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Volume 57, No. 4

29/2014

The British Columbia Gazette,

Part II

March 11, 2014

B.C. Reg. 29/2014 , deposited March 6, 2014, under the UTILITIES COMMISSION ACT [section 3]. Order in Council 96/2014, approved and ordered March 5, 2014.

On the recommendation of the undersigned, the Lieutenant Governor, by and with the advice and consent of the Executive Council, orders that the attached Direction No. 6 to the British Columbia Utilities Commission is made.

— B. BENNETT, Minister of Energy and Mines and Minister Responsible for Core Review ; T. WAT, Presiding Member of the Executive Council .

DIRECTION NO. 6 TO THE BRITISH COLUMBIA UTILITIES COMMISSION

Contents

Definitions

Application

Orders

Appendix A

Appendix B

Appendix C

Definitions

1 In this direction:

“Act” means the Utilities Commission Act ;

“amortization of capital additions” means the portion of the authority’s annual amortization expense that is subject to the amortization of capital additions regulatory account;

“amortization of capital additions regulatory account” means the regulatory account established under commission order G-16-09 and the direction in

section 5.5.7 of the reasons that accompany that order;

“arrow water divestiture costs regulatory account” means the regulatory account established under paragraph 1 of commission order G-90-11;

“arrow water provision regulatory account” means the regulatory account established under paragraph 2 of commission order G-90-11;

“asbestos remediation costs” has the same meaning as in Direction No. 7 to the British Columbia Utilities Commission;

“asbestos remediation regulatory account” has the same meaning as in Direction No. 7 to the British Columbia Utilities Commission;

“deemed equity” has the same meaning as in Direction No. 7 to the British Columbia Utilities Commission;

“electric tariff rates” means the rates in the schedules to the authority’s electric tariff;

“F2014” has the same meaning as in Direction No. 7 to the British Columbia Utilities Commission;

“F2015” has the same meaning as in Direction No. 7 to the British Columbia Utilities Commission;

“F2016” has the same meaning as in Direction No. 7 to the British Columbia Utilities Commission;

“first nations costs regulatory account” means the regulatory account established under commission order G-53-02;

“heritage payment obligation” has the same meaning as in Direction No. 7 to the British Columbia Utilities Commission;

“home purchase option plan regulatory account” means the regulatory account established under commission order G-55-09;

“IFRS pension regulatory account” means the regulatory account established under paragraph 1 (xxii) of commission order G-77-12A;

“IFRS PP&E regulatory account” means the regulatory account established under paragraph 1 (xxi) of commission order G-77-12A;

“non-current pension costs” has the same meaning as in Direction No. 7 to the British Columbia Utilities Commission;

“non-current pension costs regulatory account” has the same meaning as in Direction No. 7 to the British Columbia Utilities Commission;

“non-heritage cost of energy subject to deferral” means the portion of the authority’s annual cost of energy that is subject to the non-heritage deferral account;

“non-heritage deferral account” has the same meaning as in Direction No. 7 to the British Columbia Utilities Commission;

“OATT rates” means the rates in schedules 00, 01 and 03 to the authority’s open access transmission tariff;

“rate smoothing regulatory account” has the same meaning as in Direction No. 7 to the British Columbia Utilities Commission;

“real property gain/loss” means the net gain or net loss in a fiscal year incurred by the authority from the sale of its real property;

“related equipment” means the related equipment described in

section 3 (

b) of the Smart Meters and Smart Grid Regulation;

“Rock Bay costs” has the same meaning as in Direction No. 7 to the British Columbia Utilities Commission;

“Rock Bay remediation regulatory account” has the same meaning as in Direction No. 7 to the British Columbia Utilities Commission;

“Site C regulatory account” means the regulatory account established under commission order G-143-06 and

section 25 of Appendix A attached to that order;

“smart meter” has the same meaning as in

section 17 of the Clean Energy Act ;

“smart metering and infrastructure program” means the authority’s program to install and operate smart meters and related equipment and the program referred to in

section 17 (4) of the Clean Energy Act ;

“SMI regulatory account” has the same meaning as in Direction No. 7 to the British Columbia Utilities Commission;

“storm restoration costs” means the costs that are subject to the storm restoration regulatory account;

“storm restoration regulatory account” means the regulatory account established under commission order G-16-09 and the direction in

section 5.5.4 of the reasons that accompany that order;

“total finance charges” means the portion of the authority’s annual finance charges that is subject to the total finance charges regulatory account;

“total finance charges regulatory account” means the regulatory account established under commission order G-16-09 and the direction in

section 5.5.2 of the reasons that accompany that order;

“total rate revenue” means the portion of the authority’s annual revenues that is subject to the non-heritage deferral account;

“trade income” has the same meaning as in Direction No. 7 to the British Columbia Utilities Commission.

Application

2 This direction is issued to the commission under

section 3 of the Act.

Orders

3 Within 20 days of the date on which the authority files an application with the commission to request final orders in regard to the authority’s F2014, F2015 and F2016 rates, the commission must issue final orders as follows:

(

a) the commission must accept the

schedule of expenditures in regard to demand-side measures for F2014, F2015 and F2016 as set out in Appendix A to this direction;

(

b) the commission must confirm the authority’s rates for F2014, set by commission order G-77-12A, as final and no longer subject to refund;

(

c) the commission must set the electric tariff rates for F2015 and F2016 as set out in Appendix B to this direction;

(

d) the commission must set the OATT rates for F2015 and F2016 as set out in Appendix C to this direction;

(

e) the commission must approve the following forecasts and planned expenditures for F2015:

(

i) heritage payment obligation: $353.2 million;

(ii) non-heritage cost of energy subject to deferral: $1 074.3 million;

(iii) total rate revenue: $4 168.3 million;

(iv) trade income: $110.0 million;

(

v) non-current pension costs: $2.9 million;

(vi) storm restoration costs: $3.9 million;

(vii) total finance charges: $602.6 million;

(viii) amortization of capital additions: $34.7 million;

(ix) real property gain/loss: $10.0 million;

(

x) asbestos remediation costs: $1.8 million;

(

f) the commission must approve the following forecasts and planned expenditures for F2016:

(

i) heritage payment obligation: $399.2 million;

(ii) non-heritage cost of energy subject to deferral: $1 032.2 million;

(iii) total rate revenue: $4 459.7 million;

(iv) trade income: $110.0 million;

(

v) non-current pension costs: $0.1 million;

(vi) storm restoration costs: $3.9 million;

(vii) total finance charges: $725.2 million;

(viii) amortization of capital additions: $106.7 million;

(ix) real property gain/loss: $10.0 million;

(

x) asbestos remediation costs: $0.9 million;

(

g) the commission must order, in regard to the first nations costs regulatory account, that the authority amortize from that account $43.5 million and $43.3 million in F2015 and F2016, respectively;

(

h) the commission must order, in regard to the Site C regulatory account, that the authority defer to that account operating costs it incurs in regard to the Site C project in F2015 and F2016;

(

i) the commission must order, in regard to the storm restoration regulatory account, that the authority amortize from that account $1.4 million in each of F2015 and F2016;

(

j) the commission must order, in regard to the amortization of capital additions regulatory account, that the authority amortize from that account $9.8 million and $9.4 million in F2015 and F2016, respectively;

(

k) the commission must order, in regard to the total finance charges regulatory account, that the authority amortize from that account $25.5 million in each of F2015 and F2016;

(

l) the commission must order, in regard to the SMI regulatory account, that

(

i) the authority amortize from that account $30.5 million and $31.3 million in F2015 and F2016, respectively, and

(ii) the authority defer to that account net operating costs incurred in F2015 and F2016 arising from the smart metering and infrastructure program and net operating costs arising from commission order G-166-13;

(

m) the commission must order, in regard to the home purchase option plan regulatory account, that the authority amortize from that account $11.8 million and $11.3 million in F2015 and F2016, respectively;

(

n) the commission must order, in regard to the non-current pension costs regulatory account, that the authority amortize from that account $32.6 million and $15.5 million in F2015 and F2016, respectively;

(

o) the commission must order, in regard to the Rock Bay remediation regulatory account, that the authority amortize from that account $51.5 million and $50.5 million in F2015 and F2016, respectively;

(

p) the commission must order, in regard to the IFRS PP&E regulatory account, that

(

i) the authority amortize from that account $15.9 million and $19.8 million in F2015 and F2016, respectively, and

(ii) the authority defer to that account $156.8 million and $134.4 million in F2015 and F2016, respectively;

(

q) the commission must order, in regard to the IFRS pension regulatory account, that the authority amortize from that account $38.2 million in each of F2015 and F2016;

(

r) the commission must order, in regard to the arrow water divestiture costs regulatory account, that the authority amortize from that account $4.7 million and $4.5 million in F2015 and F2016, respectively;

(

s) the commission must order, in regard to the arrow water provision regulatory account, that the authority amortize from that account $0.3 million in each of F2015 and F2016;

(

t) the commission must order, in regard to the asbestos remediation regulatory account, that the authority amortize from that account $12.1 million and $10.7 million in F2015 and F2016, respectively;

(

u) the commission must order, in regard to the rate smoothing regulatory account, that the authority defer to that account $166.2 million and $121.2 million in F2015 and F2016, respectively;

(

v) the commission must, despite

section 5 of Direction No. 3 to the British Columbia Utilities Commission, direct the authority to defer to the non-heritage deferral account the amount that is determined by subtracting the amount in subparagraph (ii) from the amount in subparagraph (i)

(

i) the forecast return on deemed equity in F2014 calculated on the basis of an annual rate of return on deemed equity in that year of 11.84%, and

(ii) the forecast return on deemed equity in F2014 calculated on the basis of an annual rate of return on deemed equity in that year that is greater than or less than 11.84% as a result of the commission’s order arising from the generic cost of capital proceeding initiated by commission order G-20-12.

Appendix A

F2014 – F2016 DSM Expenditure

Schedule

$ MILLION

F2014

F2015

F2016

Codes and Standards

2.4

4.0

4.2

Rate Structures

6.5

2.0

1.7

Programs

Residential

30.4

17.7

18.9

Commercial

66.4

39.5

40.0

Industrial

101.9

64.3

42.9

Total Programs

198.7

121.5

101.8

Supporting Initiatives

28.7

20.6

20.3

Total Energy Efficiency Portfolio

236.3

148.0

128.0

Capacity Focused DSM

0.0

2.4

3.1

Total

236.3

150.5

131.1

Appendix B

Electric Tariff Rates – F2015 and F2016

Rate Class

Rate

Schedule

Rate

F2015

F2016

Residential

1101/1121

Basic Charge($/day)

0.1664

0.1764

Step 1 energy rate ($/kWh)

0.0752

0.0797

Step 2 energy rate ($/kWh)

0.1127

0.1195

Residential

1105 (closed)

Energy rate ($/kWh)

0.0492

0.0522

Energy rate during period of interruption ($/kWh)

0.2865

0.3037

Residential Zone II

1107/1127

Basic Charge ($/day)

0.1775

0.1882

Step 1 energy rate ($/kWh)

0.0901

0.0955

Step 2 energy rate ($/kWh)

0.1548

0.1641

Residential

1148 (closed)

Basic Charge($/day)

0.1775

0.1882

Energy rate ($/kWh)

0.0901

0.0955

Residential

1151/1161

Basic Charge ($/day)

0.1775

0.1882

Energy rate ($/kWh)

0.0901

0.0955

Exempt General Service

1200/1201/ 1210/1211

Basic Charge ($/day)

0.2129

0.2257

Demand rate – Step 1 ($/kW)

Demand rate – Step 2 ($/kW)

5.19

5.50

Demand rate – Step 3 ($/kW)

9.95

10.55

Energy Rate – Tier 1 ($/kWh)

0.1012

0.1073

Energy Rate – Tier 2 ($/kWh)

0.0486

0.0515

General Service

1205/1206/ 1207

Energy rate – Tier 1 ($/kWh)

0.0492

0.0522

Energy rate – Tier 2 ($/kWh)

0.0323

0.0342

Energy rate during period of interruption ($/kWh)

0.2865

0.3037

Small General Service Zone II

Basic Charge ($/day)

0.2129

0.2257

Energy rate – Tier 1 ($/kWh)

0.1012

0.1073

Energy rate – Tier 2 ($/kWh)

0.1686

0.1787

Distribution Service

Monthly Minimum energy charge ($/month)

39.03

41.37

Distribution Service

Energy charge ($/kWh)

0.00157

0.00166

Power Service

1278 (Closed)

$/kVA

2.526

2.678

Energy charge ($/kWh)

0.06604

0.07

Monthly minimum greater of $/kVA or ($)

4.93 9868.64

5.23 10460.76

Large General Service Zone II

1255/1256/ 1265/1266

Basic Charge ($/day)

0.2129

0.2257

Energy charge – Tier 1 ($/kWh)

0.1012

0.1073

Energy charge – Tier 2 ($/kWh)

0.1686

0.1787

Net Metering Service

Energy rate ($/kWh)

0.0999

0.0999

Small General Service

1300/1301/ 1310/1311

Basic Charge ($/day)

0.2129

0.2257

Energy Charge ($/kWh)

0.1012

0.1073

Irrigation

1401/1402

Irrigation season energy rate ($/kWh)

0.0487

0.0516

Non-irrigation season energy charge – Tier 1 ($/kWh)

0.0487

0.0516

Non-irrigation season energy rate Tier 2 ($/kWh)

0.3864

0.4096

Minimum charge irrigation season ($/kW)

4.87

5.16

Non-irrigation season if consumption >500 kWh ($per kW)

38.98

41.32

Medium General Service

1500/1501/ 1510/1511

Basic Charge ($/day)

0.2129

0.2257

Demand rate – Step 1 ($/kW)

0.00

0.00

Demand rate – Step 2 ($/kW)

5.19

5.50

Demand rate – Step 3 ($/kW)

9.95

10.55

Part 1 Energy Rate – Tier 1 ($/kWh)

0.0934

0.0989

Part 1 Energy Rate – Tier 2 ($/kWh)

0.0651

0.0690

Part 2 Energy Rate ($/kWh)

0.0971

0.0990

Minimum Energy Rate ($/kWh)

0.0311

0.0330

Large General Service

1600/1601/ 1610/1611

Basic Charge ($/day)

0.2129

0.2257

Demand rate – Step 1 ($/kW)

0.00

0.00

Demand rate – Step 2 ($/kW)

5.19

5.50

Demand rate – Step 3 ($/kW)

9.95

10.55

Part 1 Energy Rate Tier 1 ($/kWh)

0.1010

0.1066

Part 1 Energy Rate– Tier 2 ($/kWh)

0.0486

0.0513

Part 2 Energy Rate ($/kWh)

0.0971

0.0990

Minimum Energy Charge ($/kWh)

0.0311

0.0330

Large General Service (150kW and over) for Distribution Utilities

2600/2601/ 2610/2611

Basic Charge ($/day)

0.2129

0.2257

Demand rate – Step 1 ($/kW)

0.00

0.00

Demand rate – Step 2 ($/kW)

5.19

5.50

Demand rate – Step 3 ($/kW)

9.95

10.55

Part 2 Energy Rate $/kWh (RS1600)

0.0971

0.0990

Embedded Cost Rate $/kWh

0.0501

0.0531

Discount ($/kWh)

-0.0037

-0.0039

Street Lighting

100 SV fixture rate ($/month)

15.61

16.55

150 SV fixture rate ($/month)

18.61

19.73

200 SV fixture rate ($month)

21.49

22.78

175 MV fixture rate ($/month)

17.15

18.18

250 MV fixture rate ($/month)

19.76

20.95

400 MV fixture rate ($/month)

25.48

27.01

Street Lighting

Each Unmetered Fixture ($/watt per month)

0.03

0.0318

Each Metered Fixture ($/kWh)

0.0901

0.0955

Street Lighting

Energy rate ($/watt per month)

0.03

0.0318

Contact rate ($/contact per month)

0.9057

0.96

Street Lighting

Energy rate ($/kWh)

0.0901

0.0955

Street Lighting

1755 (closed)

1. Pole owned by Customer

175 MV or 100SV fixture charge ($ per month)

14.63

15.51

400 MV or 150SV fixture charge ($ per month)

25.22

26.73

2. Pole on public property

175 MV or 100SV fixture charge ($ per month)

15.54

16.47

400 MV or 150SV fixture charge ($ per month)

26.13

27.70

3. Pole paid by BC Hydro

175 MV or 100SV fixture charge ($ per month)

19.13

20.28

400 MV or 150SV fixture charge ($ per month)

30.11

31.92

Transmission Service

Demand rate ($/kVA)

6.925

7.341

Energy rate A ($/kWh)

0.04059

0.04303

Energy rate B Tier 1 ($/kWh)

0.03619

0.03836

Energy rate B Tier 2 ($/kWh)

0.08022

0.08503

Minimum demand ($/kVA)

6.925

7.341

Transmission Service

Demand rate ($/kVA)

6.925

7.341

Winter HLH energy rate (below 90%) ($/kWh)

0.03619

0.03836

Winter HLH energy rate (above 90%) ($/kWh)

0.08952

0.09489

Winter LLH energy rate (below 90%) ($/kWh)

0.03619

0.03836

Winter LLH energy rate (above 90%) ($/kWh)

0.08113

0.08600

Spring energy rate (below 90%) ($/kWh)

0.03619

0.03836

Spring energy rate (above 90%) ($/kWh)

0.07226

0.07660

Remaining energy rate (below 90%) ($/kWh)

0.03619

0.03836

Remaining energy rate (above 90%) ($/kWh)

0.07923

0.08398

Transmission Service

Demand rate ($/kVA)

6.925

7.341

Energy rate ($/kWh)

0.04059

0.04303

Minimum demand ($/kVA)

6.925

7.341

Transmission Service

Excess demand rate ($/kVA)

6.925

7.341

Transmission Service

Minimum Monthly Charge ($/month)

39.03

41.37

Transmission Service

Administrative Charge per Period of Use ($)

150.00

150.00

Energy charge ($/kWh)

0.08022

0.08503

Transmission Service FortisBC

Demand Charge ($/kW)

6.925

7.341

Energy rate ($/kWh)

4.059

4.303

Appendix C

BC Hydro OATT Rates – F2015 and F2016

Service

Rate

Schedule in Authority’s Open Access Transmission Tariff

F2015 Rate

F2016 Rate

Network Integration Transmission Service

$52.1 million/month

$62.1 million/month

Long-term Firm Point to Point Transmission Service

$53 698/MW/year

$64 968/MW/year

Monthly Short-term Firm and Non-firm Point to Point Transmission Service

$4 474.87/MW/month

$5 413.99/MW/month

Weekly Short-term Firm and Non-firm Point to Point Transmission Service

$1 032.66/MW/week

$1 249.38/MW/week

Daily Short-term Firm and Non-firm Point to Point Transmission Service

$147.12/MW/day

$177.99/MW/day

Hourly Short-term Firm and Non-firm Point to Point Transmission Service

$6.13/MW/hour

$7.42/MW/hour

Scheduling, System Control, and Dispatch Service Fee

$0.102/MWh

$0.099/MWh

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