Fred James Chief Regulatory Officer Phone: 604-623-4046 Fax: 604-623-4407 bchydroregulatorygroup@bchydro.com

March 19, 2019

Mr. Patrick Wruck Commission Secretary and Manager Regulatory Support British Columbia Utilities Commission Suite 410, 900 Howe Street Vancouver, BC V6Z 2N3

Dear Mr. Wruck:

RE: British Columbia Utilities Commission (BCUC or Commission) British Columbia Hydro and Power Authority (BC Hydro) Fiscal 2020 to Fiscal 2021 Revenue Requirements Application

BC Hydro writes to provide BC Hydro’s presentation from the workshop held on March 15, 2019.

For further information, please contact Chris Sandve at 604-974-4641 or by email at bchydroregulatorygroup@bchydro.com.

Yours sincerely,

Fred James Chief Regulatory Officer

df/rh

Enclosure

British Columbia Hydro and Power Authority, 333 Dunsmuir Street, Vancouver BC V6B 5R3 www.bchydro.com

B-2

Workshop (March 15, 2019)

BC Hydro

Fiscal 2020 – Fiscal 2021

Revenue Requirements

Application

1. Application Overview Chris O’Riley (20 minutes) President and Chief Operating Officer

2. Comprehensive Review David Wong and Approvals Sought Executive Vice President, Finance, Technology, Supply Chain (10 minutes)

3. Load Forecast Bill Clendinning

(15 minutes) Director, Energy Planning and Analytics

4. Cost of Energy Heather Matthews Rohan Soulsby (10 minutes) Director, Generation Sys. Ops. Director, Power Acq. / Contracts

5. Demand Side Management Steve Hobson (15 minutes) Director, Conservation and Energy Management

6. Break (15 Minutes)

7. Operating Costs Ryan Layton Carolynn Ryan (20 minutes) Chief Accounting Officer Chief Human Resources Officer

8. Capital Expenditures Ajay Kumar (20 minutes) Director, Line Asset Planning

9. Regulatory Accounts Ryan Layton (10 minutes) Chief Accounting Officer

Agenda

2

Application Overview

Chris O’Riley (President and Chief Operating Officer)

3

• We have been able to hold the growth in our base operating costs to

less than forecast inflation, resulting in a net bill increase of 1.76%1 on

April 1, 2019 and 0.72% on April 1, 2020.

• Phase One of the Comprehensive Review resulted in changes that have

enhanced the BCUC’s oversight of BC Hydro.

• Capital expenditures are required for a safe and reliable system.

• We have responded to the BCUC’s decision on our fiscal 2017 to Fiscal

2019 Revenue Requirements Application.

Note 1: The net bill increase of 1.76% on April 1, 2019 consists of a general rate increase of 6.85%

and a reduction of the Deferral Account Rate Rider from 5% to 0%.

Application Overview

4

Affordability for our customers is important to us

BC Hydro’s Revenue Requirement

5 Net Other includes Non-Base Operating Costs, Miscellaneous Revenue, Subsidiary Net Income, Inter-Segment Revenue, Other Utilities Revenue

Net Income $0.71B (13%)

Water Rentals $0.35B (7%)

1.42B (27%)

$1.06B (20%)

$0.79B (15%)

$0.66B (12%) Taxes $0.26B (5%)

$0.04B (1%)

Fiscal 2021 Revenue Requirement - Current View ($5.29 billion)

Taxes

Cost of Energy (includes IPPs)

Capital Amortization

Finance Charges

Base Operating Costs

Net Other

Contributions to Government

Many cost components are largely fixed

Oversight of BC Hydro Has Been Enhanced

6

Revenue Requirement

Proceeding

Government

Direction Outcome

Fiscal 2005 to Fiscal 2006 BCUC Decision (Order No. G-94-06)

Fiscal 2007 to Fiscal 2008 Negotiated Settlement Agreement (Order No. G-143-06)

Fiscal 2009 to Fiscal 2010 BCUC Decision (Order No. G-16-09)

Fiscal 2011 Negotiated Settlement Agreement (Order No. G-180-10)

Fiscal 2012 to Fiscal 2014 Direction 3 Rates set by Direction 3 (Order No. G-77-12A)

Fiscal 2015 to Fiscal 2016 Direction 6 Rates set by Direction 6 (Order No. G-48-14)

Fiscal 2017 to Fiscal 2019 Direction 7 BCUC Decision within rate caps set by Direction 7 (Order No. G-47-18)

BC Hydro is committed to an open and transparent process

Comprehensive Review

and Approvals Sought

David Wong (Executive Vice President, Finance, Technology, Supply Chain)

7

Comprehensive Review of BC Hydro

8

Key Outcomes of Comprehensive Review include:

• Enhanced regulatory oversight of BC Hydro

• New five-year rates forecast to keep rates affordable

Actions to Enhance BCUC Oversight:

• Repealed a number of regulations restricting BCUC decision

making

• BCUC to set BC Hydro’s allowed net income starting fiscal 2022

• BCUC determines regulatory accounts for BC Hydro going forward

• Expect legislation to enable BCUC to review and approve BC

Hydro’s Integrated Resource Plan (IRP)

Comprehensive Review of BC Hydro

9

BCUC determines BC Hydro’s rates going forward

• Actions to Keep Rates Affordable include:

• Writing off the $1.1 billion balance in the Rate Smoothing Regulatory Account – no longer required to be recovered from ratepayers

• Suspending the Standing Offer Program

• Reducing capital investments

• Annual base operating cost increases below forecast inflation

Comprehensive Review of BC Hydro

10

Bill increases total 2.5% over test period, 8.1% over 5 years

(40% lower than previous 10 Year Rates Plan)

• General rate increases of 6.85% for fiscal 2020 and 0.72% for fiscal 2021

• Reduce Deferral Account Rate Rider from 5% to 0% effective April 1, 2019

• Net impact of the above is a billable rate increase of 1.76% April 1, 2019 and 0.72% April 1, 2020

• No request for new regulatory accounts

• Six changes and close two regulatory accounts

• Depreciation Rates for certain asset classes

• Open Access Transmission Tariff Rates

• Demand Side Management expenditure schedule

• Re-consideration of three previous BCUC Directives

Approvals Sought

11

Bill Impact Drivers

12 12

2.5% bill increase over the test period driven by an end to rate

smoothing and continued capital investment

Load Forecast

Bill Clendinning (Director, Energy Planning and Analytics)

13

Responds to BCUC Decision on our Previous Application

• Reviewed and updated price elasticities from -0.05 to -0.10

• Considered an alternative forecast using FortisBC (electricity) method

Responds to BCUC Site C Inquiry Final Report

• Aligned LNG forecast methodology to be consistent with other large industrial customers

• Created a competitive process in which Conference Board of Canada was selected to provide us with provincial & regional economic forecasts

Responds to Internal Audit which included Independent Expert Review

• 14 audit recommendations accepted and now being implemented

Load Forecast Methodology Improvements

14

Improvements respond to recent BCUC reviews and internal audit

Total firm sales forecast

Slower growth across most sectors relative to previous forecast

15

0

10000

20000

30000

40000

50000

60000

70000

GW

h

Key changes from May 2016 forecast*

~3,800 GWh lower in F2023

~2,350 GWh lower in Liquefied Natural Gas

~1,070 GWh lower in commercial

~370 GWh lower to FortisBC

~390 GWh lower in residential

~260 GWh higher in light industrial

~190 GWh higher in large industrial

~70 GWh lower across all others

Actuals May 2016 Oct 2018

5-Yr Avg 0.4%

5-Yr Avg

2.0%

5-Yr Avg 0.5%

* Total Firm sales includes all main sectors, BC Hydro Own Use, streetlights, irrigation & other utility sales

0

2000

4000

6000

8000

10000

12000

14000

16000

18000

20000

Customer sector forecasts

The industrial sector drives load growth over the next five years

16

GW

h (a

fter a

djus

tmen

ts)

0

2000

4000

6000

8000

10000

12000

14000

16000

18000

20000

0

2000

4000

6000

8000

10000

12000

14000

16000

18000

20000Light Industrial / Commercial Residential Large Industrial

Actuals May 2016 Oct 2018

0.3% 5-Yr Avg 0.9%

5-Yr Avg 0.4%

Actuals May 2016 Oct 2018

0.7% 5-Yr Avg 0.9%

5-Yr Avg -0.1%

Actuals May 2016 Oct 2018

0.0% 5-Yr Avg 4.4%

5-Yr Avg 1.2%

0

50

100

150

200

250

300

350

400

GW

h (

Inc

rem

en

tal)

Emerging loads forecasts

Significant growth potential in these areas but large uncertainties

17

0

50

100

150

200

250

300

350

400Cannabis Cryptocurrencies

Oct 2018

GW

h (

Inc

rem

en

tal)

0

50

100

150

200

250

300

350

400

GW

h (

To

tal)

Electric Vehicles

Estimated Actuals May 2016

Oct 2018Oct 2018

Long-term risks are mixed, but electrification and natural gas have

significant upside potential

Forecast uncertainties

18

Downside Upside

The economy

The pulp & paper sub-sector

The mining sub-sector

Provincial clean growth strategy and the drive for electrification

Natural gas and upstream operations

Cryptocurrency and cannabis loads

Cost of Energy

Heather Matthews (Director, Generation System Operations)

Rohan Soulsby (Director, Power Acquisitions and Contract Mgmt.)

19

Optimizing Our Energy Supply

20

• Energy Studies process develops an optimal set of reservoir and

generation station operations and market transactions, considering:

• Water inflow

• Market prices

• Load

• 2019 internal audit with independent experts from SINTEF concluded:

• Well-established process is in place

• Key models are appropriate

• Methodologies are in-line with leading industry practices

Our Energy Studies process is endorsed by independent experts

and maximizes the value of all sources of energy supply

Improved Presentation of Cost of Energy

21

• Heritage Contract was repealed as a result of the Comprehensive Review.

This provides the flexibility to categorize costs of energy more clearly.

• 3 categories:

• Heritage Energy

• Non-Heritage Energy

• Market Energy

We’ve categorized our costs of energy more clearly in this

Application

Cost of Energy is Increasing Due to

Increases in IPP Costs

22

-500

0

500

1000

1500

2000

2500

Fiscal 2019RRA

Fiscal 2020Plan

Fiscal 2021Plan

Non-Heritage Energy(includes IPPs)

Heritage Energy

Market Energy

$ m

illio

n

Variances between planned and actual costs of energy are deferred to either the Heritage Deferral Account or the Non-Heritage Deferral

Account so that customers only pay the actual cost.

Existing EPAs Are Driving the Increase

In IPP Costs

23

Tota

l IP

P P

urc

hase C

osts

($m

illion

s)

SOP ($5.1)

New EPAs $4.2

EPA Renewals $1.3

Termination($17.3)

≈ ≈$1,5

00$1

,600

0

COST REDUCTIONS COST INCREASES

~~

F2019 RRA$1,547.9

F2021 Plan$1,634.3

Existing EPAs

$103.3

The net increase from the F2019 RRA to the F2021 Plan is approximately $86 million

which reflects both cost reductions and cost increases.

Demand Side

Management

Steve Hobson (Director, Conservation and Energy Management)

24

Traditional DSM expenditures remain at a similar level as the DSM Plan

presented in the Previous Application.

DSM Plan Continues Moderation Strategy

25

Expenditure ($ million)

New Incremental

Energy Savings (GWh/yr)

Fiscal 2020 Demand-Side Measures

90.8 700

Fiscal 2021 Demand-Side Measures

116.3 853

Provides broad access across all customer sectors

Net Levelized Costs ($/MWh)

Utility Cost Total Resource Cost Traditional DSM Portfolio $27 $14

Cost Effectiveness and Other Benefits of

Traditional DSM

26

Lower Revenue Requirements

GDP and Employment

Impacts

Greenhouse Gas

Reductions Customer non-energy benefits

DSM Plan is cost effective, reduces forecast revenue requirements

• A new Non-Integrated Areas program has been developed

• Energy Management activities within each sector have been re-categorized to align

with the DSM Regulation

• Improvements have been made to the presentation of Codes and Standards savings

to make it more understandable

Modifications to the DSM Plan

27

25

38

0

5

10

15

20

25

30

35

40

Previous Application Current Application

$ m

illio

n

Residential expenditures have increased by 50%

• BC Hydro has planned LCE expenditures of $28 million over the test period

• BC Hydro LCE expenditures are prescribed undertakings under the

Greenhouse Gas Reduction (Clean Energy) Regulation

Low Carbon Electrification (LCE)

28

Initial BC Hydro LCE Projects

Government EfficiencyBC Programs

BC Hydro LCE Program

Future activity

driven by

CleanBC Plan

Operating Costs

Ryan Layton (Chief Accounting Officer)

Carolynn Ryan (Chief Human Resources Officer)

29

Annual Base Operating Costs Are

Increasing By Less Than Forecast Inflation

30

$769 $778 $788

$-

$100

$200

$300

$400

$500

$600

$700

$800

$900

$1,000

F2019 F2020 F2021

$ M

illi

on

1.1%

Increase

1.3%

Increase

Uncontrollable Cost Pressures Partially

Offset by Reductions to Controllable Costs

31

$ Million

Benchmarking Demonstrates that BC

Hydro’s Operating Costs Are Reasonable

32

Internal Analysis Indicates that BC Hydro’s

Operating Costs Are Reasonable

33

Workforce Optimization and Accenture

Repatriation Have Generated Cost Savings

While Increasing FTEs

34

18.5

8.2

02468

101214161820

WorkforceOptimization

AccentureRepatriation

Annual Net Savings

6195 6365

170 536 423

0

1000

2000

3000

4000

5000

6000

7000

8000

F2019RRA

F2020Plan

Other*

AccentureRepatriation

WorkforceOptimization

FTE Continuity

* Primarily additions related to the Site C Project, partially offset by reduction to trainees/apprentices

$ m

illio

n

Total: 6365

Total: 7477

Apart From Growth Due to Capital

Investment, FTEs Have Been Flat Since

Fiscal 2012 and Will Remain Flat

35

The above figure shows FTEs by work function (operating, capital or deferred), excluding FTEs related to Accenture Repatriation, the Smart Metering Infrastructure Project and the Site C Project. These FTEs were removed to avoid skewing the trend line. All FTEs related to the Workforce Optimization Program are included.

• 2017 Morneau Shepell assessment concluded that our total rewards offer,

including the value of pension, benefit and time off programs was 2%

below median market rates.

• While the total value is comparable our mix is different. We have lower

salaries and incentive pay, and a higher value on pension, benefits and

time off.

• Salary increases for union employees are determined by the bargaining

mandate set by the Public Sector Employers Council (PSEC).

• Salary increases for management and professional employees

have been limited since 2012 due to previous PSEC salary freeze policy.

Our Total Rewards Package is

Consistent with Market Rates

36

Total rewards review conducted in 2017 by Morneau Shepell

Capital Expenditures

Ajay Kumar (Director, Line Asset Planning)

37

Enterprise Capital Planning Process

38

This process facilitates a common approach to capital planning,

prioritizing, and governance across BC Hydro.

High Level of System Performance

39

SAIDI (All Events, Not Normalized)

SAIFI (All Events, Not Normalized)

BC Hydro’s customers have experienced a consistent high level of

system performance.

Moderated Level of Capital Investment

40

$5,471 $5,113

$2,200 $1,576

$-

$1,000

$2,000

$3,000

$4,000

$5,000

$6,000

Previous Plan (F20-F24) Current Plan (F20-F24)

Cap

ad

ds (

$M

)

F20-F24 Growth vs Sustain*

Sustain Growth

BC Hydro is investing in safe and reliable electricity service while

keeping rates increases as low as possible.

*Note: Does not include Site C or Waneta.

41

F2020 – F2021 Capital Investment

BC Hydro’s Capital Plan mitigates highest system risks and addresses

prioritized system needs.

$0

$200

$400

$600

$800

$1,000

$1,200

$1,400

$1,600

F20 F21

Ca

pa

dd

s (

$M

)

F2020 - F2021 Capital Additions*

$0

$200

$400

$600

$800

$1,000

$1,200

$1,400

$1,600

F20 F21

Ca

pe

x (

$M

)

F2020 - F2021 Capital Expenditures*

T&D

Generation

Technology

Properties

Fleet

Business Support

*Note: Does not include Site C.

Capital Investment Planning and Delivery

42

BC Hydro has well established capital planning, project and program

delivery practices.

• Independent reviews have validated BC Hydro’s approach to planning and

delivering capital projects.

• From fiscal 2014 to fiscal 2018, BC Hydro delivered 493 projects within

0.40 per cent of the original approved expected cost.

• The Application demonstrates that BC Hydro’s performance of actual costs

versus the original approved costs is strong.

Regulatory Accounts

Ryan Layton (Chief Accounting Officer)

43

• Refund net credit in Energy Deferral Accounts during test period

• Defer variances to Plan for IFRS Lease Standard implementation and the

Biomass Energy Program to the Non-Heritage Deferral Account

• Continue to defer variances between forecast and actual dismantling costs

• Defer low carbon electrification expenditures to the DSM Regulatory Account

• Remove reference to “Prescribed Standards” from Site C Regulatory Account

• Close the Capital Project Investigation Costs and Rate Smoothing regulatory

accounts

Regulatory Account Approvals Sought

44

No new accounts, changes to six accounts, close two accounts

Net Regulatory Account Balance

45

• Write-off of Rate Smoothing Regulatory Account

• IFRS revenue standard

• Continued amortization of almost all accounts in rates

• Higher than planned Powerex trade income

Balanced expected to decline by almost 45% by fiscal 2024

Forecast Fiscal 2024 Balance Primarily

in Long-Term Accounts

46

Regulatory Account Forecast Fiscal 2024 Balance ($M)

IFRS Property, Plant and Equipment 976

Demand Side Management 871

Site C 556

First Nations Provisions 428

IFRS Pension 306

All Other Accounts (Net) 62

Total 3,199

Number of Regulatory Accounts is

Declining

47

Regulatory Account Status

Rate Smoothing To be closed in fiscal 2020

Capital Project Investigation Costs To be closed in fiscal 2021

Arrow Water Systems Will propose closure in fiscal 2022

Arrow Water Systems Provision Will propose closure in fiscal 2022

Rock Bay Remediation To be closed in fiscal 2023

Real Property Sales May be closed by fiscal 2024

Customer Crisis Fund May be closed by fiscal 2024

Mining Customer Payment Plan May be closed by fiscal 2024

Up to 8 accounts to be closed by fiscal 2024

Regulatory Schedule

Fred James (Chief Regulatory Officer)

48

Regulatory Schedule

49

Action Date (2019)

Intervener Registration Thursday, March 21

BCUC Information Request (IR) No. 1 to BC Hydro

Tuesday, April 23

Intervener IR No. 1 to BC Hydro Thursday, May 2

BC Hydro responses to BCUC and Intervener IRs No. 1

Thursday, June 6

Procedural Conference Monday, June 24

Workshop (March 15, 2019)

BC Hydro

Fiscal 2020 – Fiscal 2021

Revenue Requirements

Application