (and

FortisBC Inc.) to recover their net costs of EV fast-charging stations up to a

reasonable limit. In addition, BCSEA recommends that the Legislature add “low-

carbon transportation” to the B.C. energy objectives in the Clean Energy Act.

13. BCSEA hopes and expects that there is room for improvement in BC Hydro’s

industrial load interconnection regime, particularly in order to foster low-carbon

electrification.


14. As a matter of terminology, in BCSEA’s view, intergenerational equity should not be

used as a synonym for benefits matching. The present generation enjoys the benefit

of investments made by earlier generations. It is incumbent on the current generation

to pay this forward to future generations. Intergenerational equity means that the

present generation must not defer to future generations the costs of benefits

received by the present generation. Intergenerational equity does not prevent the

present generation deferring to future generations the costs of benefits that will be

received by future generations: that is benefits matching, which is an accepted

accounting principle.

D. ORGANIZATION OF ARGUMENT

15. For convenience, this argument follows the 13-Part structure of BC Hydro’s Final

Argument.

E. RESPONSES TO PANEL’S THREE QUESTIONS

16. BCSEA’s summary responses to the Panel’s three questions and the location of the

discussion in this argument are set out in the following table.

Panel Question3 BCSEA Response

1. Whether the Peace Region Electric Supply project meets the requirements to be considered a prescribed undertaking under section 18 of the Clean Energy Act, pursuant to section 4(2) of the Greenhouse Gas Reduction (Clean Energy) Regulation;

Yes. Paragraph 130

2. Whether the Minette Station to LNG Canada Interconnection project meets the requirements of the Transmission Upgrade Exemption Regulation, as amended by B.C. Reg. 160/2018, to exempt the project from Part 3 of the Utilities Commission Act; and

Yes. Paragraph 127

3. Whether British Columbia Hydro and Power Authority’s investments in electric vehicle charging infrastructure should be included in rate base during the current test period and recovered from ratepayers or be separately tracked and excluded from rate base until the British Columbia Utilities Commission directs otherwise, given the developing landscape of the electric vehicle charging stations market in BC.

The former. Paragraph 133

3 Exhibit A-31.


F. BC HYDRO’S INTRODUCTION

17. BC Hydro says it has had two broad objectives for this proceeding. The first is “to

provide the Commission, interveners and customers with an open and transparent

view of its operations and cost structure and to be open to feedback and suggestions

received through this process.”4 In response:

a. BCSEA acknowledges that BC Hydro provided substantial new information

regarding its Operating Costs for each Key Business Unit (Application,

Chapters 5A to 5G) and its Capital Expenditures (Appendix K), compared to

the F2017-F2019 Revenue Requirements Application. This was very helpful.

b. BCSEA acknowledges that BC Hydro has provided a very large number of

very informative responses to information requests and questions during the

oral hearing from the Commission, the Panel and Interveners.

18. BC Hydro’s second broad objective is “to convey that BC Hydro’s revenue

requirements and requested rate changes reflect a pervasive culture of restraint and

cost containment in the face of external cost pressures and an increasingly complex

operating environment.”5 BCSEA considers that BC Hydro has met that objective

during this proceeding.6

PART TWO: LEGAL FRAMEWORK AND SCOPE OF THE PROCEEDING

19. BCSEA agrees with BC Hydro that there is no need for BC Hydro to distinguish

expenditures for export from other expenditures.7

20. Section 44.1 of the Utilities Commission Act (UCA) now applies to BC Hydro.8 This

means that BC Hydro’s next long-term resource plan (i.e., Integrated Resource Plan)

will be filed with the BCUC for review and acceptance under section 44.1 of the UCA,

rather than with the Minister of Energy under section 3 of the Clean Energy Act

4 BC Hydro Final Argument, para.1.

5 BC Hydro Final Argument, para.1.

6 In saying so, BCSEA is not commenting on any of the myriad issues within the proceeding.

7 Exhibit B-5, BCUC 1.2.1, pdf p.37.

8 Exhibit B-6, BCSEA 1.3.1, pdf p.627. Energy Statutes Amendment Act, 2019, 2019-24-2,

effective May 16, 2019 (Royal Assent).


(CEA), which has been repealed. The requirement that BC Hydro file a long-term

resource plan with the BCUC comes into effect on February 28, 2021.9

21. While the Remote Communities Regulation10 remains in effect, BC Hydro ended the

Remote Community Electrification Program in 2014. BC Hydro says, “Any future

consideration of communities which may be added to the Remote Communities

Regulation will be undertaken by BC Hydro on an individual project by project

basis.”11 BCSEA does not take issue with that approach. BCSEA supports the

addition of communities to the Remote Communities Regulation in the future. Also,

BCSEA supports measures by BC Hydro and the communities in question to reduce

GHG emissions caused by reliance on diesel generation in Non-Integrated Areas.

22. BCSEA does not take issue with BC Hydro’s view that the Auditor General’s

comments regarding the use of rate-regulated accounting at BC Hydro in F2019

have been satisfied.12

23. BCSEA does not take issue with BC Hydro’s summary list of matters regarding which

BCUC is required to allow BC Hydro to recover its costs.13

24. BCSEA takes no position as to whether the BCUC has authority to identify the costs

of legislated policies where the BCUC cannot direct associated changes.14 However,

BCSEA doubts that there would be adequate evidence to do so in the current

proceeding.

PART THREE: PROVIDING SAFE, RELIABLE AND COST EFFECTIVE SERVICE, COMPLEX ENVIRONMENT

A. CONTAINING CONTROLLABLE COSTS

25. The evidence demonstrates that BC Hydro has made concerted efforts to contain

controllable costs in the Test Period, and that BC Hydro’s budgeting process is

rigorous.15

9 Section 44.1(2) of the UCA requires a public utility to file a long-term resource plan with the

Commission. Newly added section 44.1(2.1) states “The authority need not file a long-term resource plan before February 28, 2021.” 10

BC Reg. 240/2007, under the BC Hydro Public Power Legacy and Heritage Contract Act, SBC 2003, c.86. 11

Exhibit B-6, BCSEA 1.4.1, pdf p.629. 12

Exhibit B-12, BCUC 2.201.3, pdf p.10. 13

BC Hydro Final Argument, para.6. 14


BC Hydro Final Argument, para.8.


B. DEMANDS ON BC HYDRO

26. BCSEA concurs that the demands on BC Hydro are increasing as its service

environment becomes more complex.

27. BCSEA agrees that increased costs are being driven by more-stringent regulatory

requirements in areas such as reliability, cyber security, safety, archaeological,

groundwater and non-fish bearing streams, species at risk, and invasive species.16

BCSEA considers that these are important societal objectives and supports BC

Hydro meeting its corporate responsibilities in this regard.

28. BCSEA also agrees with the high-level observation by BC Hydro President and CEO

Chris O’Riley regarding increasing customer service and societal expectations:

“I think societal expectations on institutions are increasing across the board, and correspondingly societal risk tolerance is decreasing. And this in itself becomes a cost pressure for a critical infrastructure provider such as BC Hydro.”17

29. BCSEA highlights that BC Hydro now has a crucial role in achieving low-carbon

electrification in support of the Province’s CleanBC Plan to meet BC’s GHG

reduction targets, and affordability, economic development and Reconciliation

objectives. The CleanBC plan is the Province’s strategy to reach its 2030 climate

targets, through the use of clean and renewable energy in transportation, buildings

and industry in order to reduce greenhouse gas emissions and build British

Columbia’s economy.18

30. The Phase 1 Final Report of the Comprehensive Review of BC Hydro refers to “BC

Hydro’s role in implementing electrification initiatives critical to the CleanBC plan.”19

BC Hydro’s 2019/20 2021/22 Service Plan states that BC Hydro aligns with the

Government’s “strong, sustainable economy” priority by “[s]upporting the

implementation of the CleanBC plan to increase British Columbians’ use of cleaner

energy in key sectors of the economy and shift away from reliance on fossil fuels for

transportation, industry, and housing.”20 The Service Plan states:

“We are focused on delivering our renewed customer service strategy, with the goal of making it easier to do business with us and helping our

16


BC Hydro Final Argument, para.14, citing Tr. 5, p. 359, l. 9 to p. 360, l. 5 (O’Riley). 18

Exhibit B-1, Appendix C, Comprehensive Review of BC Hydro – Phase 1 Final Report, p.44, pdf p.1284. 19

Exhibit B-1, Appendix C, p.1, pdf p.1241. 20

Exhibit B-1, Appendix E, p.12, pdf p.1352.


customers make smart energy choices through our conservation and energy management programs, including encouraging our customers to use our clean and reliable electricity to power their homes, vehicles and businesses. We will support and align with the Province’s new CleanBC plan, which outlines significant greenhouse gas (GHG) reduction measures, by powering British Columbia’s economic growth with clean and renewable electricity”21

C. ADDITIONAL INVESTMENT AFTER THE TEST PERIOD

31. BCSEA agrees with Mr. O’Riley’s observation during his oral testimony that in the

context of new and rising expectations BC Hydro’s operating budgets will need to

increase in subsequent test periods.22

PART FOUR: LOAD AND REVENUE FORECASTS

A. INTRODUCTION

32. BCSEA agrees with BC Hydro that the actual sales for the first two months of F2020

and the October 2018 Load Forecast for the remainder of the F2020-F2021 Test

Period are a reasonable basis for setting rates for the Test Period.23

33. In BCSEA’s view, the October 2018 Load Forecast was reasonable at the time it was

made. And, it was not materially contradicted by actual experience up to the closing

of the evidentiary record in the proceeding on March 4, 2020.

34. BCSEA notes that the October 2018 Load Forecast includes only a limited amount of

low-carbon electrification implemented prior to the CleanBC Plan and it does not

include incremental load associated with BC Hydro implementing the CleanBC

Plan.24

35. BCSEA agrees with BC Hydro that the Panel can and should take judicial notice of

the COVID-19 pandemic that has erupted subsequent to the closing of the

evidentiary record.25 That said, as discussed further in Part Twelve, below, BCSEA’s

view is that the rates for the Test Period should be based on the evidentiary record,

and the evidentiary record should not be reopened.

21

Exhibit B-1, Appendix E, p.13, pdf p.1353. 22

BC Hydro Final Argument, para.15 citing Tr. 5, p. 372, l. 19 to p. 373, l. 9 (O’Riley). 23


Exhibit B-6, BCSEA 1.9.1, pdf p.651; Transcript Vol.8B, p.1362, lines 7-16 (Rich). 25



B. SNAPSHOT OF THE OCTOBER 2018 LOAD FORECAST UNDERLYING THE EVIDENTIARY UPDATE

36. The October 2018 Load Forecast for domestic electricity sales after rates and DSM

savings for F2021 is 53,253 GWh in the Mid-Load Forecast and 51,364 GWh in the

Low-Load Forecast. For context, the F2021 Low-Load figure is less than the Actual

(temperature normalized) figure for F2014.26

C. LOAD FORECAST METHODOLOGY

37. BCSEA does not disagree with BC Hydro’s evidence that “The initial years of each

forecast vintage, which are of greatest relevance when setting rates for a single test

period, tended to be reasonably accurate.”27

D. TEST PERIOD LOAD FORECAST

38. BCSEA agrees that “Since the May 2016 Load Forecast, BC Hydro made

improvements to its load forecast methodology and governance based on feedback

from the BCUC and internal audit recommendations.”28

39. Regarding forecasting EV load, BC Hydro says its EV load forecasting model was

reviewed in the third party audit of the 2017 Load Forecast and no recommendations

for changes were made. BCSEA is satisfied with BC Hydro’s statement that “As part

of development efforts for future load forecasts, we intend to place more focus on our

EV modelling, given the emphasis that the CleanBC plan places on the electrification

of transportation.”29

E. THE CONFIDENCE INTERVAL AROUND THE MID FORECAST

40. BCSEA accepts BC Hydro’s argument that “The confidence interval, represented by

the high / low forecasts, is a critical part of the context when defining the

reasonableness of using the October 2018 Load Forecast for setting Test Period

rates.”30 Further, BCSEA accepts that “it is inevitable that actual results will vary from

forecasts.”31 And BCSEA accepts that the Monte Carlo analysis that informs the

26

Exhibit B-1, Appendix O, October 2018 Load Forecast, pdf p.1796 27

BC Hydro Final Argument, para.23, citing Tr. 10, p. 1633, ll. 20-25 (Rich). 28




BC Hydro Final Argument, para.44, citing Tr. 10, p. 1633, ll. 6-10 (Rich).


High- and Low-Forecasts takes into account historical occurrences of economic

downturns.32 These factors reinforce the conclusion that the October 2018 Load

Forecast is the appropriate basis for setting rates in the Test Period, even though the

actual results for F2021 may turn out in hindsight to vary from the forecast.

F. THE JUNE 2019 20-YEAR LOAD FORECAST UPDATE IMPACTS THE YEARS AFTER THE TEST PERIOD

41. BCSEA agrees with BC Hydro that it was reasonable that the June 2019 Load

Forecast did not propose adjustments to the Evidentiary Update revenue forecast.

The difference was minute. Variances between actual and forecast during the Test

Period will result in a refund to, or recovery from, ratepayers. And, BCSEA agrees

that “It is impractical to continually update forecasts and expect to bring the

regulatory process to a timely resolution.”33

G. THE OCTOBER 2018 LOAD FORECAST, ASSUMED FORESTRY SUB-SECTOR DECLINE

42. BCSEA is satisfied that the October 2018 Load Forecast is the appropriate basis for

setting rates in the Test Period. In BCSEA’s view, the evidence as of October 2019

that actual load in the forestry sub-sector is below the forecast is not a sufficient

reason to reject or to modify the October 2018 Load Forecast for the purpose of

setting rates in the Test Period. Year-to-date F2020 sales as of December 31, 2019

were only 2.6% below the October 2018 Forecast.34 In BCSEA’s view, this variance

is not large enough to warrant reopening the October 2018 Forecast for the purpose

of setting rates in the Test Period.

H. THE LOAD FORECAST AND THE PORTION OF THE CLEANBC “UPSIDE” POTENTIAL THAT CAN BE ASSESSED AT THIS TIME

(a) The June 2019 Load Forecast Reflects Some, but Not All, of the CleanBC Initiatives

43. BCSEA supports use of the October 2018 Load Forecast as the basis for setting

rates in the Test Period, despite the potential load growth from electrification in the

32



BC Hydro Final Argument, para.56, citing Exhibit B-41, BC Hydro Undertaking No. 15.


Test Period that is not yet reflected in the Evidentiary Update.35 BC Hydro’s next

revenue requirement application (expected in February 202136) will provide an

effective opportunity for new information to be considered.

(b) BC Hydro Continues to Work to Build Load and Remove Barriers to Electrification

44. BCSEA wishes to make an additional point on the treatment of low-carbon

electrification in the Application.

45. To be clear, BCSEA agrees with BC Hydro’s witness Mr. John Rich, Senior

Manager, Load Forecasting, that “there is a difference between a load forecast and a

sales target.”37 The load forecasting function is intended to be unbiased and data

driven.38 BCSEA does not object to BC Hydro’s load forecasting approach to the

potential upside of the CleanBC Plan (in the present case.)

46. However, the problem, in BCSEA’s view, is that BC Hydro’s low-carbon electrification

budget for F2020-F2022 is not sufficient and it is not linked to a long-term

comprehensive plan (which would include “sales targets”) for achieving the

electrification required under the CleanBC Plan.

47. BCSEA submits that BC Hydro is literally correct when it argues that “[t]here is ample

evidence on the record of BC Hydro’s ongoing work to build load to reduce

greenhouse gas emissions.”39 However, BCSEA submits that the evidence shows

that BC Hydro’s ongoing work to build load to reduce GHG emissions in the Test

Period is not yet sufficiently robust to meet the low-carbon electrification expectations

of the CleanBC Plan.

I. REGULATORY ACCOUNTS TRUE-UP VARIANCES FROM THE LOAD FORECAST

48. As BC Hydro states, “variances between actual and forecast Cost of Energy arising

from differences between forecast and actual domestic customer load are deferred to

the Non-Heritage Deferral Account.” BCSEA agrees that “[a] regulatory variance

35

BC Hydro Final Argument, para.55, citing Tr. 8B, p. 1295, ll. 1-11 (Clendinning). 36

Transcript Vol.5, p.425, lines 6-13 (Mr. O’Riley). 37

BC Hydro Final Argument, para.59, citing Tr. 10, p. 1682, l. 25 to p. 1683, l. 10 (Rich). 38

BC Hydro Final Argument, para.57, citing Tr. 10, p. 1682, l. 25 to p. 1683, l. 10 (Rich). 39



account is a fair and efficient means of addressing emerging conditions during the

regulatory process (and after it).”40

49. Similarly, BCSEA agrees with BC Hydro that the NHDA will “permit the fair and

efficient management of load variances associated with the ongoing COVID-19

pandemic that has emerged in the weeks after the closure of the evidentiary

record.”41

J. REVENUE FORECAST, INDUSTRY STANDARD, PAST PRACTICE

50. The Revenue Forecast is a straightforward calculation, based on the pertinent load

forecast and the existing rate schedules.42

K. CONCLUSION AND REQUESTED FINDINGS

51. BCSEA concurs with BC Hydro that the Load Forecast and Revenue Forecast for the

Test Period reflected in the Evidentiary Update are reasonable.43

PART FIVE: FORECAST COST OF ENERGY

A. INTRODUCTION

52. BCSEA agrees that “BC Hydro’s forecast Cost of Energy, as updated in the

Evidentiary Update, is reasonable for the purpose of setting rates in the Test

Period.”44

53. BCSEA notes that, as part of this Application, BC Hydro is not proposing any

generation projects or seeking acceptance of any electricity purchase agreement.45

B. FORECAST INCREASE IN THE COST OF ENERGY DRIVEN BY EXISTING EPAs, FOR WHICH COST RECOVERY IS DIRECTED

(a) The Vast Majority of Total IPP Purchase Cost Increases Are Related to Existing EPAs

54. The evidence46 supports BC Hydro’s position that:

40








“The forecast increase in Cost of Energy in the Application is primarily driven by an increase in costs related to IPPs and Long-Term Commitments. The vast majority of those costs are associated with existing EPAs, the terms of which are fixed and for which cost recovery is mandated [i.e., legally required].”47

(b) A Small Portion of the Total IPP Purchase Cost Relates to EPA Renewals, which Includes Directed Biomass Purchases, and New EPAs

55. BCSEA is concerned that as of September 30, 2019, BC Hydro executed a new

long-term Electricity Purchase Agreement with Atlantic Power for its NorthWest

Energy facility in Williams Lake BC that contemplates burning retired rail ties

contaminated with creosote and pentachlorophenol as a portion of its fuel.48 When

asked if the EPA would require power to be exclusively from clean or renewable

resources, i.e., precluding the use of retired rail ties as fuel, BC Hydro stated, “[t]he

NW Energy EPA does not preclude delivery of power from retired railway ties.”49

56. BCSEA strongly opposes BC Hydro’s decision to acquire new generation under the

NW Energy EPA that is not exclusively from clean or renewable resources.

57. BCSEA acknowledges that the BCUC is prevented from denying recovery of the

costs of the NW Energy EPA by the Direction to the BCUC respecting the Biomass

Energy Program dated April 1, 2019 (Order in Council No. 158, BC Reg. 71/2019).”50

C. BC HYDRO, STEPS TO MITIGATE IPP ENERGY COSTS

58. In BCSEA’s view, the evidence supports BC Hydro’s position that it “is managing

energy costs from IPPs to the extent possible within the parameters of its contractual

obligations under EPAs.”51

D. FORECAST COST OF ENERGY, HOW BC HYDRO OPERATES THE SYSTEM

59. BC Hydro provides a useful summary of the distinction between planning and

operating, the forecast Cost of Energy for the Test Period, the Energy Studies, and

the objective of BC Hydro’s operation of the system.52

46

Cited in BC Hydro Final Argument, paras.73-75. 47


Ibid. 49


Exhibit B-17, BCSEA 3.82.1, pdf p.379; BC Hydro Final Argument, para.77, second bulleted paragraph. 51



60. BCSEA supports both the theory and the practice of how BC Hydro operates the

system within the operational timeframe.

(a) BC Hydro’s Operating Horizon Objective, the Best Interests of Ratepayers

61. BCSEA agrees that BC Hydro’s stated objective of operation of the system –

“meeting load first while maximizing value within a range of outcomes” – is in the

best interests of ratepayers. BC Hydro summarizes the objective as follows:

“In the operational (i.e., up to three years) time horizon, BC Hydro operates the system to meet load first and then makes decisions to dispatch resources and to undertake Electricity Purchases or Surplus Sales to maximize the expected value of its energy supply portfolio within a range of outcomes.”53

62. BCSEA accepts BC Hydro’s explanation that “Electricity Purchases or Surplus Sales

are undertaken to both cost-effectively meet load requirements and to take

advantage of trade opportunities.”54 As BC Hydro explains:

“Surplus Sales (also referred to as domestic sales) are sales to Powerex that occur because BC Hydro has a surplus. Market Electricity Purchases are purchases from Powerex to cost-effectively meet load. Net Purchases (Sales) from Powerex are transactions with Powerex to generate Trade Income. Powerex also generates Trade Income from a wide range of activities that are not connected to BC Hydro’s system. Ratepayers receive the full benefit of Trade Income generated by Powerex’s activities and bear no downside risk under BC Hydro’s definition of Trade Income, which has the effect of assigning any net loss in Trade Income to the Government of B.C.”55

63. BCSEA accepts that “While Powerex is able to use the residual capability of the BC

Hydro system to generate Trade Income, BC Hydro makes all of the decisions

related to system operations and has the ability to put constraints on Powerex’s

activities.”56

64. Similarly, BCSEA accepts that “meeting domestic load and maximizing the expected

value for ratepayers [are] complementary, rather than conflicting, objectives.”57 The

52

BC Hydro Final Argument, paras.82-83. 53



BC Hydro Final Argument, para.86, footnotes omitted. 56




uncertainty and risk around domestic requirements requires an assessment of

probabilities, which is done as part of the Energy Studies.58 As BC Hydro states:

“BC Hydro’s approach recognizes that actual conditions will be different than expected conditions. While decisions are made to maximize value, BC Hydro manages those decisions to maintain its ability to respond to a range of probable future conditions.”59

(b) In 2018, BC Hydro Managed Through Significant Events While Maximizing Value for Ratepayers

65. BCSEA is familiar with the evidence regarding the unusual events and BC Hydro’s

operational activities between the summer of 2018 and the spring of 2019. Briefly, in

the summer of 2018 BC Hydro sold power, based on high market prices and a

forecast surplus at the time. System storage then became depleted due to: low

inflows to the Williston Reservoir in the Fall of 2019; the October 2019 Enbridge

natural gas pipeline explosion, which boosted electricity demand; unusually cold

temperatures in February 2019, which increased heating load; and dry conditions in

the spring of 2019, which reduced inflows to BC Hydro reservoirs and receipts of

power from run-of-river and wind IPPs. BC Hydro responded by entering the

“Powerex Letter Agreement” under which BC Hydro secured imports and reduced its

risk. In the end, BC Hydro’s operational decisions “saved money for the

ratepayers.”60

66. During the oral hearing, questions were put to BC Hydro’s witnesses regarding these

events. Ms. Heather Matthews, Director of the Generation System Operations Key

Business Unit at BC Hydro, took the lead role in responding on this topic. She

testified, in conclusion, that “certainly I stand by that those sales that we made in the

summer [of 2018] were the correct things to do and I’d do them again.”61

“THE CHAIRPERSON: So with hindsight you would go back and do exactly the same thing anyway?

MS. MATTHEWS: [Answer] Yes.”62

58



Transcript, Vol.9, p.1470, lines 17-19, (Ms. Matthews). 61

Transcript, Vol.9, p.1485, lines 22-24, (Ms. Matthews). 62

Transcript, Vol.9, p.1485, line 25 to p.1486, line 1, (Ms. Matthews).


67. BCSEA considers Ms. Matthews to be a highly qualified witness who displayed an

impressive knowledge of the events in question. BCSEA submits that her evidence

on this point is persuasive and should be accepted by the Panel.

(c) Energy Study Methodology

68. BCSEA agrees with BC Hydro’s argument that the Energy Study methodology

produces a sound price signal that enables BC Hydro to achieve its operating

objective to meet load first while maximizing value within a range of outcomes.

69. Attributes of the Energy Study methodology include the following:

“The Energy Study models account for the trade-offs (risk/reward) between selling now and selling later, or buying now and buying later.”63

“A key output of the Energy Studies is a forecast of the marginal value of water in BC Hydro’s two largest reservoirs (Williston and Kinbasket).”64

“The Energy Studies account for a wide range of potential occurrences. The use of weather year ensembles ensures that the variability in inflows, prices, loads, and resources due to the impacts of weather are well represented in the models.”65

“BC Hydro updates the Energy Studies monthly with new input data pertaining to import/export transmission limits and market prices. BC Hydro also incorporates the most recent actual load data, augmented by the latest approved load forecast.”66

70. In BCSEA’s view, the Energy Study methodology has been explained persuasively in

the Application, the responses to Information Requests, oral testimony by BC Hydro

witnesses, and BC Hydro’s Final Argument.67 BC Hydro’s monthly Energy Studies

process received a favourable review by SINTEF and BC Hydro’s Internal Audit

group.68

(d) The Lower Cost of Energy Forecast in the Evidentiary Update

71. The forecast Cost of Energy in the October 2019 Evidentiary Update69 was materially

lower than the forecast in the Application.70 BC Hydro explains that “[t]his reflects [a]

63




BC Hydro Final Argument, para.107, footnote omitted. 67


Exhibit B-1, p.4-14, pdf p.240. 69

Exhibit B-19.


shift from run-of-river IPP power to lower cost market purchases due to low water

conditions.”71

E. BC HYDRO, HERITAGE ASSETS

72. BC Hydro argues that its management of the Heritage Assets provides optimal value

to BC Hydro customers, in both the operating and planning time horizons.72

(a) Operating Horizon

73. BCSEA agrees that, in the operating horizon, BC Hydro’s approach of “operating the

system in an integrated manner is better for ratepayers than prioritizing operating

specific Heritage Assets.” BCSEA accepts that “prioritizing operating specific

heritage assets over existing EPAs would be detrimental to ratepayers.”73 As BC

Hydro argues:

“While Heritage Assets are generally lower cost than IPP purchases, in the operating horizon the resource stack available to BC Hydro is essentially fixed. EPAs with IPPs are take-or-pay. BC Hydro’s monthly Energy Studies optimize the operational management of all sources of energy supply on BC Hydro’s integrated system. Over the operating horizon, BC Hydro operates the system to meet its objective of meeting load and otherwise maximizing net revenue for the benefit of its ratepayers. The price signals that come out of the Energy Studies are used to determine which basins to run, and in what order, or whether BC Hydro is willing to either import or export. This approach means that over the operating horizon, BC Hydro will obtain energy in the most economic manner possible, rather than prioritizing lower cost sources of energy.”74

(b) Planning Horizon

74. In the planning horizon, BC Hydro argues that its capital planning maximizes the

long-term benefits from the Heritage Assets. BCSEA agrees with BC Hydro’s high-

level summary as follows:

“BC Hydro is in a multi-decade period of significant renewal of its Heritage Assets. Investments are prioritized and staged to maintain overall system reliability and spread capital costs to avoid sudden rate impacts. For facilities that are not a significant contributor to overall system reliability, investments to restore generation have been deferred until such time that

70


BC Hydro Final Argument, sub-heading (d) on p.53. 72





there is a system need for energy and capacity; and they are of a high enough priority to be included within BC Hydro’s 10 year Capital Plan.”75

75. While BCSEA agrees that BC Hydro’s capital planning maximizes the long-term

benefits from the Heritage Assets, BCSEA believes that BC Hydro should plan much

more low-carbon electrification in order to maximize the long-term benefits from the

Heritage Assets and contribute to meeting B.C.’s legislated GHG reduction targets.

F. VARIANCE ACCOUNTS, CUSTOMERS PAY ACTUAL COST OF ENERGY

76. Variances between planned and actual costs of energy are deferred to the Heritage

Deferral Account or the Non-Heritage Deferral Account. The NHDA also captures the

Domestic Revenue Variance between planned and actual domestic customer load.

BCSEA agrees with BC Hydro’s statement that, “In the end, although BC Hydro’s

revenue requirements are based on a forecast Cost of Energy, customers only pay

the actual costs.”76

G. CONCLUSION AND REQUESTED FINDINGS

77. BCSEA supports BC Hydro’s request that the BCUC find that BC Hydro’s forecast

Cost of Energy for the Test Period is reasonable, being based on a sound

methodology and appropriate assumptions.

PART SIX: OPERATING COSTS

A. INTRODUCTION

78. This Part addresses planned operating costs for F2020-F2021.

B. OPERATING COSTS SNAPSHOT: COST PRESSURES WITH OFFSETTING TEST PERIOD SAVINGS

79. In paragraph 121 of its Final Argument, BC Hydro reproduces a table showing Total

Base Operating Costs (Fiscal 2019 – Fiscal 2021). For context, the table includes

columns showing figures prior to the Evidentiary Update and the variance. In order to

simplify the presentation and to focus on the numbers that are currently at issue,

BCSEA provides the following version showing only the figures for F2019 Actual,

F2020 Update, and F2021 Update.

75




Total Base Operating Costs (Fiscal 2019 – Fiscal 2021 ($ millions)77

Operating Cost by Business Group F2019 Actual

F2020 Update

F2021 Update

Integrated Planning 285.9 290.8 293.0

Capital Infrastructure Project Delivery 85.9 80.1 81.1

Operations 215.6 237.3 240.1

Safety 53.6 56.8 57.5

Finance, Technology, Supply Chain 261.2 262.6 264.8

People, Customer, Corporate Affairs 105.5 110.6 111.9

Other78 (250.5) (244.3) (244.4)

Total Base Operating Costs 757.2 793.8 803.9

80. It can be observed that for F2020, the first of the two test years, Total Base

Operating Costs is approximately 5% above the preceding year (F2019). And for

F2021, the second test year, Total Base Operating Costs is approximately 1% above

the first test year.

C. BCUC’S RECOMMENDATIONS AND COMMENTS ON OPERATING COSTS

81. In its Decision on the Previous Application,79 the Commission made

recommendations and comments regarding BC Hydro’s Operating Costs. BCSEA

concludes that BC Hydro has responded adequately to these points in its evidence

and Final Argument.

82. In the current Application, BC Hydro provided:

a. additional information on each of BC Hydro’s Key Business Units (KBUs) and

their Departments,

b. details of BC Hydro’s budgeting process,

c. details of BC Hydro’s cost containment initiatives, and

d. additional benchmarking regarding operating costs.

83. BC Hydro also responded to questions regarding:

a. Total Rewards program, and employee retention,

77

Source: Exhibit B-11-2, Evidentiary Update, Appendix A, Schedule 5, Lines 1 to 9. Cited in BC Hydro Final Argument, para.121. 78

“Other” Operating Costs by Business Group is negative due to Capitalized Costs being removed from Operating Costs. Exhibit B-11-2, Evidentiary Update, Appendix A, Schedule 5.7, Line 5. 79

Decision and Order G-47-18, dated March 1, 2018. At: https://www.ordersdecisions.bcuc.com/bcuc/decisions/en/306836/1/document.do.

https://www.ordersdecisions.bcuc.com/bcuc/decisions/en/306836/1/document.do


b. Workforce Optimization Program, replacing contractors with employees,

c. Work Smart Program,

d. Full Time Equivalent (FTE) levels, and

e. Zero-based budgeting.

84. These topics are addressed in the paragraphs that follow.

D. BC HYDRO BUDGETING, GOVERNANCE PROCESSES, COST CONTAINMENT EFFORTS

85. BC Hydro’s operating costs budgeting process involves both bottom-up and top-

down elements.

86. BCSEA agrees that the bottom-up component went into depth and was not merely

incremental adjustments to previous spending.

87. In BCSEA’s view, the top-down component, which BC Hydro says “ultimately

dictated the budget amounts during the Test Period,”80 did result in lower budgeted

Operating Costs than would have resulted from a zero-based budgeting approach.

88. BCSEA believes the evidence establishes that BC Hydro has appropriate oversight

processes in place so that it operates within its budgets and targets, including a

vacancy management process, performance metrics and regular internal reporting.81

E. CONTROLLABLE COST PRESSURES WITHIN EXISTING BUDGETS, INCREASES AND UNCONTROLLABLE COSTS

89. BC Hydro’s budgeting for Operating Costs (and Capital Expenditures) in the Test

Period occurred in conjunction with BC Hydro’s participation in the BC Government’s

Phase One Comprehensive Review of BC Hydro.82

90. The evidence supports BC Hydro’s contention83 that its Executive Team determined

that all cost pressures would be managed within the F2019 forecast operating cost

budget, with the exception of (a) storm restoration costs, (b) the Employer Health

Tax and rising benefits costs, and (c) wage increases. A fourth exception was added

in the Evidentiary Update: (d) updated pension discount rate. BC Hydro describes

80



Exhibit B-1, p.1-8, pdf p.69. 83



these exceptions as “uncontrollable” operating costs pressures. In other words, the

determination was that for all “controllable” operating costs, upward pressure would

be balanced by found savings and efficiencies.

91. BCSEA accepts that the budgets for the four types of “uncontrollable” operating

costs in the Test Period are reasonable. Details are provided in the paragraphs that

follow.

92. The increase in the budget for storm restoration costs in the Test Period results from

application of the previously-approved methodology that uses a five-year average of

actual storm restoration costs for the five most recent normal weather years.

Customers pay for only the actual, not budgeted, storm restoration costs due to the

Storm Restoration Costs Regulatory Account.

93. The (new) Employer Health Tax increases BC Hydro’s Standard Labour Rates in the

Test Period.

94. The budgeted salary increases of 2% per year for unionized employees and 2.5%

per year for management and professional salaries are reasonable. For practical

purposes, compensation for the unionized employees is determined by provincial

guidelines. For the management and professional compensation, it is noted that

annual management and professional percentage increases from F2012 to F2019

averaged only 1%.84 BCSEA accepts that the compensation increases contemplated

by the Test Period budget are needed to keep pace with the market after some years

of restraint and thereby to retain and attract high quality employees.85 Similarly,

BCSEA does not object to the incentive pay component of BC Hydro’s total rewards

program.86

95. The updated (decreased) pension discount rate increases BC Hydro’s pension costs

in the Test Period. BCSEA accepts that the timing and size of the change were

routine.87

84




BC Hydro Final Argument, paras.161-162.


F. MEANS TO CONTROL COSTS AND ABSORB NEW UNCONTROLLABLE OPERATING COST PRESSURES

96. BC Hydro lists the following examples of measures to reduce Operating Costs in the

Test Period:

a. Workforce Optimization Program (replacing contractors with internal FTEs),

b. Accenture Repatriation,

c. Vacancy Factor,

d. elimination of the Unallocated Funds Budget,

e. elimination of a Property Lease,

f. reduced the Communications Budget,

g. expansion of Paperless Billing,

h. Work Smart Program, and

i. “Making it Easier to Get Work Done” Initiative.88

97. Regarding the Workforce Optimization Program, BCSEA agrees that BC Hydro has

given adequate consideration to the longer term costs of replacing contractors with

employees.89

98. Regarding elimination of the unallocated funds budget in the Test Period, BC Hydro

acknowledged that this “will, necessarily, have an impact on BC Hydro’s ability to

manage unanticipated costs pressures during the test period.90

99. Regarding the Work Smart Program, BCSEA accepts BC Hydro’s argument that the

objective of the Program is to increase employees’ work output (measured in

capacity hours), not to reduce employment levels. As BC Hydro says, “In the

absence of Work Smart BC Hydro would expect its operating costs to be driven

higher as a direct result of increased regulatory and compliance requirements.”91

88



Exhibit B-6, Response to BCSEA 1.26.1, pdf p.700. 91



G. FTE NUMBERS, WORK ON SITE C, AND INSOURCING

100. BCSEA agrees that it is in the best interest of customers for BC Hydro to

continue managing the business with a focus on total cost, rather than the number of

FTEs per se.92

101. Regarding its number of FTEs over time, BC Hydro summarizes, correctly in

BCSEA’s view, that “apart from growth in the workforce directly related to increased

capital investment and the Accenture repatriation, BC Hydro’s FTEs have remained

relatively flat since fiscal 2012 and are forecast to remain flat over the Test Period.”93

102. The Site C Project is the only area driving net new FTEs. These costs are

capitalized and therefore do not affect the F2020-F2021 Revenue Requirement.

BCSEA notes, though, that BC Hydro’s customers will begin paying for the costs of

Site C when the Project comes into service.

103. BC Hydro argues that it uses overtime where it is cost-effective to do so, and has

reduced the amount of planned overtime for the Test Period.94 In BCSEA’s view, BC

Hydro has appropriate structures in place to manage overtime effectively.

H. OPTIMIZING POWER SYSTEM MAINTENANCE

104. The Operating Costs budget includes the costs of power system maintenance. In

the bigger picture, maintenance costs together with capital investments are within BC

Hydro’s asset management strategy.

105. BC Hydro says increases in power system maintenance costs in the Test Period

will be “mitigated,” but that it expects budgets will need to increase after this Test

Period.95

106. In BCSEA’s view, BC Hydro has provided extensive evidence regarding its

management of power system maintenance actions and costs in the context of risk

management and sustainment capital investments. BC Hydro’s asset management

practices have been reviewed favourably, for example by Navigant and the Auditor

General of BC.96 BC Hydro’s operations and maintenance costs compare favourably

for both transmission and distribution in utility industry benchmarking by First

92







Quartile.97 For generation station maintenance, benchmarking by Navigant indicates

that BC Hydro’s costs are relatively low.98

107. While maintenance budgets are higher in the Test Period than in F2019, BC

Hydro says this is due largely to a combination of (a) storm restoration budget

(Distribution Emergency Response) increases under the five-year average

methodology, (b) funds spent on maintenance being transferred from “unallocated” to

“maintenance,” and (c) increases in the Standard Labour Rate.99 BCSEA accepts

this explanation.

108. Vegetation management spending in F2015 to F2019 and budgeted in F2020 to

F2021 is almost flat. BC Hydro says this will be adequate. In his opening statement

to the Commission Panel, Mr. O’Riley highlighted vegetation management as one of

three areas in which to expect operating cost increases beyond inflation in future

revenue requirements processes.100 He pointed to increasing concern in the electric

utility industry about forest fires, referring to damage to electric utility assets, as well

as to potential liability to third parties for fires started by power systems. He also

indicated that mandatory reliability standards address vegetation and that this will

drive up BC Hydro’s management, quality control, and quality assurance and actual

spending on vegetation.101

I. BRATTLE REPORT AND INDICATIVE COMPARISON, BC HYDRO’S OPERATING COSTS

109. In addition to the benchmarking by First Quartile and Navigant,102 BC Hydro

provided in evidence a 2019 report by Brattle Group benchmarking BC Hydro’s

operating costs against those of its peer U.S. utilities.103 The Brattle Report examined

“non-fuel operations and maintenance expenses,” i.e., excluding water rentals and

fuel which are included within BC Hydro’s Energy Costs. The Brattle Report

addresses total operating costs, and operating costs by function and sub-function.

97




Exhibit B-30, p.4. 101

Transcript Vol.5, p.504 line 17 to p.507 line 4. 102

Discussed in para.106, in the text above. 103

Exhibit B-1, Appendix T.


The Brattle Report concludes that BC Hydro’s operating costs compare favourably

with those of its peers, on all of the metrics.104

110. As the Brattle Report benchmarked against U.S. utilities, BC Hydro also provided

its own high-level comparison of BC Hydro’s operating costs with those of Manitoba

Hydro, FortisBC, and Hydro-Québec. Acknowledging methodological limitations, the

internal review put BC Hydro’s operating costs “in line with those of other Canadian

utilities on both a per MWh and a per customer basis.”105

111. The Application requests that the BCUC rescind the requirement that BC Hydro’s

revenue requirements applications contain financial information that follows the

Commission’s Uniform System of Accounts (USoA).106 BC Hydro says this would

give it discretion to determine whether and how often to prepare these schedules107

(as a supplement to and based on BC Hydro’s existing system of accounts). BC

Hydro says preparing the BCUC USoA financial schedules is labour intensive

(something less than half an FTE per year108). BC Hydro says that “having the

discretion to prioritize these pressures against other requirements is an important

part of our ongoing efforts to limit overall base operating cost increases.”109

112. The topic of rescinding the mandatory production of BCUC USoA schedules

comes up in the context of benchmarking because the Brattle Report relies on the

FERC Uniform System of Accounts, which is different than both the BCUC USoA

and BC Hydro’s existing system of accounts. If BC Hydro was to obtain future

benchmarking reports based on the FERC USoA, then one possibility would be for

BC Hydro to prepare supplementary financial schedules based on the FERC USoA

rather than on the BCUC USoA. However, it is not yet known if the Commission will

direct BC Hydro to provide future iterations of the Brattle Report. BC Hydro states in

conditional terms:

“...if the BCUC and interveners found the Brattle Report valuable, then reporting based on the FERC Uniform System of Accounts would likely provide greater value, going forward, compared to reporting based on the BCUC Uniform System of Accounts.”110

104

Exhibit B-1, p.5-51, pdf p.322. 105

Exhibit B-1, p.5-55, pdf p.326. 106

Exhibit B-1, p.1-33, pdf p.94; BC Hydro Final Argument, para.237. 107



BC Hydro Final Argument, para.237, citing Exhibit B-13, BCOAPO 2.123.1. 110



113. Despite having said that using the FERC USoA would be of greater value than

using the BCUC USoA if Brattle Reports are to be prepared in the future, BC Hydro

also notes that the costs of new spending opportunities (such as future Brattle

Reports) “add up and push against BC Hydro’s ability to keep rates affordable and

competitive.” BC Hydro’s position is that the value of presenting BC Hydro’s

accounts according to the FERC Uniform System of Accounts “is insufficient at the

present time to justify a directive that would remove the ability of management to

prioritize this work against other pressures, as appropriate.”111

114. BCSEA’s view is that a direction by the Commission requiring BC Hydro to

present financial schedules under the FERC USoA, or the BCUC USoA for that

matter, is not warranted. BC Hydro should itself determine what method to employ

considering costs and priorities. BCSEA takes no position on whether the

Commission should direct BC Hydro to provide benchmarking studies equivalent to

the Brattle Report in future revenue requirements applications.

J. CONCLUSION AND REQUESTED FINDINGS

115. BCSEA supports BC Hydro’s request112 that the Commission find that the

forecast operating expenses in the Test Period are reasonable.

PART SEVEN: CAPITAL EXPENDITURES AND ADDITIONS

A. INTRODUCTION

116. This Part addresses BC Hydro’s capital planning and delivery processes and its

forecast capital expenditures and additions in the Test Period.

B. BC HYDRO’S EVIDENCE SUPPORTING CAPITAL FORECASTS, AMOUNT, CAPITAL FILING GUIDELINES

117. BC Hydro has certainly filed a significant volume of evidence supporting its

capital forecasts for the Test Period.113

118. BCSEA accepts that the nature of the information filed is generally consistent

with BC Hydro’s 2018 Capital Filing Guidelines approved with revisions by the

Commission on December 2, 2019.114

111





C. CAPITAL PLANNING PROCESS

119. BCSEA agrees that BC Hydro has a robust capital planning process. As BC

Hydro summarizes:

“BC Hydro’s Test Period capital forecast is the product of an enterprise-wide capital planning process. It incorporates top-down limitations, and risk-based project prioritization to balance affordability, system performance and risk. BC Hydro has developed an ex-plan governance process to respond to evolving circumstances.”115

D. REDUCED CAPITAL FORECAST, AFFORDABILITY, SYSTEM PERFORMANCE AND RISK

120. BC Hydro’s Current Capital Plan for F2020 to F2021 (the Test Period) is $682

million or 22.3 percent below the Previous Capital Plan for F2020 to F2021.116

Deferral of projects accounts for $137 million of the reduction.117 These reductions

occurred in the context of BC Hydro’s participation in Phase 1 of the Comprehensive

Review of BC Hydro. BC Hydro says this “moderating of capital spending” will reduce

upward pressure on rates and will not materially impact system performance due to a

combination of strong system performance and slower demand growth.118 BC Hydro

says it will monitor asset condition and performance and will respond as needed.119

121. BCSEA agrees that additional reductions in capital spending would be

undesirable.120

E. DELIVERY OF CAPITAL PROJECTS, EFFICIENCY, EFFECTIVENESS

122. Regarding delivery of capital projects, BCSEA considers that the evidence

supports BC Hydro’s summary position that it “has implemented delivery processes

tailored to the size and complexity of projects, is engaged in continuous improvement

114

Decision and Order G-313-19, at https://www.bcuc.com/Documents/Proceedings/2019/DOC_56448_2019-12-02-BCH-Review-of-BCH-Capital-Expenditures-Decision.pdf. The approved version of BC Hydro’s 2018 Capital Filing Guidelines is at https://www.bchydro.com/content/dam/BCHydro/customer-portal/documents/corporate/regulatory-planning-documents/regulatory-filings/cap-exp/2020-01-17-cepr-compliance-g-313-19-d2.pdf. 115


Exhibit B-5, BCUC 1.108.1, cited in BC Hydro Final Argument, para.268. 117

Exhibit B-5, BCUC 1.108.1, cited in BC Hydro Final Argument, para.269. 118




https://www.bcuc.com/Documents/Proceedings/2019/DOC_56448_2019-12-02-BCH-Review-of-BCH-Capital-Expenditures-Decision.pdf

https://www.bcuc.com/Documents/Proceedings/2019/DOC_56448_2019-12-02-BCH-Review-of-BCH-Capital-Expenditures-Decision.pdf

https://www.bchydro.com/content/dam/BCHydro/customer-portal/documents/corporate/regulatory-planning-documents/regulatory-filings/cap-exp/2020-01-17-cepr-compliance-g-313-19-d2.pdf




of those processes, has rigorous financial approval processes in place, and has

been delivering its portfolio of projects on budget.”121

123. BCSEA generally agrees with BC Hydro’s points as follows:

a. BC Hydro’s planning and delivery functions work together to ensure

[reasonably] seamless transition and accountability;

b. BC Hydro’s delivery processes are tailored to the size and complexity of

projects;

c. BC Hydro is continuously improving its delivery processes;

d. BC Hydro has rigorous financial approval processes in place for all

investments;

e. BC Hydro evaluates power system projects upon completion;

f. BC Hydro has delivered its capital portfolio on budget; and

g. improvements in Technology processes have brought strong results

[compared to the industry generally].

F. BC HYDRO’S CAPITAL MANAGEMENT PROCESSES, ENDORSEMENTS BY THIRD PARTIES

124. BC Hydro’s capital planning and delivery processes have been reviewed

favourably by third parties such as the Office of the Auditor General.122

G. AMORTIZATION OF CAPITAL ADDITIONS REGULATORY ACCOUNT, CUSTOMERS ONLY PAY ACTUAL COSTS

125. BC Hydro states, “the Amortization of Capital Additions Regulatory Account

captures the differences between the forecast and actual amortization of capital

additions, with variances recovered over the next test period.” BCSEA agrees that

this means that customers will only pay for actual costs when actual capital

expenditures and additions vary from forecast due to factors such as changes in

project timing and scope changes.123

121





H. EXPENDITURES ON RIPRAP FOR W.A.C. BENNETT DAM

126. BC Hydro says its expenditure of $700,000 for the riprap stockpile for the W.A.C.

Bennett Dam was prudently incurred and should be recovered in rates.124 BCSEA is

not aware of any evidence contradicting BC Hydro’s justification of the expenditure.

I. VARIANCE OF DIRECTIVE 3, MINETTE TO LNG CANADA PROJECT

127. A brief background is as follows. BC Hydro’s Northwest Substation Upgrade

project was designed to serve LNG Canada’s load interconnection request.125 In

March 2018, Directive 3 of the Decision on the Previous Application126 required BC

Hydro to apply for a CPCN if it intended to proceed with the Northwest Substation

Upgrade project. In July 2018, the Government amended the Transmission Upgrade

Exemption Regulation127 under the UCA, to exempt BC Hydro from Part 3 of the

UCA regarding certain transmission upgrades. The Northwest Substation Upgrade

project has since been cancelled due to LNG Canada splitting its load

interconnection request into two phases. However, a new BC Hydro project called

the Minette to LNG Canada Interconnection Project facilitates the first phase of LNG

Canada’s interconnection and includes items that were part of the cancelled

Northwest Substation Upgrade project. BC Hydro says the Minette to LNG Canada

Interconnection Project is exempt under the Transmission Upgrade Exemption

Regulation. LNG Canada has not committed to the second phase of its project,

which would be supported by two potential BC Hydro projects: the Minette

Substation Upgrade project, and the Northwest Substations Outage Mitigation

project.128 BC Hydro says these two projects would also be exempt under the

Transmission Upgrade Exemption Regulation.129

128. BCSEA concurs with BC Hydro that the Minette Station to LNG Canada

Interconnection project meets section 2(1)(e) and section 2(2) of the Transmission

Upgrade Exemption Regulation and is therefore exempt from Part 3 of the UCA.130

129. In addition, BCSEA supports BC Hydro’s request131 that the Commission remove

Directive 3 requiring BC Hydro to file a CPCN application for the Northwest

124


LNG Canada is the proponent of an LNG export terminal in Kitimat, BC. 126

Decision and Order G-47-18, p.39, pdf p.46. 127

BC Reg. 140/2013. 128





Substation Upgrade project if BC Hydro intends to proceed with it.132 In BCSEA’s

view, rescinding Directive 3 ‘for greater certainty’ would have no substantive legal

effect. However, it would eliminate the potential for uncertainty.

J. SPECIFIC ISSUES RAISED

(a) PRES Project

130. BCSEA concurs with BC Hydro that the Peace Region Electricity Supply (PRES)

Project is a prescribed undertaking under section 4(2) of the Greenhouse Gas

Reduction (Clean Energy) Regulation133 (GGRR) and section 18 of the CEA.134

(b) Bear Mountain Terminal to Dawson Creek Transmission Voltage Conversion Project and North Montney Transmission Development Project

131. BCSEA concurs with BC Hydro that the potential Bear Mountain Terminal to

Dawson Creek Transmission Voltage Conversion Project and the North Montney

Transmission Development Project may also qualify as prescribed undertakings

under the GGRR and the CEA.135

132. BCSEA supports in principle the development of a mechanism for the BCUC to

assess the applicability of the GGRR in advance.136

(c) EV Charging Infrastructure

133. Regarding BC Hydro’s investments in electric vehicle charging infrastructure,

BCSEA concurs with BC Hydro as follows:

a. Capital additions regarding EV charging infrastructure, net of contributions

from Government or third parties, are included in rate base pursuant to

section 1 of Direction No. 8.137

b. The inclusion of capital additions regarding EV charging infrastructure in rate

base has no practical effect during the Test Period, during which BC Hydro’s

net income is prescribed to be $712 million for each of F2020 and F2021.

131


Decision and Order G-47-18. 133

BC Reg. 102/2012. 134




Direction No. 8 to the British Columbia Utilities Commission, BC Reg. 24/2019, at http://www.bclaws.ca/civix/document/id/complete/statreg/24_2019.

http://www.bclaws.ca/civix/document/id/complete/statreg/24_2019


c. The question of whether investments in EV charging stations should be

included in rate base in the future should not be considered in this

proceeding. It is not relevant to the Test Period. And, it is anticipated that the

BC Government will issue a legislative response to the Phase Two Final

Report of the Commission’s Inquiry into the Regulation of EV Charging

Services.

134. BCSEA urges the Government to move expeditiously to allow BC Hydro (and

FortisBC Inc.) to recover their net costs of EV fast-charging stations up to a

reasonable limit. On this topic, BCSEA also recommends that the Legislature add

“low-carbon transportation” to the BC energy objectives in the CEA.

(d) Cybersecurity

135. BCSEA is satisfied that BC Hydro puts an appropriately high priority on

cybersecurity. BC Hydro acknowledges that cybersecurity risk is a significant issue. It

has provided a substantial body of evidence regarding its cybersecurity management

structure, practices, investments, incident response plan, and third party reviews. BC

Hydro’s position is that it manages cybersecurity risk appropriately and will continue

to do so with the budgeted spending during the Test Period. BC Hydro says it is

likely that additional investment in cybersecurity will be required following the Test

Period given the increasing challenges. In BCSEA’s view, there is no evidence of

any deficiency in BC Hydro’s approach to cybersecurity in the Test Period or beyond.

(e) Projects in the same location

136. Questions were asked about whether BC Hydro could gain efficiencies by

combining projects that are in the same location. BCSEA is persuaded by BC

Hydro’s evidence that BC Hydro appropriately coordinates projects in the same

location to achieve efficiencies, and that it would be detrimental to combine individual

projects at the same location simply because they are at the same location. The

examples of projects at Mica138 and at the Bridge River system139 indicate that BC

Hydro’s approach is reasonable, and consistent with the Capital Filing Guidelines.

138




137. BC Hydro argues specifically that the “Bridge River 1 Replace Units 1-4

Generators / Governors Project”140 (Bridge 1 to 4 Project) should not be combined

with the Bridge River Transmission Project.141 BCSEA’s view is that the need for

each project is independent of the other. The Bridge 1 to 4 Project is aimed at

improved generation and water conveyance reliability at a single BC Hydro facility. It

would incidentally increase generation by 8 MW. The Bridge River Transmission

Project is aimed at resolving insufficient transmission capability for the Bridge River

system as a whole – to handle BC Hydro generation, 400 MW of IPP generation and

50 MW of expected IPP generation.

138. BC Hydro says it intends to file a section 44.2 capital expenditure schedule

application for the Bridge 1 to 4 Project, and to file a CPCN application for the Bridge

River Transmission Project if it is over $100 million.142 This is consistent with the

recently approved Capital Filing Guidelines. Granted, the Capital Filing Guidelines

“do not bind the BCUC in the exercise of its jurisdiction.”143

139. The Clean Energy Association of B.C. (CEABC), representing IPPs, has called

for a “conceptual cost estimate for refurbishing the entire Bridge River system.”144

CEABC’s counsel asked the BC Hydro witnesses, “How do you know that it’s a low

cost facility until you look at the numbers for refurbishing the entire system?”145 The

witnesses provided a lengthy explanation of BC Hydro’s planning and project

development practices as applied in the Bridge River system.146 BCSEA’s view is

that these practices are reasonable as described. In particular, it would not be

accurate to generalize that BC Hydro develops projects without any consideration of

other projects and the system in the area. BCSEA expects that specific investments

in the Bridge River area will come before the BCUC, whether in a capital expenditure

schedule, a CPCN application or a revenue requirement application, at which time

the Commission and the interveners will have an opportunity to scrutinize how a

specific investment fits within the broader context.

140

Exhibit B-1, Appendix J, Attachment 1, p.50 of 133, pdf p.1553. 141

Exhibit B-1, Appendix J, Attachment 1, p.75 of 133, pdf p.1578. 142


BC Hydro Capital Filing Guidelines, para.2. 144

Transcript Vol.11, p.1903, lines 5-11. 145

Transcript Vol.11, p.1909, lines 23-25. 146

Transcript Vol.11, pp.1902-1910.


(f) Strategic property purchases

140. In the current proceeding, BCSEA is not critical of BC Hydro’s strategic

purchases of property in Vancouver to support future substation projects in the West

End and in East Vancouver.147 The substation projects will be the subject of CPCN

applications in due course. The Commission’s proceedings regarding those CPCN

applications will provide an appropriate opportunity to examine the merits of the

property purchases. In BCSEA’s view, early acquisition of property is reasonable

given the scarcity of available properties meeting the highly specific locational

requirements of these particular projects. Notably, the properties are not amortized

for accounting purposes, and so there will be no amortization expense during the

Test Period.148

(g) Project write-offs

141. The Application proposes to change the status quo regarding project write-offs.

Previously, project write-offs were to the account of the shareholder. The Application

proposes budgets for project write-offs of $9.9 million and $9.7 million in F2020 and

F2021 respectively. Actual write-offs up to the budgeted amounts would be to the

account of ratepayers. Actual write-offs above the budgeted amounts would be to the

account of the shareholder. The size of the F2020 and F2021 project write-off

budgets is based on three-year historical actuals as a percentage of capital

expenditures, applied to forecast capital expenditures in the Test Period.

142. BC Hydro justifies recovery of project write-offs from ratepayers (up to the

budgeted amount) on the ground that project write-offs reflect prudent capital

management. BC Hydro says project write-offs are “effective project and investment

management practices and are the result of mature portfolio management practices

to ensure our capital investments are prudent.” BC Hydro says, “BC Hydro makes

every effort to reduce and avoid project write-offs through the effective use of the

early project investigation process as well as making write-off decisions as early as

possible in the project lifecycle.”149

143. BCSEA accepts the concept that prudent capital management will result in

project write-offs to some extent. Directionally, this supports recovery from

147


Exhibit B-53, BC Hydro Undertaking No.46, cited in BC Hydro Final Argument, para.357. 149

Exhibit B-1, p.8-21, pdf p.983; BC Hydro Final Argument, paras. 369-371; Exhibit B-56, BC Hydro Undertaking No.49, pdf p.9.


ratepayers rather than the shareholder. In BCSEA’s view, BC Hydro’s capped

approach (actual project write-offs above the budget figure are to the account of the

shareholder) limits any (theoretical) potential for the utility to allow increased project

write-offs due to recovery from ratepayers.150

144. In terms of the size of the proposed F2020 and F2021 budgets for project write-

offs, BCSEA considers the proposed methodology reasonable. The historical project

write-offs occurred when they were to the account of the shareholder, so they are not

influenced by moral hazard. For these reasons, BCSEA does not oppose approval of

BC Hydro’s proposed budgets for project write-offs in the Test Period.

(h) Variances from Plan on past projects

145. BC Hydro has explained variances from plan on past projects. BCSEA’s view is

that these explanations have been appropriately probed in the information requests

and the oral hearing. BCSEA is not aware of any evidence that would warrant a

finding by the Commission that BC Hydro’s spending on a capital project was

imprudent so as to justify denying recovery of costs.

(i) Industrial load interconnection

146. “Industrial load interconnection” in this section refers to interconnections by

customers or IPPs at transmission voltages and interconnections of large loads at

distribution voltages. This section does not address connections by residential and

small commercial customers to distribution feeders.

147. BC Hydro’s industrial load interconnection practices have long been criticized as

too slow and too expensive for the customer or IPP wanting to connect. BC Hydro

disagrees, stating:

“BC Hydro is managing its industrial load interconnection requests well, with study times comparing well against BC Hydro’s own business practice timelines and the practices at other utilities. BC Hydro is, however, continuing to look for opportunities to improve the process.”151

148. At a high level, BCSEA certainly wants to see interconnections being achieved in

shorter rather than longer timeframes, at lower rather than higher costs consistent

with safety, reliability and future needs, and with cost allocation that fairly balances

150

As of December 31, 2019, the actual project write-offs in F2020 already exceeded the F2020 budget of $9.9 million by $4.2 million. Exhibit B-56, BC Hydro Undertaking No.49, pdf p.9. 151



the interests of existing and future customers and IPPs, and promotes low-carbon

electrification. Of course, ‘the devil is in the details.’

149. In BCSEA’s view, BC Hydro’s specific arguments are well supported by the

evidence:

a. Distribution and transmission interconnection processes are governed by the

tariff and published business practices;152

b. BC Hydro has engaged in continuous improvement of interconnection

processes;153

c. Interconnections are prioritized in the capital planning process and well

supported;154

d. BC Hydro is engaging with customers on its interconnection processes;155

e. BC Hydro has been meeting its internal targets and also benchmarks

favourably;156 and

f. BC Hydro will continue to improve the interconnection process.157

150. Nevertheless, BCSEA hopes and expects that there is considerable room for

improvement in BC Hydro’s industrial load interconnection regime, particularly for the

purpose of fostering low-carbon electrification.

K. CONCLUSION AND REQUESTED FINDINGS

151. In BCSEA’s view, the evidence establishes that BC Hydro has well-developed

planning and delivery processes and that BC Hydro is delivering its projects

effectively and efficiently. BCSEA respectfully submits that the Commission should

find that the planned capital additions and expenditures for the Test Period are

reasonable.

152








PART EIGHT: REGULATORY ACCOUNTS

A. INTRODUCTION

152. BC Hydro seeks approval of the Dismantling Cost Regulatory Account, and

closure of four regulatory accounts. BCSEA agrees with BC Hydro that the

underlying rationale for the BCUC’s approval of the existing regulatory accounts

remains sound even though the Government has repealed directions regarding some

of BC Hydro’s regulatory accounts.158

B. BC HYDRO’S REGULATORY ACCOUNTS, ACCOUNTING STANDARDS AND BCUC GUIDELINES

153. BCSEA accepts BC Hydro’s premise that it uses regulatory accounts for four

purposes:

“(1) to ensure that customers pay actual costs (no more, no less) where uncontrollable and unpredictable factors could otherwise produce unfair results,

(2) to defer differences between forecast and actual costs or revenues due to uncontrollable risks,

(3) to smooth out the rate impact of large, non-recurring costs, and

(4) to better match costs and benefits for customers.”159

154. BCSEA also accepts BC Hydro’s premise that its regulatory accounts should

comply with International Financial Reporting Standards (IFRS) and the BCUC’s

Regulatory Account Checklist.160

155. BCSEA agrees with BC Hydro that rate-regulated accounting is permitted under

“IFRS 14, Regulatory Deferral Accounts.”161

156. BCSEA accepts BC Hydro’s evidence that its existing regulatory accounts fall

within the categories identified in the BCUC Regulatory Account Checklist.162

158







C. MERITS OF EACH REGULATORY ACCOUNT, NUMBER OF ACCOUNTS

157. BCSEA considers that regulatory accounts can be an appropriate and desirable

mechanism to shift the timing and allocation of a utility’s costs and revenue. BCSEA

accepts application of the matching principle in situations in which current

expenditures benefit future customers. This accords with economically efficient price

signals. BCSEA opposes the misuse of regulatory accounts to shift to future

customers the costs of meeting the needs of current customers. This would be

contrary to economically efficient price signals and contrary to the principle of

intergenerational equity.

158. BCSEA would disagree with a suggestion that the number of BC Hydro’s

regulatory accounts warrants concern in and of itself. In BCSEA’s view, the focus

should be on the purposes for which each regulatory account is established and

maintained, the balance in each account and in total, and the mechanisms for

reducing the positive or negative balances in each account and in total. Moreover,

the number of BC Hydro’s regulatory accounts is within the industry range, which is

broad. And, BC Hydro is not proposing to increase the number of regulatory

accounts; rather, it is proposing to close four regulatory accounts, with up to four

more to follow.

159. The Association of Major Power Customers (AMPC) filed evidence prepared by

InterGroup Consultants. One of InterGroup’s recommendations addresses BC

Hydro’s regulatory accounts:

“7. The BCUC should direct BC Hydro to simplify the regulatory and deferral accounts as a long-term priority, to help ensure BC Hydro’s costs are fully regulated, and are transparent to the regulator and impacted parties (Section 4.5).”163

160. BCSEA asked AMPC to clarify if the intention was to simplify by combining

regulatory accounts to reduce the number of regulatory accounts, or to simplify by

removing certain types of spending from regulatory account treatment and

recovering such spending in the revenue requirement for a given test year.

161. AMPC’s response says BC Hydro’s regulatory accounts should be both reduced

in number and narrowed in scope. AMPC states:

“The scope of deferral accounts means that BC Hydro’s shareholder is at very little risk from normal business functions and variances. If the

163

Exhibit C-11-11, AMPC Evidence, pdf p.6.


accounts are not simplified and narrowed (both in scope and number), the justification for a ROE is significantly undermined (i.e., the justification for reward based on assumed risk diminishes as the risk assumed diminishes). Further, the accounts are excessively broad which makes transparent regulation difficult. For these reasons the accounts should ideally be narrowed in scope (not just collapsed into fewer accounts). Absent such steps, the ROE should be adjusted materially downwards.”164

162. BCSEA is not persuaded that BC Hydro’s regulatory accounts should be reduced

in number and narrowed in scope, for the following reasons.

a. The number of regulatory accounts is not in itself a problem, and in any event

is being reduced.

b. AMPC does not identify which regulatory account(s) it says should be

narrowed in scope. It would be inappropriate to set out to narrow the scope of

all of BC Hydro’s regulatory accounts. AMPC acknowledges this when it

(appropriately) defends amortization of BC Hydro’s DSM expenditures.

c. The relevance and consequences of BC Hydro’s regulatory accounts on the

Commission’s forthcoming determination of BC Hydro’s return on equity is

not within the scope of the current proceeding. Moreover, even if it was

assumed for the sake of argument that the number and scope of BC Hydro’s

regulatory accounts points to a lower ROE, in BCSEA’s view the Panel in the

current proceeding could not, and should not, endeavor to boost BC Hydro’s

future ROE by somehow directing BC Hydro to reduce the number and scope

of its regulatory accounts.

d. There is no evidence that BC Hydro’s revenue requirement (and rates) would

necessarily, or even likely, be lower if the number and scope of regulatory

accounts was reduced. At face value, reducing the number and scope of

regulatory accounts would increase both shareholder’s and ratepayers’ risk of

variance between forecasts and actuals.165

163. BC Hydro says it plans to limit future applications for new regulatory accounts to

situations where there are un-forecast and non-controllable expenditures greater

than $10 million in a fiscal year. BC Hydro is not seeking approval of the $10 million

threshold. It says, “proposals regarding specific regulatory accounts should be

164

Exhibit C-11-13, AMPC Response to BCSEA 6.1, pdf pp.41-42. 165

Transcript Vol.7, p.978 line 26 to p.980 line 3 (Mr. Layton).


evaluated by the BCUC individually on their merits.”166 BC Hydro says the $10 million

threshold applies to new regulatory accounts, not to whether existing regulatory

accounts should be closed. BCSEA does not oppose this approach.

164. On the subject of whether existing regulatory accounts should be closed, the

Commission asked BC Hydro why it is appropriate to continue to defer the variances

between the actual and forecast cost of energy arising from differences between

actual and forecast domestic customer load to the NHDA. BCSEA agrees with BC

Hydro’s response that focuses on the variances being uncontrollable:

“Variances between the actual and forecast cost of energy arising from differences between actual and forecast domestic customer load are beyond BC Hydro’s control and are frequently volatile and unpredictable due to uncontrollable factors such as weather and economic conditions.

For example, if British Columbia experiences a cold winter, actual load may be higher than forecast, which would mean that BC Hydro would collect more revenue than forecast. If this variance was not deferred, this would result in an increase in BC Hydro’s net income, which would be to the account of the shareholder, rather than to the benefit of ratepayers.

Similarly, uncontrollable events could result in actual load being lower than forecast. A specific and notable example is the July 2015 closure of the Howe Sound Pulp and Paper facility due to low water levels. This closure was unexpected and represented approximately $40 million in reduced annual revenue to BC Hydro. If this variance was not deferred, it would have resulted in a significant impact to BC Hydro’s net income in that fiscal year...”167

D. BC HYDRO’S REGULATORY ACCOUNTS, BENEFIT TO CUSTOMERS

165. BCSEA agrees that BC Hydro’s regulatory accounts benefit customers.

166. The Cost of Energy Variance Accounts (Heritage Deferral Account and Non-

Heritage Deferral Account) manage uncontrollable factors and volatility.

Uncontrollable and difficult to predict factors include the weather, water inflows,

system load requirements, market commodity prices, exchange rates, transmission

rates, surplus sales, and domestic load. Customers pay the actual costs of energy,

and neither the ratepayers nor the shareholder reaps a windfall due to the inevitable

variance between forecast and actual costs of energy.168

166

Exhibit B-16, CEC 1.69.1, pdf p.1442. 167

Exhibit B-16, BCUC IR 3.301.4, pdf p.172. 168

Transcript Vol.7, p.978 line 26 to p.980 line 3 (Mr. Layton).


167. The regulatory accounts BC Hydro seeks to continue have each been approved

by the Utilities Commission in the past. The Commission has also approved

regulatory accounts for FortisBC Inc. (electric) to address variances between actual

and forecast figures for uncontrollable factors. More than half (54%) of the utilities

covered by S&P Global Market Intelligence’s Regulatory Research Associates use a

decoupling type of adjustment clause.169

168. Regarding the Non-Current Pension Costs Regulatory Account,170 the factors

affecting the variances are largely market driven and beyond BC Hydro’s control.

BCSEA agrees that the Non-Current Pension Costs Regulatory Account avoids

windfall gains and losses for either the shareholder or ratepayers, consistent with the

“forecast variance account” category of the BCUC’s Regulatory Account Checklist.171

169. BCSEA supports continuation of the Real Property Sales Regulatory Account.

BCSEA concurs with BC Hydro that this account allows ratepayers to receive

benefits that would otherwise flow to the shareholder.172 By default, the shareholder,

not ratepayers, is entitled to the proceeds of sale from properties that are no longer

used and useful for utility purposes.173 BC Hydro has properties and property rights

purchased over the decades for utility purposes, but that are now surplus to BC

Hydro’s requirements.174 As part of the former 10 Year Rates Plan, the Government

directed approval of the account, by which $100 million of net proceeds from sales of

surplus properties would benefit ratepayers.175 The Ratepayers have been getting

the financial benefit of sales of these properties since 2015, in the form of rates that

were lower than they would otherwise have been.176 There is minimal risk to

ratepayers, as each of the properties has been sold at a profit.177 BCSEA agrees that

the carrying and site improvement costs being paid by customers in rates are minor

in comparison with the sale proceeds from which customers are benefitting.178

170. BCSEA strongly supports continuation of the Demand Side Management (DSM)

Regulatory Account. The DSM Regulatory Account captures all of BC Hydro’s

169

Exhibit B-28-2, p.3 of 39, pdf p.5. 170

Exhibit B-1, p.7-44, et seq., pdf p.934. 171










traditional DSM costs, and also its low-carbon electrification expenditures on

undertakings defined in section 4 (3) (a), (b), (c) or (d) of the GGRR. The DSM

Regulatory Account is amortized over a period of time to reflect the average

persistence of the benefits of the expenditures. This is an application of benefit

matching. As BC Hydro notes, “Benefit matching is a recognized principle in the

BCUC Checklist, and the deferral of DSM costs is a common accounting treatment in

the industry.”179

171. In sub-heading (d) before para.422 of its Final Argument, BC Hydro says the

DSM Regulatory Account “ensures intergenerational equity by matching costs and

benefits.” [underline added] The DSM Regulatory Account certainly matches costs

and benefits. However, in BCSEA’s view this is not a matter of intergenerational

equity. Intergenerational equity means that the costs of present benefits are not

deferred to be paid by future ratepayers. This is explained further detail in

paragraphs 176 and 181, below.

172. BCSEA agrees with BC Hydro that all DSM costs are appropriately included in

the DSM Regulatory Account for amortization over a period of years reflecting the

(weighted) average measure life. The DSM benefits are the result of the entire DSM

portfolio. In BCSEA’s view, it would not be reasonable to exclude the costs of Indirect

and Portfolio Enabling activities from DSM Regulatory Account. These activities are

necessary to successfully design, develop, and implement a successful portfolio.180

173. BCSEA supports continuation of the Remediation Regulatory Account. It

captures variances between forecast and actual asbestos remediation costs and

costs related to compliance with polychlorinated biphenyl regulations. These costs

are unpredictable and there have been significant variances.

E. AUDITOR GENERAL’S CONCERNS ABOUT REGULATORY ACCOUNTS

174. The BC Auditor General removed her qualification regarding the use of rate-

regulated accounting at BC Hydro on the Government’s F2019 financial

statements.181

179


Exhibit B-1, Appendix X, p.77, pdf p.2217. 181

Exhibit B-12, BCUC 2.201.3, cited in BC Hydro Final Argument, para.429.


F. BC HYDRO MANAGEMENT OF REGULATORY ACCOUNT BALANCES

175. BCSEA does not disagree with BC Hydro’s observation that the overall regulatory

accounts net balance has declined significantly from its peak.

176. BC Hydro states, “Approximately 80% of the forecast balances in fiscal 2024

resides in five regulatory accounts that are being, or will be, recovered over a longer

period of time to promote intergenerational equity.”182 BCSEA does not disagree that

approximately 80% of the forecast balances in F2024 resides in five regulatory

accounts that are being, or will be, recovered over a longer period of time. This is a

matter of benefits matching,183 which BCSEA supports. However, it is not, in

BCSEA’s view as noted above, a matter of intergenerational equity. The present

generation enjoys the benefit of investments made by earlier generations. It is

incumbent on the current generation to pay this forward to future generations.

Intergenerational equity means that the present generation must not defer to future

generations the costs of benefits received by the present generation.

Intergenerational equity does not prevent the present generation deferring to future

generations the costs of benefits that will be received by future generations: that is

benefits matching, which is an accepted accounting principle.

177. Approved recovery mechanisms are in place for all the regulatory accounts

except three, which do not yet require a recovery mechanism.184 BCSEA concurs

with BC Hydro that the approved recovery mechanisms remain appropriate.

178. As stated in paragraph 170, above, BCSEA specifically endorses continuation of

the DSM Regulatory Account. In BCSEA’s view, the current 15-year amortization

period is appropriate for the DSM Regulatory Account, as it is based on evidence of

the weighted average (by GWh and by $) measure life of traditional DSM and low-

carbon electrification initiatives.185

179. The figures for weighted average measure life vary slightly between three

categories: measures in the DSM Regulatory Account at the end of F2021,

measures in the DSM Regulatory Account during the two-year Test Period, and

182

BC Hydro Final Argument, para.432, underline added. BC Hydro also cites intergenerational equity in paras.442 and 443 in support of amortizing the DSM Regulatory Account. 183

The five regulatory accounts in question are listed under the heading “Benefits Matching Accounts” in Table D-2, Exhibit B-19, pdf p.121 and in Table 7-2, Exhibit B-1, p.7-10, pdf p.900. 184

BC Hydro Final Argument, para.433. Recovery mechanism are not in place for the Mining Customer Payment Plan Regulatory Account, Customer Crisis Fund Regulatory Account, and the Site C Regulatory Account. 185



measures over the ten-year period from F2020 to F2029. BCSEA provides a

summary in the table below:

Average Measure Life (years), Traditional DSM Programs and Low-Carbon Electrification

GWh Weighted $ Weighted

DSM RA end of F2019186 14.5 14.0

Test Period F2020-F2021187 17.1 15.0

F2020-F2029188 16.2 15.0

180. BCSEA submits that 15 years is the appropriate amortization period for the DSM

Regulatory Account at the present time, even though the weighted average measure

life for expenditures in the DSM RA at the end of F2019 was slightly below 15 years.

The following reasons support this view.

a. BCSEA agrees with BC Hydro that the weighted average measure life figures

for traditional DSM “are conservative because the calculation equates

persistence to the effective measure life of a DSM initiative and does not

consider that some customers will re-install an efficient measure when the

initial measure has reached its end-of-life, rather than revert to an inefficient

measure.”189

b. BCSEA submits that the evidence of measure life based on the Test Period

and the ten-year period going forward (i.e., F2020-F2029) should carry more

weight than the evidence based on the expenditures in the DSM RA at the

end of F2019.

c. The measure life of LCE initiatives is substantially longer than the measure

life of traditional DSM measures.190 BCSEA expects that LCE expenditures

will ramp up in the coming years at a higher rate than traditional DSM

expenditures. If so, then LCE will form an increasing proportion of the DSM

RA and this will tend to increase the average measure life.

186

Exhibit B-5, BCUC 1.150.5.1, pdf p.1716. 187

Exhibit B-1, Table 10-14, p.10-37, pdf p.1067. 188



The Low-Carbon Electrification measure life estimates range from 19.8 to 27.8 years: Exhibit B-1, Table 10-14, p.10-37, pdf p.1067; Exhibit B-5, BCUC 1.150.5.1, pdf p.1716.


d. Stability in the amortization period is desirable. Minor differences between the

estimated measure life and the amortization period, whether higher or lower,

do not justify changing the amortization period.

181. BCSEA agrees with BC Hydro that the amortization period for the DSM

Regulatory Account should not be shortened, e.g., to ten years from the current 15

years.191 However, BCSEA disagrees that this position is supported by

intergenerational equity. BCSEA’s position is based on the benefits matching

principle. Intergenerational equity is not a synonym for benefits matching. Future

generations do not owe us anything. We owe previous generations for making the

investments from which we are now benefiting.

182. Regarding the Non-Current Pension Costs Regulatory Account, BCSEA agrees

with BC Hydro that 13 years is the appropriate amortization period based on the

evidence. BCSEA accepts BC Hydro’s argument that accounting standards

precluded BC Hydro from recognizing the impact of changes in legislation relating to

B.C.’s Medical Services Plan before the required legislation had been passed.192

183. BCSEA agrees with BC Hydro’s summary argument that cost control measures

are in place for deferred controllable costs.193

G. BC HYDRO’S PROPOSED CHANGES TO REGULATORY ACCOUNTS

184. BCSEA supports BC Hydro proposals to:

a. reduce the DARR from 5% to 0% on April 1, 2019; and

b. refund over the Test Period the F2019 net closing balance, the forecast

F2020 and F2021 net additions, and net interest regarding the Cost of Energy

Variance Accounts.194

185. Based on the Evidentiary Update, these proposals result in a refund to the benefit

of ratepayers during the Test Period of approximately $630.8 million.195 BCSEA

considers this to be consistent with benefits matching and reducing upward pressure

on rates. In terms of intergenerational equity, to the extent that the Rate Smoothing

Regulatory Account deferred to future customers the costs of providing service to

191





Exhibit B-17, Zone II RPG 3.60.1, pdf p.596.


previous customers, the transfer of the $2.2 billion from BC Hydro to the Government

has the effect of transferring the intergenerational equity problem from ratepayers to

taxpayers. BCSEA is not suggesting that anything should be done differently at this

point.

186. BCSEA supports BC Hydro’s proposal to refund most of the approximately

$630.8 million in F2021. This avoids retroactively adjusting the interim F2020 rates,

and hence avoids a potential source of customer confusion.196

187. BCSEA supports BC Hydro’s proposal to return the net credit balance in the Cost

of Energy Variance Accounts to ratepayers during the Test Period. BCSEA agrees

with BC Hydro’s rationale that the one-time accounting adjustment of $319 million

related to the recognition of revenues under the Skagit River Agreement means that

previous ratepayers have overpaid.197 However, BCSEA characterizes this an

instance of benefits matching, not intergenerational equity.

188. BCSEA supports BC Hydro’s proposal to defer variances related to electricity

purchase agreements (EPAs) that are leases under IFRS 16 to the Non-Heritage

Deferral Account.

189. BCSEA generally supports BC Hydro’s proposal to defer variances between

forecast and actual amounts related to the Biomass Energy Program to the Non-

Heritage Deferral Account.198 For the record, however, BCSEA opposes BC Hydro

recovering from customers its costs of acquiring non-clean or renewable power

generated from contaminated rail ties pursuant to the EPA between BC Hydro and

Atlantic Power. BCSEA acknowledges that Order in Council No. 158/2019 requires

the BCUC to allow BC Hydro to recover the costs associated with the Biomass

Energy Program.

190. BCSEA supports BC Hydro’s proposal to continue to defer to the Dismantling

Cost Regulatory Account, on an annual and ongoing basis, any variances between

forecast and actual dismantling costs.199

196




Exhibit B-6, CEC 1.71.1, pdf p.1474; BC Hydro Final Argument, para.460.


H. FORECAST FOR REAL PROPERTY SALES

191. BCSEA accepts BC Hydro evidence regarding the reasonableness of BC Hydro’s

forecast of real property sales for the Test Period.200

I. CONCLUSION AND REQUESTED FINDING

192. BCSEA does not agree with BC Hydro’s use of the term “intergenerational equity”

as a synonym for the benefits matching principle. However, BCSEA supports a

finding that BC Hydro’s current use of regulatory accounts, its proposals to close and

modify some of them, and its forecasted additions, are just and reasonable.

PART NINE: OTHER REVENUE REQUIREMENTS ITEMS

A. INTRODUCTION

193. This Part addresses depreciation rates, finance charges and return on equity.

B. TEST PERIOD REVENUE REQUIREMENTS, DEPRECIATION RATES

194. BCSEA agrees that BC Hydro’s depreciation rates are appropriate for setting

rates in the Test Period.201 BC Hydro has said it will conduct a depreciation study in

the near future. In BCSEA’s view, BC Hydro should not be faulted for not prioritizing

a new comprehensive depreciation study until now.202

C. FORECAST FINANCE CHARGES

195. BCSEA accepts that the forecast finance charges in the Evidentiary Update are

reasonable for the purposes of setting rates during the Test Period.203

196. In the 2016 proceeding leading to Decision and Order G-42-16, BCSEA

supported the proposed Debt Management Regulatory Account and BC Hydro’s

Debt Management Strategy to use Future Debt Hedges. BCSEA accepts that the

purpose of the hedging strategy is to lock in a rate, rather than to make a profit.

200



BC Hydro Vice-President and Chief Financial Officer David Wong provides useful explanation of industry practice regarding depreciation studies for capital intensive utilities like BC Hydro at Transcript Vol.5, p.445 line 3 to p.446 line 16. 203



D. INTERGROUP’S RECOMMENDATIONS REGARDING BC HYDRO’S FUTURE RETURN ON EQUITY

197. BC Hydro’s return on equity is fixed for the Test Period. BC Hydro will apply to

the Commission for approval of a return on equity that will be applicable after the

Test Period. In BCSEA’s view, it would be premature for the Current Panel to

address the content of the future determination of BC Hydro’s future return on equity.

E. CONCLUSION AND REQUESTED FINDINGS

198. In BCSEA’s view, the Commission should find that BC Hydro’s depreciation rates

and forecast finance charges are reasonable for the Test Period.

PART TEN: TRANSMISSION REVENUE REQUIREMENTS

A. INTRODUCTION

199. The Transmission Revenue Requirements include the costs of the transmission

lines and high-voltage station equipment that provide transmission service under BC

Hydro’s Open Access Transmission Tariff (OATT). BC Hydro says its updated OATT

rates are just and reasonable and should be approved.

B. TRR AND OATT RATES

200. BCSEA has no reason to disagree with BC Hydro’s position that the

Transmission Revenue Requirements and OATT rates reflect established cost of

service methodology based on cost causation and rate design approved by the

Commission in past proceedings.204

C. THE OATT RATE DESIGN

201. BCSEA has reviewed BC Hydro’s informative history of the development of the

electricity industry and markets within the Western Interconnection, and the approval

and evolution of BC Hydro’s Open Access Transmission Tariff (OATT) to meet

evolving needs for access to the wholesale transmission grid and in particular the

requirements of the U.S. Federal Energy Regulatory Commission (FERC).205

204


Exhibit B-31, Panel 2.8.5, 2.8.5.1, 2.8.5.2, 2.8.6, pdf pp.61-79. And, BC Hydro Final Argument, paras.498-501.


202. As BC Hydro states:

“BC Hydro continues to monitor market evolution and FERC Orders and make applications to amend its OATT that it believes are appropriate in British Columbia. Such applications also keep the [BC Hydro] OATT aligned with the FERC pro forma OATT which allows Powerex to demonstrate to FERC that its comparability requirements are being met, which in turn allows Powerex to maintain its access to markets in the U.S. in order to generate Trade Income for the benefit of BC Hydro’s ratepayers.

BC Hydro is currently developing its response to three recent FERC Orders, including engagement with transmission customers and interested parties.”206

203. BCSEA agrees with BC Hydro that the BC Hydro OATT rate design remains

valid, and notes that BC Hydro is not requesting any determination in this proceeding

regarding the design of the OATT.207

D. CONCLUSION AND REQUESTED FINDINGS

204. BCSEA considers that the Test Period OATT rates as filed208 are just and

reasonable and should be approved.

PART ELEVEN: DEMAND-SIDE MANAGEMENT

A. INTRODUCTION

205. This Part addresses both BC Hydro’s traditional Demand-Side Management

(DSM) expenditures and its low-carbon electrification (LCE) expenditures on

undertakings defined in section 4 (3) (a), (b), (c) or (d) of the GGRR, both of which

are the subject of Chapter 10 of the Application.

206. In this proceeding, BC Hydro seeks Commission acceptance of a traditional DSM

Expenditure Schedule for the Test Period under s.44.2 of the UCA. The expenditure

schedule is for $90.8 million in F2020 and $89.1 million in F2021.209 The DSM

Expenditure Schedule reflects the first two fiscal years of the three-fiscal-year DSM

Plan in Appendix X of the Application.

206

Exhibit B-31, Panel 2.8.5.1, pdf p.68. 207


Exhibit B-11-2, Appendix E. 209

Exhibit B-11, Evidentiary Update, p.7, pdf p.12.


207. Regarding the budgeted expenditures for LCE Projects/Program during the Test

Period, BCSEA agrees with BC Hydro that these expenditures are exempt from

rejection by the Commission by virtue of the GGRR and section 18 of the CEA. BC

Hydro also requests approval to defer its LCE expenditures over the Test Period to

the DSM Regulatory Account, pursuant to the Direction to the BCUC Respecting

Undertaking Costs. These points are discussed below.

208. BCSEA supports a determination by the Panel that the traditional DSM

expenditure schedule for the Test Period is in the public interest, and that BC

Hydro’s LCE expenditures should be deferred to the DSM Regulatory Account.

209. Assuming the traditional DSM Expenditure Schedule for the Test Period is

accepted by the Commission, BCSEA is unsure whether BC Hydro requires the

Commission’s approval to record the DSM costs in the DSM Regulatory Account.

The Panel in the Previous RRA Decision noted that “pursuant to Direction No. 7 BC

Hydro’s development, implementation and administration costs for DSM are

recorded in the DSM Regulatory Account and amortized over 15 years.” However,

Direction No. 7 has since been repealed.210 If Commission approval is indeed

required, and if the traditional DSM Expenditure Schedule for the Test Period is

accepted (which BCSEA supports), then BCSEA supports approval of the costs

being recorded in the DSM Regulatory and (as argued below) being amortized over

15 years.

210. BCSEA is satisfied with BC Hydro’s explanation of why DSM is located with the

People, Customer and Corporate Affairs Business Group rather than the Integrated

Planning Business Group.211

B. MODERATION APPROACH, ENERGY SURPLUS

211. The spending envelope in the DSM Expenditure Schedule for the Test Period

roughly continues the “moderation approach” in the F2017-F2019 DSM Expenditure

Schedule accepted by the Commission.212

212. BC Hydro’s traditional DSM portfolio expenditures, planned and actual, excluding

expenditures on the Thermo-Mechanical Pulp Program (TMP), are shown in the

following table:

210

B.C. Reg. 28/2014, repealed by B.C. Reg. 24/2019, effective February 14, 2019. 211


Decision and Order G-47-18, p.78, pdf p.85.


Traditional DSM Portfolio Expenditures, Plan and Actual, excluding TMP213

$million Plan Actual

F2017 113.7 97.3

F2018 104.8 84.2

F2019 100.7 76.4

F2020 Test Period 90.8 TBD

F2021 Test Period 89.1 TBD

F2022214 85.5 TBD

213. BCSEA would strongly prefer a more ambitious traditional DSM spending

envelope, and a more ambitious amount of energy and capacity savings, in the Test

Period. In BCSEA’s view, the amount of low-carbon electrification needed for B.C. to

meet its legislated GHG reduction targets under the CleanBC Plan will put BC Hydro

into an energy and capacity deficit planning position sooner rather than later. BC

Hydro will then require all cost-effective traditional DSM savings. Despite BC Hydro’s

assurances, BCSEA is concerned that the “moderation approach” jeopardizes BC

Hydro’s ability to ramp up conservation and efficiency savings when they become

urgently needed. In addition, BCSEA is concerned that the decision not to achieve all

cost-effective energy and capacity savings during the Test Period will create “lost

opportunities” by allowing inefficient assets to be locked-in for the long term.

214. BCSEA acknowledges that BC Hydro currently has surplus energy and capacity

for planning purposes.215 In this context, the market price screening filter ensures

that the traditional DSM activities during the Test Period put downward pressure on

rates.

215. BCSEA acknowledges that the BC Government has expressed support for BC

Hydro maintaining its traditional DSM spending at the same level overall.216

216. BCSEA disagrees that the proposed level of traditional DSM spending in the Test

Period is supported by the B.C. energy objective “of the authority reducing its

expected increase in demand for electricity by the year 2020 by at least 66%.”217 BC

Hydro achieved the 66% reduction target several years ago, and in any event the

66% target is a floor not a ceiling.

213


Exhibit B-1, Appendix X, Table 2, p.7, pdf p.2147. 215



BC Hydro Final Argument, para.511, underline added.


217. As noted above, BCSEA is not convinced by BC Hydro’s assurance that it retains

the ability to ramp up traditional DSM activities in the future in response to the 2021

IRP or the CleanBC Plan.218

C. BC HYDRO’S TRADITIONAL DSM PLAN, BCUC DIRECTIVES, GOVERNMENT PRIORITIES, AND DSM REGULATION

(a) Increased Residential DSM, decreased Commercial and Industrial DSM

218. BC Hydro’s traditional DSM expenditure schedule for the Test Period increases

the spending on programs aimed at Residential customers and decreases the

spending on programs aimed at Commercial/Light Industrial customers. Program

spending aimed at Large Industrial customers remains more or less flat.

219. BCSEA provides the following table showing DSM Programs Expenditures,

without TMP. It can be observed that Residential DSM spending in the Test Period is

higher than in the Previous Test Period (F2017 to F2019). Commercial DSM

spending in the Test Period is below the levels in the Previous Test Period (and

Commercial DSM spending declined substantially over the course of the Previous

Test Period). Industrial DSM spending in the Test Period is about the same as in

F2019 (and rose during the Previous Test Period).

DSM Programs Expenditures, Actual/Forecast, without TMP219

$ millions F2017 F2018 F2019 F2020 F2021 F2022220

Residential 12.5 11.8 14.3 18.4 19.7 21.0

Commercial 34.5 24.7 21.2 18.9 17.5 17.2

Industrial 23.0 22.4 26.8 26.5 26.9 26.3

Total Programs w/o TMP

70.0 58.9 62.3 63.8 64.1 64.5

220. BCSEA supports increasing the Residential component of the DSM spending,

although BCSEA would have preferred that this be accomplished by increasing the

DSM envelope rather than by decreasing DSM spending aimed at Commercial/Light

Industrial customers.

221. The percentage split in traditional DSM program spending in the Test Period is

30%, 38% and 32% for Residential, Commercial/Light Industrial and Large Industrial,

218


Exhibit B-6, Gjoshe 1.14.2, pdf p.1627. 220

Data in this column is from Exhibit B-1, Appendix X, Table 6, p.16, pdf p.2156.


respectively. This is a significant change from the previous period (F2017-F2019), as

shown in the table below:

Traditional DSM Program Spend by Sector (excluding TMP)221

Residential incl. Low Income %

Commercial/Light Industrial %

Large Industrial %

Total %

F2017-F2018 Actual and F2019 Forecast

19 57 24 100

F2020-F2021 Forecast

30 38 32 100

222. The readjustment of traditional DSM program spending between customer

categories is consistent with the Commission Panel’s recommendation in Decision

and Order G-47-18 that BC Hydro consider more targeted DSM programs directed at

residential customers in the next DSM application.222 The Panel gave three reasons

for this recommendation:

“The Panel notes the relatively low level of DSM spending for residential customers (including low-income customers), despite DSM program utility costs that are comparable to those of BC Hydro’s commercial DSM programs.

The Panel further notes BC Hydro’s proposed 39 percent decrease in funding for non-low-income residential programs in this Application.

The Panel also notes that residential customers are allocated 40 percent of DSM program costs, but do not receive a comparable share of the DSM program funding.”223

221


Decision and Order G-47-18, p.81, pdf p.88, and p.116, pdf p.123. 223

Decision and Order G-47-18, p.81, pdf p.88, bullets added for clarity.


223. BCSEA supports the Low-Income Program. The DSM expenditure schedule for

the Test Period expands spending on the Low-Income Program.224 Spending and

energy savings under the Low-Income Program continue to follow an upward track,

as shown in the following table.

Low-Income DSM Program, Program Expenditures and Energy Savings by Year225

F2016 Actual

F2017 Actual

F2018 Actual

F2019 Plan

F2020 Plan Test

Period

F2021 Plan Test

Period

F2022 Plan

Program Expenditures $million

$2.4 $2.9 $3.5 $3.8 $5.8 $6.9 $7.8

Energy Savings GWh/y

4.8 4.5 5.7 6.2 8.9 8.8 9.3

224. The Low-Income Program contains three sub-components: Energy Savings Kits,

Energy Conservation Assistance Program, and a new Indigenous Customers Offer

for customers connected to the Integrated system. Participation in each component

continues to increase, as shown in the following table.

Low-Income DSM Program, Participation226

F2016 Actual

F2017 Actual

F2018 Actual

F2019 Plan

F2020 Plan Test

Period

F2021 Plan Test

Period

F2022 Plan

Energy Savings Kits 10,563 10,611 13,489 16,000 22,250 22,800 22,800

Energy Conservation Savings Program

2,764 2,836 3,600 3,040 3,905 4,360 4,495

Indigenous Customers Offer

0 0 0 0 70 150 315

Total 13,327 13,447 17,089 19,040 26,225 27,310 27,610

225. The Home Renovation Rebate Program focuses on customers with electric heat,

who typically have high electric bills as heating is normally 50% of a home’s energy

consumption.227 BCSEA supports BC Hydro’s measures to increase participation in

the Home Renovation Rebate Program228 through additional measures such as heat

pumps and smart thermostats, and increased incentives.229 BCSEA asked about the

224


Exhibit B-6, BCSEA 1.44.1, pdf p.799. As of May 2, 2019. 226

Exhibit B-6, BCSEA 1.44.1, pdf p.799. As of May 2, 2019. 227


Exhibit B-6, BCSEA 1.43.2.2, pdf p.787. 229

Exhibit B-6, BCSEA 1.43.2.1, pdf p.785.


details of these improvements, including the specific measures, incentive level,

anticipated participation, and eligibility criteria.230 BCSEA is satisfied with BC Hydro’s

fulsome responses.

226. As the Home Renovation Rebate Program focuses on customers with electric

heat, BCSEA asked whether incentives are available for customers who are fuel-

switching from higher-carbon heating equipment (such as oil or natural gas). BCSEA

is satisfied with BC Hydro’s response that:

“BC Hydro does not offer heat pump incentives for residential customers who are fuel-switching from higher-carbon producing heating equipment because the Province of British Columbia already provides heat pump incentives for fuel switching through the CleanBC Better Buildings Program. BC Hydro administers these incentives on behalf of the Government of B.C. ... BC Hydro funded programs are designed to align with, and not overlap with, government funded programs.”231

(b) Social Housing DSM

227. Within the Commercial program area, in F2019 BC Hydro launched an initiative

aimed at providers of social housing, such as BC Housing, and the B.C. Non-Profit

Housing Authority. BCSEA supports this initiative, called the “Social Housing Retrofit

Support Offer for Multi-Unit Residential Buildings.” BCSEA has supported increased

coordination on DSM between BC’s energy utilities, and notes with approval that the

offer is a partnership between FortisBC Energy Inc., FortisBC Inc., BC Hydro and the

Government of B.C. (through Efficiency B.C.)232

228. The Social Housing Offer includes four measures:

Energy study funding to review the potential energy conservation measures;

Implementation support that provides engineering design, tendering and project management;

Rebates for upgrading eligible technologies for lighting, HVAC and commercial kitchen; and,

Rebates for low-carbon electrification opportunities.233

230

Exhibit B-6, BCSEA 1.43.2.1, 1.43.2.2, 1.43.2.3., 1.43.2.4, 1.43.3.5 and 1.46.1. 231

Exhibit B-6, BCSEA 1.43.2.6, pdf p.795. And see: Exhibit B-6, BCSEA 1.46.1, pdf p.803. 232 Exhibit B-1, Appendix X, p.45, pdf p.2185. “Efficiency B.C.” is now branded CleanBC Better

Homes for residential programs and CleanBC Better Buildings for commercial buildings: Exhibit B-31, Panel 2.18.2, Attachment 1, p.6, pdf p.192. 233

Exhibit B-1, Appendix X, p.45, pdf p.2185.


229. BCSEA is satisfied with BC Hydro’s detailed description of the proposed F2020-

F2021 DSM incentives for social housing providers for existing buildings and new

construction.234

(c) Non-Integrated Areas DSM

230. BCSEA supports BC Hydro’s increased DSM activities in Non-Integrated

Areas.235

231. The non-integrated communities have been described as remote and heavily

reliant on electricity for heating, with many homes having poor construction and old

appliances.236 In the previous test period (F2017-F2019), BC Hydro was working with

First Nations and remote communities to trial a number of different approaches to

addressing barriers to DSM and energy efficiency upgrades (i.e. delivery of the

programs). At that time, BC Hydro did not track DSM spending in NIAs.237

232. The Commission Panel in the Previous RRA Decision noted with approval the

significant increase in DSM funding levels in the NIAs since F2016, and implied that

additional DSM expenditures in the NIAs might be justified considering the high

avoided cost of diesel. The Panel states:

“However, requested DSM funding levels as a percentage of revenues in the NIA over the test period are still are estimated to be similar to that of the integrated area, despite the unique market barriers of the NIA communities (including affordability), the significantly higher utility avoided fuel cost (six times higher than BC Hydro’s screening filter), and additional emissions reduction benefits.”238

233. The Panel in the Previous Decision directed BC Hydro to track its DSM spending

in the NIAs and to report on how it has addressed the DSM concerns raised by the

Non Integrated Areas Ratepayers Group and the Zone II Ratepayers Group.239

234. BC Hydro responded positively, in BCSEA’s view. BC Hydro has a new NIA DSM

program in the F2020-F2022 DSM Plan. It says this “is a comprehensive program

that builds on the pilot work conducted to explore delivery approaches and efficiency

234








measures tailored for the NIA.”240 The NIA program includes new residential and

commercial program offers. It also includes “Community Support,” which provides

“financial and technical resources to Indigenous communities in Non-Integrated

Areas to support them in pursuing energy upgrades.”241

235. The following table shows the NIA DSM program expenditures as planned.

Non-Integrated Areas DSM Program Expenditures242

F2020 Plan Test Period

F2021 Plan Test Period

F2022 Plan

$million 1.2 1.4 1.5

236. The cost effectiveness of the NIA program benefits from a higher avoided cost of

energy due to the cost of diesel generation in the NIA communities. As a result, the

NIA program has a positive benefit cost ratio, even without the 40% adder under the

DSM Regulation.243

237. BCSEA asked for an explanation of how the NIA DSM program will ensure that

the training it provides will be sufficient to allow local contractors to effectively install

“deeper measures such as windows and doors, insulation, advanced air sealing,

ventilation systems, heat pumps and programmable thermostats,” given that the

savings that will result from such measures will be highly dependent on quality

installation practices. BCSEA is satisfied with BC Hydro’s detailed response.244

(d) Codes and Standards savings

238. Regarding the presentation of codes and standards savings, the Panel in the

Previous RRA Decision directed BC Hydro to review whether attributing all of the

savings occurring from the implementation of codes and standards to the utility’s

DSM codes and standards program is consistent with industry practice.245 BC Hydro

retained a third party expert, the Cadmus Group, which reported that industry

practice regarding codes and standards attribution is varied.

240


Exhibit B-6, Zone II RPG 1.26.8, cited in BC Hydro Final Argument, para.524. 242


BC Hydro Final Argument, para.526. Demand-Side Measures Regulation, BC Reg. 326/2008, under the Utilities Commission Act. 244

Exhibit B-6, BCSEA 1.47.1, pdf pp.804-805. 245



239. Based on the Cadmus Group’s report, BC Hydro introduced the following

changes:

a. codes and standards savings are excluded from benefit cost calculations and

levelized costs;

b. codes and standards savings are presented as a stand-alone bucket of

energy and associated capacity savings, and are not attributed to individual

programs; and,

c. a forecast of codes and standards savings is provided and incorporated into

BC Hydro’s Load Forecast.246

240. BCSEA supports these changes, which are consistent with the approach taken in

Ontario and Manitoba. As BC Hydro says, “This ensures that there is no distortion to

the cost-effectiveness results of the traditional DSM programs.” BCSEA agrees with

BC Hydro’s comment as follows:

“As BC Hydro’s codes and standards expenditures are still included at the portfolio level, the result is that the cost effectiveness of the DSM portfolio is more conservative than if the codes and standards savings were included. However, all of BC Hydro’s traditional DSM initiatives are cost-effective without any attribution from codes and standards.”247

(e) Capacity-focused DSM

241. BCSEA supports BC Hydro’s pilots and trial offers focused on shifting the timing

of peak demand in areas where BC Hydro faces capacity constraints.248 The

constrained substations where BC Hydro plans to test different capacity focused

solutions are Pineview, Hope and Kent.249 BC Hydro says it expects work from its

capacity focused DSM initiatives to inform the next Integrated Resource Plan.250 And,

BC Hydro is developing a DSM non-wires evaluation framework for planners to use

in identifying options for feeder reinforcement.251

242. BC Hydro describes “success” regarding its capacity-focused DSM pilots in the

following terms:

246

Exhibit B-1, p.10-10, pdf p.1040. 247

BC Hydro Final Argument, para.533, underline added. 248

Exhibit B-1, p.10-21, pdf p.1051. 249



Transcript Vol.12, p.2269 line 1 to p.2272 line 10; Transcript Vol.13, p.2395, line 22 to p.2395, line 5; Transcript Vol.14, p.2630, line 17 to p.2633, line 16.


“Success with each capacity-focused DSM trial or pilot will be in the learning gained with regards to the capability to reliably shift and/or reduce load. This information will help to inform our ability to bundle capacity focused initiatives to defer upgrades at the local level or as resource options to inform the next Integrated Resource Plan.

Beyond the trial or pilot stage, the success of capacity focused initiatives will be based on the ability to reliably shift or reduce loads at a lower cost than supply side resources and infrastructure.”252

243. BCSEA supports BC Hydro’s proposal to extend the funding period for capacity

focused DSM initiatives.253 The dollar amounts and the corresponding fiscal years

are set out in Table 10-9 in the Application.254 BC Hydro describes the extension of

the funding period as follows:

“In the Previous Application, BC Hydro proposed a total budget of $38.6 million for these initiatives from fiscal 2017 to fiscal 2019. This DSM Plan

extends that budget to fiscal 2021 but reduces the overall total by 12 per cent to $34 million.”255

244. BCSEA accepts BC Hydro’s explanation that extending the time period is

desirable “due to the complexity of assessing the impacts and value of capacity-

focused DSM to BC Hydro’s system,” and to provide “more time to incorporate past

learnings into new activities, consider changing technologies and accommodate the

long lead times required for some customer projects.”256

245. Regarding the 12% reduction in capacity-focused DSM spending, BC Hydro’s

evidence is that the reduced budget will not impact its ability to test and analyze

opportunities. BC Hydro says, “The budget reflects the expenditures needed to

implement our capacity-focused DSM activities and is not constraining BC Hydro

during the test period.”257 BC Hydro states:

“Within this proposed budget, BC Hydro will continue to conduct demand response trials in the residential, commercial and industrial sectors. BC Hydro plans to test different solutions in a number of constrained substation areas. The objective of these tests will be to determine whether the combination of demand response activities and targeted energy

252



Exhibit B-1, p.10-22, pdf p.1052. 255

Exhibit B-1, p.10-21, pdf p.1051. 256

Exhibit B-1, p.10-22, pdf p.1052. A detailed rationale for the extension is provided in Exhibit B-5, BCUC 1.183.2, pdf p.2042; and Exhibit B-6, Willis 1.12.1, pdf p.2069. 257

Exhibit B-6, BCSEA 1.39.5.1, pdf p.769.


efficiency offers can shift the timing of peak demand in a constrained local area.”258

246. Again, BCSEA supports the capacity-focused DSM initiative.

(f) Energy Management Activities

247. BCSEA has no objection to BC Hydro’s re-categorization of its existing energy

management activities into a new program, called Energy Management Activities,

within each sector. As BC Hydro explains, “The change aligns with 2017

amendments to the DSM Regulation that added ‘Energy Management Program’

(meaning a program to assist customers to optimize energy use) to the definition of

‘Specified Demand Side Measure’.”259

D. DIRECTIVE 61 REGARDING ALLOCATION OF PORTFOLIO COSTS, RESCISSION

248. BCSEA supports BC Hydro’s request that the BCUC rescind Directive 61 from its

October 2004 Decision on BC Hydro’s Fiscal 2005 to Fiscal 2006 Revenue

Requirements Application.260 Directive 61 requires portfolio level costs to be

allocated to programs.261

249. BCSEA’s view is that costs should only be attributed to programs if they are

solely connected to a specific program.

250. The DSM Regulation, adopted in 2008 after the issuance of Directive 61 in 2004,

contemplates that costs will be attributed to a program only if they are solely

connected to that program.

251. Current industry practice, as expressed in the National Standard Practice Manual

in 2017, is that “fixed portfolio-level costs should not be allocated to programs for the

purpose of assessing the cost-effectiveness of individual programs.”262

252. Decisions on individual programs should be based entirely on the merits of the

program itself. Portfolio-level costs should be considered only when looking at the

cost effectiveness of the overall portfolio, not the cost effectiveness of individual

programs. Including portfolio-level costs in the evaluation of a program could shift the

258

Exhibit B-1, p.10-22, pdf p.1052. 259


Decision and Order No. G-96-04. 261


National Standard Practice Manual, May 2017, cited in Exhibit B-5, BCUC 1.172.1, pdf p.1957.

https://www.bcuc.com/Documents/Proceedings/2004/DOC_5430_BCH%202004RR%20Final.pdf


result from a net benefit to a net cost, which could lead to a program with a net

benefit not being implemented.263

E. TRADITIONAL DSM, UCA, CLEAN ENERGY ACT, AND DSM REGULATION

253. In determining whether to accept the traditional DSM Expenditure Schedule for

the Test Period, section 44.2(5.1) of the UCA requires the BCUC to consider:

a. the interests of persons in B.C. who receive or may receive service from BC

Hydro,

b. B.C.’s energy objectives,

c. the 2013 IRP,264

d. the B.C. energy objective to generate at least 93% of the electricity in British

Columbia from clean or renewable resources and to build the infrastructure

necessary to transmit that electricity, and

e. the extent to which the demand-side measures are cost-effective as defined

in the DSM Regulation.

254. Regarding the extent of the Commission’s discretion in relation to a DSM

expenditure schedule, section 44.2(3) of the UCA provides that the Commission

must accept a schedule if the commission considers that making the expenditures

referred to in the schedule would be in the public interest, or reject the schedule.

Section 44.2(4) provides that the commission may accept or reject, under subsection

(3), a part of a schedule. The Commission does not have authority to direct a utility to

file a DSM expenditure schedule, to make additions to a DSM expenditure schedule,

or to change the design of a particular program.265 However, the Commission has

authority to reject a DSM expenditure schedule, in whole or in part, for stated

reasons that the utility may consider in proposing a modified DSM expenditure

schedule.

263

Exhibit B-1, pp.1034-1035, pdf pp.1064-1065. 264

Section 44.2(5.2)(b) requires the Commission to consider “the most recent of the following documents: (i) an integrated resource plan approved under section 4 of the Clean Energy Act before the repeal of that section; (ii) a long-term resource plan filed by the authority under section 44.1 of this Act.” The 2013 IRP approved by the Government under the CEA is the most recent. Moreover, BC Hydro’s 2008 Long-Term Acquisition Plan, filed under section 44.1 and 44.2 of the UCA, was rejected by the BCUC in Decision and Order G-91-09. 265



255. BCSEA agrees with BC Hydro that the traditional DSM Expenditure Schedule for

the Test Period is in the interests of persons in British Columbia who receive or may

receive service from BC Hydro.266

256. More broadly, the DSM Expenditures Schedule can be expected to generate

considerable economic impacts. For example, a 2017 study by the Deetken Group

for BC Hydro concluded that the DSM Plan is expected to generate the following

economic impacts from F2017 to F2026:

“• GDP impacts of $1.9B

• Employment of 23,300 FTEs

• Provincial tax revenue of $213M.”267

257. BCSEA agrees that the traditional DSM Expenditure Schedule for the Test Period

fosters the B.C. energy objective “to take demand-side measures and to conserve

energy.”268 However, as stated in paragraph 216, BCSEA submits that it cannot be

concluded that the DSM Expenditure Schedule for the Test Period fosters “the

objective of [BC Hydro] reducing its expected increase in demand for electricity by

the year 2020 by at least 66%,”269 because that particular objective has already been

met.

258. BCSEA disagrees with BC Hydro that the traditional DSM Expenditure Schedule

for the Test Period is “consistent with the 2013 IRP.”270 BC Hydro characterizes the

F2020-F2021 DSM spending as a continuation of the F2017-F2019 spending.

However, F2017-F2019 DSM Expenditure Schedule was a reduction in DSM

spending compared to the 2013 IRP. The Panel in the Previous RRA Decision

states, “The Panel also considered in its deliberations the Minister’s letter supporting

BC Hydro’s reduction in DSM spending compared to the 2013 IRP...”271 The Panel

chose to accept the F2017-F2019 DSM Expenditure Schedule, but it did not

conclude that the F2017-F2019 DSM spending was consistent with the 2013 IRP.

259. BCSEA agrees with BC Hydro that the “[traditional DSM] portfolio as a whole, as

well as rate structures and all programs, are cost effective using the modified total

266


Exhibit B-6, Ince IR 1.12.15 Attachment 1, p.2, pdf p.1941. 268


BC Hydro calculates the 66% reduction measure using F2008 as the base year and F2021 as an approximation of 2020. Exhibit B-5, BCUC 1.173.1, pdf p.1963. 270


Decision and Order G-47-18, p.79, pdf p.86, underline added.


resource cost test required by the DSM Regulation.” BCSEA also agrees that “[t]he

Test Period portfolio as a whole, as well as rate and all programs, also are cost

effective under the more stringent requirements of the total resource cost test

excluding non-energy benefits and utility cost test.”272

260. Under the DSM Regulation, BC Hydro’s long-run marginal cost of clean energy

delivered to the Lower Mainland (LRMC) is an input into the total resource cost test

(TRC). BC Hydro correctly used the most recent LRMC of $105/MWh in calculating

the TRCs of the portfolio and programs. BCSEA agrees that $105/MWh is an

outdated figure for BC Hydro’s LRMC. The next LRMC figure, to be determined in

the upcoming 2021 IRP, is expected to be considerably lower than $105/MWh.

261. At the request of the Commission, BC Hydro back-calculated a hypothetical

LRMC of $52/MWh that would produce TRCs of at least 1.0 for the portfolio and all

the programs of the DSM Expenditure Schedule for the Test Period.273 This

compares favourably to a range between $54/MWh and $80/MWh, which BC Hydro

recently estimated for the cost of new wind power delivered to the Lower

Mainland.274 This hypothetical analysis should allay any potential concern that BC

Hydro is proposing to spend too much on DSM.

262. BCSEA agrees that the traditional DSM Plan for F2020-F2022 would meet the

adequacy requirements of the DSM Regulation, if it was legally subject to those

requirements. The F2020-F2022 DSM Plan is designed to meet the adequacy

requirements, and the details are set out in Table 10-7 of the Application.275

263. The following paragraphs up to paragraph 270 address inter-year and inter-

program transfers of allocations within an accepted traditional DSM expenditure

schedule.

264. BC Hydro’s position is that it “retains discretion to reallocate its DSM costs during

the Test Period, and this ability is important for the company and customers.”276 BC

Hydro states:

“BC Hydro’s interpretation of the Utilities Commission Act is that BC Hydro is permitted to reallocate costs or resources between program areas and years without seeking prior BCUC approval.”277

272




Exhibit B-1, p.10-17, pdf p.1047. 276



265. BCSEA notes that the Commission Panel in the 2019 Decision regarding

FortisBC Inc.’s 2019-2022 DSM Plan and Expenditure Schedule states:

“For reasons set out immediately below, the Panel finds that in the absence of explicit approval from the BCUC, BCUC acceptance of FBC’s 2019–2022 DSM as set out in detail in Table 5.1 of the Application does not provide acceptance of any Inter-Year Transfers or Inter-Program Transfers. For greater clarity, this finding is not directed at fettering FBC’s ability to spend DSM funds as it sees fit. Rather, it provides clarity on what expenditures are included in the accepted expenditure schedule for the purpose of recovering those expenditures in rates.”278

266. BCSEA agrees with BC Hydro that it is important for BC Hydro to have the

flexibility to respond to challenges or opportunities in the market. As BC Hydro

states:

“For instance, if an initiative is over-performing or underperforming, then BC Hydro may need to reallocate funds to maintain the overall portfolio performance and portfolio balance. BC Hydro’s spending may also vary from plan due to factors that are fully or in part outside its control, such as the timing of large customer projects or slower than anticipated participation in a program due to economic conditions BC Hydro.”279

267. BCSEA also agrees with BC Hydro that appropriate checks and balances are in

place regarding reallocations made during the test period. These include BC Hydro’s

Financial Approval Authority Policy, and BC Hydro’s annual DSM reports to the

Commission. In addition, BC Hydro acknowledges that “a significant deviation from

the expenditure breakdown shown in the expenditure schedule could result in cost

recovery risk.”280

268. Regarding inter-year transfers, BCSEA’s view is that the exact timing of the

expenditure would not change whether the DSM Expenditure Schedule is still in the

public interest. Regarding both inter-year and inter-program transfers, BCSEA’s view

is that flexibility would reduce the risk of underspending, which has been a concern

of BCSEA in the past.

269. BCSEA supports BC Hydro’s legal position that it retains discretion to implement

inter-year and inter-program transfers within an accepted DSM Expenditure

277

Exhibit B-5, BCUC 1.174.1.1. 278

Decision and Order G-47-19, pp.12-13, bold in the original. 279

Exhibit B-5, BCUC 1.174.1.1, cited in BC Hydro Final Argument, para.550. 280



Schedule for the Test Period, without prior approval by the Commission but subject

to the usual reporting requirements and to cost recovery risk.

270. In the alternative, BCSEA supports Commission approval of flexible rules for

inter-year and inter-program spending transfers regarding BC Hydro’s traditional

DSM Expenditure Schedule for the Test Period. In this respect, consideration should

be given to the approach taken by the Commission in the Decision regarding

FortisBC Inc.’s 2019-2022 DSM Plan and Expenditure Schedule,281 in summary:

a. approval of inter-year transfers within the same program area subject to

reporting in the annual DSM report to the Commission, and

b. approval of transfers of up to 25% of budgeted expenditures from an existing

program area to another existing program area subject to reporting in the

annual DSM report to the Commission.

F. THE EXPENDITURE SCHEDULE EXCLUDES THERMO-MECHANICAL PULP EXPENDITURES

271. BC Hydro amended its proposed expenditure schedule to remove expenditures

on the Thermo-Mechanical Pulp Program, because it is no longer forecasting

expenditures on the TMP Program.

G. LOW CARBON ELECTRIFICATION EXPENDITURES, PRESCRIBED UNDERTAKINGS, COST RECOVERY IS MANDATED

272. This section addresses BC Hydro’s Low-Carbon Electrification expenditures on

undertakings defined in section 4 (3) (a), (b), (c) or (d) of the GGRR, referred to as

“LCE Project/Programs.” This is comprised of “Initial LCE Projects” and “LCE

Program.” BC Hydro’s position, with which BCSEA agrees, is that the “LCE

Project/Programs” are prescribed undertakings under section 4(3)(a) to (d) of the

GGRR and section 18 of the CEA (discussed further, below).

273. To be clear, “LCE Project/Programs” does not include LCE infrastructure

projects, such as the PRES project, that BC Hydro also says, and BCSEA agrees,

are exempt under the GGRR and CEA s.18 (paragraph 130, above).

281

Decision and Order G-47-19, pp.14-16.


a. One point of distinction is that “LCE infrastructure projects” are undertaken

under section 4(2) or section 4(3)(e) of the GGRR, whereas “LCE

Project/Programs” are undertaken under section 4(3)(a) to (d) of the GGRR.

b. Another point of distinction is that “LCE infrastructure projects” are brought

into the revenue requirement as capital expenditures, whereas “LCE

Project/Programs” are brought into the revenue requirement by being

recorded in the DSM Regulatory Account (discussed in paragraphs 280-287,

below.)

274. In BCSEA’s view, BC Hydro’s budget for low-carbon electrification is far too low.

BCSEA has assembled BC Hydro’s updated figures for LCE Projects/Program in the

table below.282

Expenditures for Initial LCE Projects and for LCE Program

$millions F2018 Actual

F2019 Actual

F2020 Forecast

F2021 Forecast

F2022 Forecast

F2023 Forecast

Total

Initial LCE Projects283

0.21 6.85 13.33 3.38 6.00 29.76

LCE Program284 0.48 4.49 4.36 3.13 4.20 16.66

Total LCE Projects/Program285

45.64

275. BC Hydro has set the following objectives for the LCE expenditures and activities

in the test period:

“Supporting the Government of B.C.’s climate change objectives by helping our customers to reduce their greenhouse gas emissions;

Assisting our customers in pursuing low carbon electrification opportunities that:

o Increase revenue from additional electricity consumption to reduce pressure on rates over the energy surplus period; and

o Reduce their greenhouse gas emissions;

282

This table does not show a test period (with shading), because there is no test period for the LCE Projects/Program expenditures as BC Hydro is not seeking approval of them. 283

Exhibit B-31, Panel 2.18.2, Attachment 1, Table 2-1, pdf p.196. 284

Exhibit B-31, Panel 2.18.2, Attachment 1, Table 3-2, pdf p.199. 285

Exhibit B-31, Panel 2.18.2, Attachment 1, Table 4-1, pdf p.202. The figure for LCE Projects/Program Total doesn’t equal the exact total of Initial LCE Projects Total and LCE Programs Total. Totals by fiscal year are not shown because they are not in the evidence.


Assessing customer response to our program offers and gaining experience with new technologies to help us understand potential barriers that customers and BC Hydro may face when developing and advancing low carbon electrification alternatives; and

Acting early to capture time-sensitive opportunities.”286

276. BCSEA commends BC Hydro for articulating these important objectives.

However, BCSEA is concerned that the proposed LCE budget for F2020-F2023 is

inadequate to achieve the necessary quantity of electrification.

277. BC Hydro says that it “expects to develop a future plan for low carbon

electrification that is informed by the learning gained through Initial LCE Projects and

the BC Hydro LCE Program as well as Government of B.C.’s CleanBC Plan.”287

BCSEA asked if BC Hydro has assessed the quantity of LCE that it might be called

on to undertake to help achieve the Province’s legislated GHG reduction targets

under the CleanBC plan. Unfortunately, BC Hydro demurred, responding:

“BC Hydro expects that BC Hydro’s role, including its undertakings of Low Carbon Electrification projects and programs, in achieving the reduction targets under the CleanBC plan will be explored through Phase Two of the Comprehensive Review.”288

278. BCSEA encourages BC Hydro to develop a comprehensive long-term plan for

low-carbon electrification measures across all sectors that will meet quantitative

GHG reduction objectives in order to achieve B.C.’s legislated GHG reduction

targets.

279. BCSEA supports BC Hydro’s LCE Projects/Program expenditures that reduce

GHG emissions in B.C. by displacing the use of energy derived from fossil-fuels.289 In

addition, the LCE Projects/Program expenditures are estimated to decrease

cumulative bills in the Test Period by approximately 0.1%.290

280. Regarding cost recovery, BCSEA agrees with BC Hydro’s premise as follows:

“Sections 18(1) to 18(3) of the Clean Energy Act state that the BCUC must set rates to allow BC Hydro to recover the costs of prescribed undertakings, and must not exercise any power that would prevent BC Hydro from carrying out prescribed undertakings. The effect of section 18

286


Exhibit B-1, p. 10-24, pdf p. 1054. 288


BCSEA notes that the impact on global GHG emissions due to the export of natural gas from B.C. is debatable and is beyond the scope of this Argument. 290

Exhibit B-31, Panel 2.18.3, pdf p.207.


of the Clean Energy Act is that the BCUC need only consider whether the LCE expenditures are prescribed undertakings as described in the GGRR. If the BCUC concludes that they are, then it must approve rates to allow BC Hydro to collect sufficient revenue to recover the costs of the prescribed undertakings.”291

281. BCSEA concurs with BC Hydro that there are two broad requirements for the

LCE expenditures to fall within the class of prescribed undertakings in sections

4(3)(a) to (d) of the GGRR:

“(a) The LCE expenditures must meet the descriptions in sections 4(3)(a), 4(3)(b), 4(3)(c), or 4(3)(d) of the GGRR; and

(b) At the time BC Hydro decided to undertake the LCE expenditures meeting the descriptions in sections 4(3)(a), 4(3)(b), BC Hydro must have reasonably expected the LCE expenditures to be cost effective as set out in section 4(4) of the GGRR.”292

282. Both of these requirements are met by the LCE Projects/Program expenditures,

in BCSEA’s view.

283. First, the Initial LCE Projects are in one or more class of undertakings defined in

subsections 4(3)(a) and 4(3)(c).293 And, the components of the LCE Program are in

the paragraphs of section 4(3)(a) to (d) of the GGRR set out in Table 3-1 of Appendix

Y.294

284. Second, the evidence is that the NPV of all of BC Hydro’s LCE expenditures

under sections 4(3)(a) and 4(3)(b) of the GGRR is $118.6 million,295 establishing that

these expenditures are cost-effective under the GGRR.296 It follows that when BC

Hydro decided to undertake these LCE expenditures it reasonably expected them to

be cost effective.

285. BCSEA agrees with BC Hydro as follows:

“The GGRR cost-effectiveness test does not require each individual component to be cost effective, nor does it require the BCUC to definitively determine whether the prescribed undertakings will in fact be

291



Exhibit B-31, Panel 2.18.2, Attachment 1, p.7, pdf p.193. 294

Exhibit B-1, Appendix Y, Table 3-1, p.10, pdf p. 2246. 295

Exhibit B-31, BCUC Panel 2.18.2, Attachment 1, LCE Program Updated in December 2019, p. 14, pdf p.200; and Exhibit B-5, BCUC 1.186.2, pdf p.2075, cited in BC Hydro Final Argument, para.563. 296

“Cost-effective” under the GGRR essentially means the NPV of the benefits (LCE sales revenues net of foregone export revenues) exceed the NPV of the LCE costs, both using a discount rate equal to BC Hydro’s weighted average cost of capital.


cost effective. Rather, the requirement is that BC Hydro must reasonably expect all of the undertakings in those two subsections on a cumulative basis to be cost-effective at the time BC Hydro decides to carry them out.”297

286. BCSEA also agrees with BC Hydro that it is not required to seek acceptance of

an expenditure schedule under section 44.2 for the LCE expenditures, even if some

or all of the LCE expenditures were also to qualify as a “demand-side measure.”298

287. In the Application, BC Hydro requests approval to defer its LCE Projects/Program

expenditures to the DSM Regulatory Account on the basis that they are prescribed

undertakings pursuant to section 18 of the CEA and section 4(3)(a) to (d) of the

GGRR. BCSEA understands this request to be a formality. The Direction to the

BCUC Respecting Undertaking Costs299 under the UCA says the Commission must

allow BC Hydro to defer to the DSM Regulatory Account amounts equal to BC

Hydro’s costs of implementing an undertaking within a class defined in section 4 (3)

(a), (b), (c) or (d) of the GGRR.

H. BC HYDRO MANAGEMENT OF TRADITIONAL DSM AND LCE INITIATIVES

288. In BCSEA’s view the evidence supports the conclusion that BC Hydro’s

management of traditional DSM and the LCE Projects/Program is appropriately

informed by the identification and assessment of delivery risks and the development

of mitigation measures at various stages of DSM implementation. Risks are

assessed and mitigated at the initiative level as well as at the portfolio level.300

289. BC Hydro submits an annual DSM Milestone Evaluation Summary Report to the

Commission.301 BC Hydro elaborated:

“BC Hydro typically conducts evaluations of all its DSM programs. The frequency varies depending on the program but typically ranges between three years and six years. On an exception basis, a decision may be made to not evaluate a program. Examples include a program that has been or will be discontinued, or if the cost of an evaluation would be disproportionate relative to program expenditures.”302

297



B.C. Reg. 77/2017. http://www.bclaws.ca/civix/document/id/complete/statreg/77_2017 300

Exhibit B-1, p.10-41, pdf p.1071. 301

Exhibit B-1, Appendix AA, pdf p. 2294. 302

Exhibit B-6, BCSEA 1.53.1, pdf p.825.

http://www.bclaws.ca/civix/document/id/complete/statreg/77_2017


290. Regarding evaluation, measurement and verification of the traditional DSM

portfolio, BCSEA is satisfied that BC Hydro’s policies and procedures are guided by

industry best practices and are neutral and unbiased.

291. BCSEA is satisfied that BC Hydro’s evaluation function is sufficiently independent

and represents an appropriate blend of internal and external resources, taking into

account costs and expertise.303 As BC Hydro notes, BC Hydro does not profit from

any over-estimation of DSM savings.

I. CONCLUSION AND REQUESTED FINDINGS

292. In BCSEA’s view, BC Hydro’s traditional DSM expenditure schedule is in the

public interest and BC Hydro’s LCE Projects/Programs expenditures are a

prescribed undertaking under section 18 of the CEA. BCSEA submits that the BCUC

should accept the proposed DSM Expenditure Schedule for the Test Period, and

approve deferral of the LCE Projects/Programs expenditures to the DSM Regulatory

Account.

PART TWELVE: IMPLEMENTATION OF RATES AND CONSIDERATION OF NEW INFORMATION

A. INTRODUCTION

293. BCSEA agrees with BC Hydro’s proposal to implement the Evidentiary Update by

making the interim F2020 rates permanent, and decreasing rates by 1.01% on April

1, 2020 (i.e., the beginning of F2021).304

B. BC HYDRO’S RATE IMPLEMENTATION PROPOSAL, INTERESTS OF BOTH CUSTOMERS AND THE COMPANY

294. BCSEA accepts the four principles that BC Hydro applied in weighing the rate

implementation options:

a. recovery of the revenue requirements in the Test Period (no more and no

less),

b. rate stability in the Test Period,

c. avoiding bill adjustments, and

303




d. avoiding the re-introduction of longer-term rate smoothing.305

295. BCSEA has reviewed the various rate implementation options and is satisfied

that the proposed option works the best in relation to the four criteria. In particular,

BCSEA would not support a rate implementation option that re-introduced longer-

term rate smoothing.

C. UPDATING EVIDENTIARY UPDATE INPUTS

296. BCSEA supports reliance on the financial data current to the Evidentiary Update.

In BCSEA’s view, the Evidentiary Update is a reasonable basis for setting rates in

the Test Period. A line has to be drawn somewhere. New financial data will never

stop emerging. BCSEA submits that the regulatory accounts are an appropriate way

to account for information that became available after the Evidentiary Update. The

proceeding will have been underway for 15 months by the time BC Hydro’s reply

argument is due on May 27, 2020. In BCSEA’s view it is time to bring this proceeding

to a conclusion.

297. Regarding COVID-19, BCSEA agrees that the BCUC can take judicial notice of

the fact that the COVID-19 pandemic is having ongoing detrimental economic effects

and is disrupting daily life in unprecedented ways. BCSEA joins BC Hydro in

acknowledging the hardships faced by customers due to the virus, including those

who have died, those who are in hospital or whose health has been impacted, and

those who are facing economic challenges and uncertainties.306

298. In case it needs to be said, BCSEA would oppose re-opening the evidentiary

record to consider the impacts of the COVID-19 pandemic on BC Hydro’s rates and

DSM expenditures during the Test Period. BCSEA agrees with BC Hydro that the

regulatory accounts “will mitigate much of the uncertainty caused by the pandemic by

capturing variances from forecast which can then be returned to or recovered from

customers in the next test period in accordance with existing BCUC orders.” In

BCSEA’s view, the appropriate approach is expressed by BC Hydro when it states,

“if any particular approval from the BCUC is required over the remainder of the Test

305




Period due to the pandemic, BC Hydro will bring forward requests to the BCUC in

separate applications as needed.”307

D. CONCLUSION AND REQUESTED FINDING

299. BCSEA submits that the Evidentiary Update remains a reasonable basis upon

which to base Test Period rates.

PART THIRTEEN: CONCLUSION AND ORDER SOUGHT

300. BCSEA supports Commission approval of the Draft Order set out in Appendix B

of the Evidentiary Update.308

ALL OF WHICH IS RESPECTFULLY SUBMITTED. May 4, 2020

____________________________ William J. Andrews Barrister & Solicitor Counsel for B.C. Sustainable Energy Association

307


Exhibit B-19, Appendix B, pdf p.102, as corrected by Exhibit B-11-2.

1\