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Annual Report2016/2017

British ColumbiaUtilities Commission

VisionTo be a trusted and respected regulator that

contributes to the well-being and long-term

interests of British Columbians.

MissionThe Commission's mission is to ensure

that ratepayers receive safe, reliable, and

nondiscriminatory energy services at fair

rates from the utilities it regulates, and that

shareholders of those utilities are afforded a

reasonable opportunity to earn a fair return on

their invested capital.

Value StatementsAccessibility We facilitate fair, transparent and inclusive

processes that encourage well represented

input from relevant stakeholders who possess

the information required to present their

views effectively.

Integrity

We lead in a straight forward and

consistent manner, by making objective and

well-reasoned decisions and by treating

stakeholders with dignity and respect.

Responsiveness We deliver efficient regulation, aligned with

all relevant legislation and regulations and

government policies, that takes into account

the business needs of regulated entities and

the public interest.

Innovation

We continually strive to develop new

efficiencies and innovative solutions in our

internal operations and regulatory processes.

Excellence

We promote excellence by expecting high

standards of performance and conduct

by regulated entities and by encouraging

professional development and excellence in

our staff and commissioners.

British Columbia Utilities Commission

2016/2017 ContentsOrganizational Overview

Operational Highlights

Responding to Customers

Report on Performance

Recoveries and Expenses

Summary of Decisions, Reasons for Decisions and Negotiated Settlements

Summary of Commission Orders

Energy Costs

Directions

Regulated Entities, Licensed Gas Marketers, Mandatory Reliability Standards Registrants

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Annual Report | 2016/2017

It is no small feat to outline a year’s worth

of activities of the BC Utilities Commission

(BCUC), in particular this past year. This report

reflects the hard work and many achievements

of our staff and Commissioners, as well as the

many people who contributed in some way to

the initiatives and matters before the BCUC.

A key objective of the BCUC’s 2016-19

Business Plan was to take steps to increase

organizational efficiency. Over the course of

this past year, we took great strides towards

achieving this objective. As is outlined in

more detail within this report, we undertook

significant efforts to consult with and empower

employees to work in a more collaborative and

efficient way, and addressed the structural

and workflow obstacles that impede overall

efficiency. This process took over a year and

resulted in some significant changes to the

structure and systems of the BCUC.

We have worked hard this past year to improve

communication, both internally and externally.

Our Business Plan laid out three strategic goals:

improving efficiency, strengthening internal

communications and engaging stakeholders. We

have many achievements to celebrate and are

continuing to work hard on these goals with a

number of ongoing projects.

Internally, we continue to work together to

implement the findings of consultations

and workflow analyses. We closed the year

near completion of a new visual identity

for the BCUC, one that strengthens our

independence and public identity. Finally, as

an immediate initial step towards engaging

stakeholders, we are working to improve

our inward- and outward-facing technology,

developing an IT strategic plan for the first

time in the BCUC’s history. These projects

have been significant activities that are

carrying over into the next reporting year, and

ones that will show great payoff.

In our continued effort to strengthen the

BCUC’s contributions and leadership in the

energy and regulatory fields, we are proud to

have had opportunities this year to engage with

other Boards and agencies on a national and

international scale. We dedicated resources

to hosting the annual CAMPUT conference

– a gathering of hundreds of regulators and

stakeholders, including consumers and others

involved in Canada’s utility industry – where

people can participate in meaningful dialogue

on a range of matters of mutual interest. BCUC

members coordinated topics and experts in

the fields of future energy systems, pipeline

infrastructure, public engagement, and First

Nations consultation and accommodation. The

hard work of many volunteers supported a very

successful event.

Message from the Chair

01


Another crucial initiative was our work with the

Western Electricity Coordinating Council to

bring Mexico into the North American electric

grid. The interconnected nature of our systems

requires mutual commitment to reliable and

secure cooperation across large jurisdictions.

The BCUC has overseen the implementation of

Mandatory Reliability Standards in B.C. for a

number of years, and we are proud of our role in

bringing Mexico on board to improve the security

of the transmission grid.

It must be said that our employees and

members have contributed significantly to the

initiatives outlined above, while continuing to

undertake their important day-to-day work.

This report shows that we faced challenging

and complex work with performance results to

be proud of. Our staff and Commissioners are

highly engaged and committed to the excellent

work they do, even as the regulatory regimes

and energy environment evolve at a rapid pace.

In closing, I would like to extend my gratitude

to all those who made this year a success. It is

with pleasure that I submit this report to the

Lieutenant Governor in Council in accordance

with the Utilities Commission Act and the

Budget Transparency and Accountability Act.

David Morton, Chair/CEO


02

Organizational Overview

Serving the public interest through fair, evidence-based and inclusive processes.

03


About Us The British Columbia Utilities Commission (BCUC) is an independent, non-partisan

agency of the Government of British Columbia that is responsible for regulating B.C.’s

energy utilities, the Insurance Corporation of B.C.’s compulsory automobile insurance

rates, intra-provincial pipelines and the reliability of the electrical transmission grid. We

work hard to ensure British Columbians get value from their utilities, with safe, reliable

energy services, and fair energy and basic auto insurance rates, while providing utilities

with the opportunity to earn a fair return on their capital investments.

The BCUC is governed by the Utilities Commission Act and has specific responsibilities

under the Administrative Tribunals Act and the Freedom of Information and Protection

of Privacy Act. We also consider all relevant legislation and regulations, as well as

government policies and the business environment of regulated companies.

As a quasi-judicial entity, we make legally binding decisions. We take our responsibilities to

the public and to the companies we regulate seriously, and we work to maintain processes

that are fair, transparent and inclusive. The BCUC values input from British Columbians,

and we are committed to issuing well-reasoned, evidence-based decisions.

The BCUC• regulates public utilities within its

jurisdiction and in accordance with

relevant legislation;

• ensures ICBC’s basic insurance rates

are set in an adequate, efficient, just

and reasonable manner;

• adopts mandatory reliability

standards based on the public

interest, and supervises compliance

by utilities with these standards;

• reviews questions and complaints

about the actions of regulated

utilities and ICBC, and adjudicates

gas marketing disputes;

• establishes tolls and conditions of

service for intra-provincial pipelines

and common gas processors;

• reviews energy and automobile

basic insurance matters referred to

it by the Government of B.C.;

• encourages participation in public

processes; and

• ensures stakeholders have the

information they need to participate

effectively by making all relevant

materials publicly available.



04

The BCUC believes that our employees are vital

to the success of our organization. Our goal is

to ensure that their knowledge and experiences

are used effectively, and that we support our

employees in their career development.

An organizational effectiveness assessment

was initiated by the Chair and CEO in spring

2016. Staff and Commissioner interviews

were conducted to assess the current

organizational structure and how it impacts

internal cooperation and coordination. In the

resulting report, key gaps were identified

around integration, role clarity, workload,

development and support, and trust. A series

of recommendations were proposed, with three

primary areas of focus:

1. enhanced leadership;

2. structure reorganization; and

3. staff training and development.

The assessment also showed that the BCUC

must further optimize its structure to better

respond to the nature of our work. To ensure

we meet our commitments to improving

effectiveness and maintaining public trust, the

following areas were examined:

• staffing and workload levels;

• collaboration among teams;

• clarity of roles and processes within

our organization;

• clarifying aspects of our vision,

mission and values; and

• developing, supporting and

recognizing staff.

Throughout the assessment process, there

was an emphasis on staff development (three

workshops covering communication and team

building skills, as well as numerous lunch-

and-learn sessions) and a workflow analysis

to address the first steps towards structural

reorganization. A cross-functional advisory

team was also established to enhance inclusion

and communication, and to solicit broad

perspectives for the structural reorganization.

A structural reorganization plan was

implemented, beginning with a restructuring

of staff in late F2017. Additional changes

are ongoing and are planned throughout the

remainder of the fiscal year.

In addition, over the course of the past

year, new members were welcomed to the

management team. Recruitment of a Chief

Operating Officer (COO) began in September

2016, following negotiations with the Public

Sector Employers’ Council (PSEC) to address

mandatory compensation ranges that impeded

recruitment of optimal candidates. The COO

will be tasked with leading the regulatory

functions, focusing on regulatory efficiencies

and effectiveness.

Organizational Structure


05


Together, the CEO, Director of Corporate

Services, and the COO will lead our staff and

Commissioners through the next phases of

the organizational effectiveness project, and

will ensure that the BCUC has a supportive,

collaborative and positive culture.

Commissioners: Commissioners are

independent decision-makers and are

appointed by the Lieutenant Governor in

Council in consultation with the BCUC’s Chair

and CEO. The Commissioners hold a variety of

professional backgrounds and work with staff

experts to ensure sound evidentiary reviews are

undertaken.

Corporate Services: Corporate Services

is responsible for strategic human resource

management, BCUC finances, information

technology and facilities management. The

division implements and administers human

resources policies relating to benefits, pay,

onboarding, employee relations, training,

development, travel and more. The division is

also responsible for the BCUC’s budget, and

ensures cost recovery from regulated entities

through an annual levy and direct proceeding

costs.

Regulatory Services: Regulatory Services is

led by the Commission Secretary/Manager,

Regulatory Services, who fulfils statutory duties

outlined in the Utilities Commission Act and

acts as the BCUC’s official representative. The

Regulatory Services group also manages all

administrative functions for the organization,

including web services.

Regulatory: Facilities and Planning, Rates,

and Compliance and Mandatory Reliability

Standards make up the BCUC’s three

regulatory divisions. Staff specialists within

these divisions apply professional expertise

in areas including accounting, economics,

ratemaking, business management,

engineering, policy and compliance. Based on

the subject matter under review by the BCUC,

staff from each division form cross-divisional

proceeding teams responsible for ensuring the

development of a full record of evidence for

consideration by Commissioners.

Communications: Communications is

responsible for planning and implementing all

internal and external communications for the

BCUC. Communications supports the following

activities: community engagement, media

relations, issues management and internal

communication with employees.

Strategic Solutions: Strategic Solutions

keeps the BCUC well informed of emerging

energy issues that will impact the Commission’s

regulatory role, and undertakes research and

analysis to support changes in regulatory policy

and procedure.



06

David M. Morton Chair and Chief Executive

Officer

Appointed Chair and CEO

effective December 31, 2015.

Prior to appointment as Chair,

served as Commissioner from

November 2010 to December

30, 2015. Bachelor of Applied

Science, University of Toronto;

Professional Engineer (British

Columbia); Licentiate in

Accounting, Society of

Management Accountants

Canada; certified with the

ICD.D designation in 2013 by

the Institute of Corporate

Directors. Consultant with

over 25 years of experience in

the information technology

sector, specializing in project

management, business and

technical analyst services.

Dennis A. Cote

Commissioner (Part-time)

Appointed in October

2008. Bachelor of General

Studies, Simon Fraser

University. Retired in 2007

as Vice President, Product

Development and Support

for the British Columbia

Automobile Association; held

various other executive roles

with the British Columbia

Automobile Association,

including Vice President Sales,

Director of Travel Services;

Merchandise Investment

Manager and Store

Manager with the Hudson

Bay Company, B.C. Region;

currently a member of the

Board of Consumer Protection

British Columbia.

Douglas J. Enns Commissioner (Part-time)

Appointed in March 2016.

Bachelor of Arts (Economics),

University of Manitoba;

FCPA, Fellow Chartered

Professional Accountants

of British Columbia; C.Dir,

Chartered Director, McMaster

University; MBA, University of

Wales; completed Enterprise

Risk Management Certificate,

Stanford University. President

of Upturn Consulting Ltd.;

Chair of the Board of

Consumer Protection British

Columbia; member of the

Board of Directors of British

Columbia Life Insurance Ltd.;

past President of the Institute

of Chartered Accountants

of British Columbia; former

Board member of Royal Roads

University, the University

of Victoria, Medic Alert

Foundation and RaxMax

Industries Advisory Board.

Commissioner Biographies


07


William M. Everett


Appointed in February 2016.

Bachelor of Arts (Political

Science and Economics),

University of Manitoba;

Bachelor of Law, University of

British Columbia. Practised

law at Lawson Lundell LLP

primarily in the area of

complex litigation with a focus

on commercial, construction,

engineering, products liability,

insurance and regulatory issues

for the last 44 years and has

appeared as counsel before

the Supreme Court of Canada,

courts in B.C. and Alberta and

regulatory tribunals; Chartered

Arbitrator and has mediated

and arbitrated numerous

disputes; an elected Bencher

of the Law Society of B.C. in

1998, served as its President in

2003 – 2004 and is currently

an Adjudicator on Law Society

Panels disciplinary and

credential hearings; has served

on many Boards, including the

Pacific Alzheimer Research

Foundation, Vancouver Art

Gallery, Crofton House School

and the Vancouver Playhouse

Theatre.

Howard G. Harowitz Commissioner (Part-time)


Bachelor of Commerce

(Economics), University of

British Columbia; Master

of Business Administration,

Stanford University. Partner

at PricewaterhouseCoopers;

President of two operating

companies; principal and

director of a private consulting

firm; Director, Vancouver

Coastal Health, Dalai Lama

Centre and Gateway Theatre

Society.

Karen A. Keilty Commissioner (Part-time)

Appointed in June 2014.

Bachelor of Business

Administration, Simon Fraser

University; FCPA, Fellow

Chartered Accountant,

Chartered Professional

Accountants of British

Columbia; completed Directors

Education Program and

Not-for-Profit Governance

Course with the Institute

of Corporate Directors.

30 years’ audit experience

with Deloitte, serving as

the leader of Deloitte’s

B.C. audit practice prior to

retirement in 2014; Director

of Great Canadian Gaming

Corp.; Member of Executive

Committee, Canada’s

Energy and Utility Regulators

(CAMPUT); served on Council

of Institute of Chartered

Accountants of B.C. and as

President in 2019/10; past

Director of Quest University,

Vancouver Social Venture

Partners, British Columbia

Paraplegic Foundation, Forum

for Women Entrepreneurs,

Vancouver Enterprise Forum,

B.C. Chamber of Commerce

and Women’s Addiction

Foundation.

Miriam KresivoCommissioner (Part-time)

Appointed in June 2016. Juris

Doctor, UBC Law School;

Bachelor of Arts, McGill

University. Associate Counsel

at Alexander Holburn

Beaudin and Lang, Second

Vice President of the Law

Society of B.C.; previously

General Counsel of Chevron

Canada Limited, Products

Division; past member of

the Board of B.C. Pavilion

Corporation, the owner and

operator of the Convention

Centre and BC Place.



08


Norman E. MacMurchy


until November 2016

Appointed in November 2010.

Honours Bachelor of Arts

(Economics and Commerce),

Royal Military College of

Canada; Master of Arts,

Economics, University of

Western Ontario. Retired

2006 as Executive Director,

Industrial Gas Consumers

Association of Alberta;

held various positions with

the Alberta and federal

governments including Chair,

Alberta Petroleum Marketing

Commission; Assistant Deputy

Minister, Sustainable Energy

Development Division, Alberta

Department of Energy and

Natural Resources; and

Chief, Policy Analysis and

International Division, National

Energy Board.

Iain F. MacPhail Commissioner (Part-time)

until June 2016


Bachelor of Arts (Economics),

University of Western Ontario;

CPA, Chartered Accountant,

British Columbia and Ontario.

Over 37 years of experience

as a professional accountant

focused on taxation and

financial advisory services;

served as Director, Chief

Financial Officer and Advisor

to resource companies,

charities and not-for-profit

organizations.

Bernard A. Magnan


Appointed in June 2012.

Bachelor of Commerce

(Economics), Concordia

University; Master of

Business Administration,

Simon Fraser University;

Certified Management

Consultant; Fellow of

Chartered Professional

Accountants. Served five

years as Assistant Managing

Director and Chief Economist,

the Vancouver Board of

Trade; Managing Director of

BMA Ltd., a management

consulting and project

management firm specializing

in project management,

strategic planning and

corporate turnarounds for

several industries including

transportation, finance,

manufacturing, health care

and utilities.

09



Richard I. Mason


Appointed in March

2016. Bachelor of Arts

(Mathematics and Computing

Science), University of

Cambridge; Master of

Business Administration,

University of Cambridge.

Previously held the role of

CEO with two information

technology businesses and

executive leadership roles at

Health Insurance B.C. and

Pacific Blue Cross; mentor

to entrepreneurs for the

Canadian Youth Business

Foundation, and to students of

the University of Cambridge’s

MPhil. Management program;

former member of the B.C.

Medical Association’s Council

on Health Promotion.

Richard D. Revel Commissioner (Part-time)

Appointed in December

2011. Bachelor of Science,

Notre Dame University of

Nelson; Doctor of Philosophy

(Plant Ecology), University of

British Columbia. Currently

Professor Emeritus,

University of Calgary; retired

in 2008 as Professor of

Environmental Science at

the University of Calgary;

specialized in the technical

and economic aspects

of resource development

and management; held

appointments to the National

Energy Board of Canada and

with the Ministries of Energy

and Mines and Environment

in Ecuador under the auspices

of the United Nations

Development Programme.


10

Staff Chair and CEO

David MortonChair and Chief Executive Officer

COO

Recruitment underwayChief Operating Officer

Corporate Services

Viki VourlisDirector

Sheena ZypManager, Human Resources and

Procurement Administrator

Kevin WongFinancial Administrator

Blake MansbridgeHuman Resources and Finance

Business Analyst

Mark HudsonWeb/IT Administrator

Madi KennedyJunior Analyst

Regulatory Services

Patrick Wruck Commission Secretary and

Manager, Regulatory Services

Constance SmithSenior Administrator

Yvonne LapierreAdministrative Assistant

Daniela Guest

Administrative Assistant

Katie BerezanAdministrative Assistant

Nhi Do

Administrative Assistant

Amanda DuncanAdministrative Assistant

Keshni NandAdministrative Assistant

Aisha Quo VadisReceptionist


11


Facilities and Planning

Recruitment underwayDirector

Jackie AshleySenior Regulatory Analyst

Errol SouthSenior Regulatory Analyst

Hillary CheungRegulatory Economist

Chris GarandSenior Engineer

Joel RonneSenior Infrastructure Engineer

Lejla UzicaninSenior Economist

Rates

Yolanda DomingoDirector

Suzanne SueSenior Regulatory Specialist

Claudia McMahonSenior Regulatory Specialist

Laurel RossSenior Regulatory Specialist

Sarah WalshSenior Regulatory Specialist

Leon CheungSenior Regulatory Analyst

Tanya LaiRegulatory Analyst

Bonnie GuzmanRegulatory Analyst



12

Compliance and MRS

Kristine BienertDirector

Ian HomerSenior Compliance Analyst

Marija TresoglavicCompliance Administrator

Christine SchwabMRS Program Manager

Ashita Anand SangheraInfrastructure Engineer

Atalla BurettaGas Engineer

Canon HoCustomer Relations Analyst

Cathy MarrManager, Energy Supply

Katharine CarlsenManager, Gas Marketing Programs

Communications

Erica HamiltonDirector

Strategic Solutions

Doug ChongDirector


13



Delivering on our plan to improve the BCUC experience for the public, stakeholders and our regulated utilities.


14

Optimizing Information Technology to Enhance Communication and Streamline Procedures The BCUC determined that a number of

our processes and technology tools could be

improved to provide a better level of service

to stakeholders while improving internal

efficiency and effectiveness. After analyzing

communication and work processes, we

embarked on an information systems renewal

project. For the coming year, as part of our

Information Technology Strategic Plan, the

BCUC will undertake the following information

technology projects:

• replacement of the informational

portions of the BCUC’s website; and

• implementation of an intranet to

improve internal communication and

knowledge sharing.

Some projects will commence in this fiscal year

and be completed in the following fiscal year,

including:

• implementation of a Microsoft

SharePoint solution to improve

internal management of proceeding

documents;

• implementation of a Microsoft

Dynamics solution to better track,

manage and report on timelines and

interested stakeholder involvement

for proceedings. The system will also

be used to track and report on the

complaints process. Stakeholders

can expect more clarity on

application/submission progress and

on proceeding timelines; and

• replacement of the proceedings,

decisions and orders archive, and

search functionality on the public

website. Users will enjoy improved

search and navigation tools.

Assessing the Public Interest: The Residential Inclining Block Electricity Rate Report

The Minister of Energy and Mines and Minister

Responsible for Core Review asked the BCUC

to report on the impact of the BC Hydro and

FortisBC Inc. Residential Inclining Block (RIB)

rates. Complaints had been received regarding

“unreasonable bill impacts” on some customers,

in particular rural customers who do not have

access to natural gas to heat their homes, and

low-income customers.

The BCUC conducted an extensive, province-

wide public consultation, seeking input on the

process for the review and on the analysis

submitted by BC Hydro and FortisBC Inc. Ten

organizations and individuals registered as

stakeholders and submitted comments and

analysis. A further 669 letters of comment

from the public were received and entered into

the record.


15


Replacing the previous flat rate structure, the

RIB rates were introduced to incent consumers

to conserve energy, and there is evidence that

this has been successful. However, it has been

suggested that the RIB rates cause people living

in areas without access to natural gas to cross-

subsidize people living in areas that do have

access to natural gas. The BCUC determined

that there is no such cross-subsidy, and that the

RIB rates are not unjust, unreasonable, unduly

discriminatory or unduly preferential, which

are the tests the BCUC must use when setting

rates.

The BCUC also considered the demand-side

management (DSM) programs offered by BC

Hydro and FortisBC Inc. aimed at encouraging

customers to conserve energy and promote

energy efficiency, including programs tailored

for low-income customers. The BCUC believes

that there is potential for these DSM programs

to reduce customers’ electricity use, although

more could be done to promote programs

to encourage customers to participate. Also,

the BCUC believes that there is potential for

additional programs and innovative financing

programs that could further help customers, in

particular low-income customers, to conserve

energy and reduce their electricity bills.

Improving Stakeholder Engagement

The BCUC is open, transparent and focused

on working with and listening to the public,

stakeholders, utilities and government to

improve our communications and stakeholder

engagement practices.

Currently, members of the public can engage

with BCUC processes by:

• registering on the public evidentiary

record and receiving email

notification of all non-confidential

evidence presented in a proceeding;

• contributing views and opinions

about a matter before the BCUC;

and

• applying to intervene in proceedings

for those who demonstrate that

they are sufficiently affected by a

decision.

As part of our overall strategic direction for

2016-19, the BCUC is committed to a greater

level of engagement with stakeholders.

An assessment of the effectiveness of our

communications and public engagement was

completed by an external consultant in 2016,

with the following recommendations:

• the BCUC should increase public

consultation and engagement

through greater opportunities for

stakeholder input; and

• the BCUC should proactively use

media relations, social media

and digital media to raise public

awareness of BCUC proceedings.

While certain aspects of the stakeholder

engagement plan have started to be

implemented immediately, such as proactively

engaging media and obtaining public input,

the plan will continue to be operationalized in

the upcoming year. As part of our restructuring

initiative, we created a new position to assume

this responsibility.



16

Encouraging Participation through Updated Guidelines

As part of the BCUC’s commitment to

encourage quality participation and broader

representation of parties in our proceedings, we

use our ability under the Utilities Commission Act

to provide Participant Assistance/Cost Award

(PACA) funding to participants. The BCUC’s

procedures and considerations for this funding

are set out in the PACA Guidelines.

Based on our 2016-19 Business Plan strategy

to improve effectiveness and efficiency, we

launched an external stakeholder consultation

process to review the PACA Guidelines in

January 2016. We received three rounds of

written comments from 18 stakeholders

representing regulated entities, interveners and

individuals.

Based on the feedback received, the BCUC

reviewed the PACA Guidelines to ensure they

remain useful, effective and up to date. Three

high-level objectives were identified for the

review and development of the new PACA

Guidelines:

1. improve the quality of participation

in proceedings;

2. encourage broader representation of

participants; and

3. make the PACA Guidelines easier

to use, both by the BCUC and by

participants.

With these high-level objectives in mind, and

considering the comments received from the

consultation process, changes have been made

to the PACA Guidelines. Highlights include:

Participant eligibility

Updated to encourage broader participation

by replacing the "substantial interest in a

substantial issue" threshold with a "directly or

sufficiently affected" threshold, and allowing

eligibility based on relevant experience,

information or expertise.

Criteria for a cost award

Updated to improve the quality of

participation in proceedings by prioritizing the

usefulness of the participant’s contribution to

a proceeding, rather than how the participant

is affected by the BCUC’s decision.

Updated to provide clarity and guidance on

funding days for written proceedings, rather

than just focusing on oral proceedings.

Interim funding

Updated to make the PACA Guidelines easier

to use by specifying guidelines for interim

funding.

Professional fees

Updated to reflect current costs of

professional participation by amending the

rate schedule based on inflation and the rates

allowed by other jurisdictions.

Updated to encourage participants to use

professional services in a cost-effective

manner, recognizing the complexity of the

matters in a proceeding.


17


On August 31, 2016, the BCUC issued Order

G-143-16 to approve the amended PACA

Guidelines, which became effective for all

proceedings initiated on or after August 31,

2016. The BCUC also developed PACA Budget

Estimate and PACA Application forms to

support the information-gathering and

evaluation process.

Increasing Efficiency in Reviewing Applications As part of the BCUC’s efforts to increase the

efficient review of applications, we sought

stakeholder feedback on draft filing guidelines

to assist utilities in the preparation of regulatory

(deferral) account applications. The guidelines

are intended to ensure completeness of

applications so as to facilitate an efficient

review of regulated entities’ applications for

regulatory accounts by reducing BCUC staff’s

review time.

BCUC staff reviewed historical regulatory

account applications and review processes,

including the types of regulatory account

requests put forward by utilities and the

information requests elicited by BCUC

staff and other participants. Based on the

information gathered, BCUC staff prepared

draft Regulatory Account Filing Guidelines

and initiated a public comment process. Eight

stakeholders, including regulated utilities,

intervener groups and individuals, submitted

feedback on the draft guidelines.

Based on the feedback received, the wording

of the guidelines was amended to incorporate

stakeholders’ comments and/or concerns,

where appropriate. Of note, the title of the

document was changed from Regulatory

Account Filing Guidelines to Regulatory Account

Filing Checklist to emphasize that the purpose

of the document is to assist regulated entities

when filing regulatory account requests so as to

facilitate an efficient review by the BCUC, and

to emphasize that the contents of the Checklist

are not meant to be seen as prescriptive

guidelines or rules.

The BCUC finalized the Regulatory Account

Filing Checklist for stakeholders in May 2017. The

checklist is now available on the BCUC’s website

to serve as a tool for regulated entities going

forward.



18


The number of written complaints this year decreased to 397 from 475 reported in the previous year.

19


The BCUC works to resolve complaints

about regulated electricity or gas utilities

and ICBC’s basic automobile insurance

rates that are within our jurisdiction

under the Utilities Commission Act. While

most complaints are resolved through

discussions between the customer and

utility concerned, unresolved issues may be

referred to the BCUC.

Complaints received by the BCUC this year

include issues related to:

• billing;

• metering and meter reading;

• application of standard charges

and rates;

• tariff-related matters;

• customer service;

• power quality;

• maintenance of utility

infrastructure; and

• information requests about service

or regulation.

The number of written complaints this year

decreased to 397 from 475 reported in the

previous year. The table to the right provides

a breakdown of the complaints received per

utility. Those utilities with no complaints to

the BCUC are not included.

Complaints Received Number Total

BC Hydro and Power Authority 230

General Complaints 67

Billing 44

Rates 38

Smart Meters 61

Disconnection 20

FortisBC Inc. (electric) 68


Billing 21

Rates 20

Advanced Metering Infrastructure 3

Disconnection 5

FortisBC Energy Inc. (gas) 55


Billing 14

Rates 18

Disconnection 2

Insurance Corporation of British Columbia 15

Pacific Northern Gas Ltd. 5

Nelson Hydro 3

FortisBC Alternative Energy Services Inc. 1

Canwest Propane ULC 1

Shannon Estates Thermal Energy Systems 1

Stargas Utilities Ltd. 1

Superior Propane 1


Total 397

Addressing Utility Customer Complaints



20

The decrease in the number of complaints from

the previous year is due in part to a decline in

the number of complaints regarding BC Hydro’s

Meter Choices Program and FortisBC Inc.’s

Advanced Metering Infrastructure Project.

While BC Hydro and FortisBC Inc. continue

to replace legacy meters as permitted (by

regulation for BC Hydro, and by a Certificate of

Public Convenience and Necessity for FortisBC

Inc.), complaints in this category have declined

this year.

There continue to be complaints from FortisBC

Inc. and BC Hydro customers regarding the

two-step Residential Inclining Block (RIB) rate.

In July 2016, the BCUC received a letter from

the Minister of Energy and Mines requesting

that the BCUC investigate concerns about the

rate structure. The Minister posed five questions

and a proceeding was established to respond

to the five questions. The proceeding concluded

in early 2017, and on March 28, 2017, the BCUC

issued an independent report in response to the

Minister’s request (for more information, see

“Assessing the Public Interest: The Residential

Inclining Block Electricity Rate Report” under

“Operational Highlights” in this report).

The Natural Gas Customer Choice Program

In British Columbia, natural gas marketers

have been authorized to sell natural gas to

commercial customers since 2003 and to

residential customers since 2006 through the

Customer Choice program. The BCUC’s role in

this program is to license the gas marketers,

establish the Rules and Code of Conduct that

gas marketers must follow, and adjudicate

disputes and complaints filed against gas

marketers by customers.

Gas Marketer Participation

In F2016/2017, the BCUC licensed six gas

marketers under the Customer Choice program:

• Access Gas Services Inc.

• Bluestream Energy Inc.

• Direct Energy (BC) Ltd.

• Just Energy (BC) LP

• Planet Energy (BC) Corp.

• Summitt Energy BC LP

Customer Choice Program Fee Recovery Application

During the 2015 Customer Choice program

Annual General Meeting, the issue of declining

program enrolments and the resulting impact

on FortisBC Energy Inc.’s ability to recover

program costs was raised. The BCUC directed

FortisBC Energy Inc. to submit an application

to address the Customer Choice program fee

structure. In April 2016, they applied to the

BCUC for approval of a revised cost recovery

model for the Customer Choice program. Their

application proposed to allocate costs between

gas marketers and all FortisBC Energy Inc.’s

non-bypass customers based on the principle

of cost causation, with a combined fixed and

variable fee structure for recovery of costs

allocated to licensed gas marketers.

A written public hearing was held to review the

application. Intervening in this proceeding were

licensed gas marketers, the Commercial Energy

Consumers Association of B.C. and the B.C.

Old Age Pensioners' Organization. All of the

interveners opposed FortisBC Energy Inc.’s cost

allocation model and put forth alternative cost

allocation proposals.


21


Upon completion of the hearing and review

of the evidence in the proceeding, the BCUC

determined that the cost causation principle

is the appropriate basis for allocating the

Customer Choice program costs. It further

determined the cost causation principle should

be applied on the basis of the following criteria:

1. Are the costs incurred specifically to

administer the program and services

for licensed gas marketers and their

customers? If so, these costs should

be allocated to these gas marketers.

2. Are the costs incurred to ensure the

program is available for all eligible

customers whether or not they

currently choose to participate. If all

FortisBC Energy Inc.’s non-bypass

customers benefit from the cost,

then these types of costs should be

allocated to all of these customers.

3. Where costs are incurred to

administer the program and ensure

it is available for all eligible FortisBC

Energy Inc. customers, non-bypass

customers and licensed gas

marketers should share those costs.

The BCUC determined the fixed monthly fee

for each licensed gas marketer would be set

at $750 per month, with the balance to be

recovered through variable fees. The BCUC also

approved the use of a non-rate, based deferral

account to capture and record any under- or

over-recovery of gas marketer fees to be used

as a debit or credit when these fees are set

annually (starting April 1, 2017).

Complaints and Disputes

The BCUC adjudicates complaints and disputes

that have not been directly resolved between

customers and licensed gas marketers.

The complaint process is available for members

of the public with a general complaint or

concern about a gas marketer’s customer

service, salesperson conduct or marketing

practices, or about the Customer Choice

program administration. Complaints can be

from members of the public who may or may

not have entered into an agreement with a gas

marketer. In F2016/2017, the BCUC reviewed a

total of 26 written complaints. This represents a

decline compared to F2015/2016, during which

the BCUC reviewed 44 written complaints.

The dispute process is available for customers

who have signed a contract with a licensed gas

marketer and wish to dispute their contract.

Contracts may be disputed for a number of

reasons, including contract term, contract price,

validity of the contract and non-compliance

with the Code of Conduct. In F2016/2017, the

BCUC received 171 disputes through the dispute

resolution process, decreasing from a total of

207 disputes in F2015/2016. This figure includes

disputes adjudicated by the BCUC and non-

contested disputes in which the gas marketer

agreed to cancel a customer’s contract of their

own accord, without a BCUC determination.



22

Report on Performance Maximizing the efficiency and effectiveness of the review process.

23


Performance measurement and evaluation provides information that can aid in process

improvement and innovation, and ultimately improve the regulatory experience for stakeholders.

By measuring performance, the BCUC aims to improve key aspects of our regulatory efficiency and

effectiveness, specifically timeliness, responsiveness and transparency. While striving for regulatory

efficiency and effectiveness, the BCUC is committed to ensuring that other important aspects of

regulatory performance that are more difficult to measure are not sacrificed, such as the diligence

and quality of reasoning and writing.

Table 1 summarizes the performance measures

and targets selected by the BCUC. Two types of

performance measures are identified:

i. performance measures with targets; and

ii. indicative performance measures

(without targets).

Indicative performance measures do not have

targets, due to the potential for erratic trends

caused by external factors outside the BCUC’s

control.

In addition to performance measures, the

BCUC reports on the following measures

annually to provide context and transparency:

• Average Annual Decision Cycle Time;

• Total Cycle Time for each hearing

proceeding;

• Business Plan project updates; and

• Mandatory Reliability Standards

metrics.

Table 1: BCUC Performance Measures and Targets for F2017

Performance Measure Target

Cycle Time

1. Decision Cycle Time 90% issued in 90 calendar days or less

2. Other Proceedings Total Cycle Time Maximum annual average of 40 calendar days

Customer and Stakeholder Experience

3. Complaint and Enquiry Response Time 85% in 5 business days or less

4. Participant Assistance/Cost Award Cycle Time 100% issued in 60 calendar days or less

Organizational and Financial Performance

5. Employee EngagementMeet or exceed the BC Public Service – Work Environment Survey score

6. Total Expenditure per Capita ($/capita) None (Indicative Measure)

7. Energy Regulation Expenditure per gigajoule ($/GJ) None (Indicative Measure)



24

of decisions issued in 90

calendar days or less

93%

Target minimum of 90% achieved

Average cycle time for non-hearing

proceedings

calendar days39

Target maximum of 40 days achieved

of complaints and enquiries

responded to in 5 business days

or less

86%

Target minimum of 85% achieved

Target minimum of 100% not reached

of PACAs issued in 60

calendar days or less

90%

Compared favourably to the BC Public Service – Work Environment Survey score of 66

Employee Engagement Survey results

73/100

Indicative measures (no target)

Total energy regulation

expenditure per capita

$1.67

Energy regulations expenditure per

gigajoule

$0.018

Performance Measures at a Glance


25


The BCUC’s Public Hearing Process


Start of the total application cycle time for all proceedings

End of non-hearing proceeding total cycle time

Start of decision cycle time

End of decision cycle time

The BCUC releases an Order and Notice of Public Hearing

Public hearing required

Staff review and request further information from applicant if required

Public opportunity to ask to participate in the hearing

Staff provide recommendation to Commissioners

Process determined Decision released

Written hearing

Streamlined review process

Oral hearing

Negotiated settlement process

Request for and examination of information

Decision released

Request for and examination of information

Final argument

Final argument

Decision released

Decision released

Decision released

No public hearing required

Commission-initiated proceeding

Application filed by utility or complaint filed by customer


26

1. Decision Cycle Time

The Decision Cycle Time is a measure of

the BCUC’s deliberation on proceedings.

It is measured by the duration in

calendar days from the date of the

reply argument (or in some cases

another event signalling the beginning

of the BCUC’s deliberation) to the

earlier date of the decision or order.

This performance measure includes any

proceedings with arguments, or those

that allow for arguments, that result in

a final order, decision or report.

The purpose of this measure is to

support the objectives of effectiveness

and efficiency by ensuring transparency

and accountability for the timely

issuance of decisions for hearings. This

requires the BCUC to balance timeliness

and quality, ensuring that efficiency

does not adversely affect quality and

vice versa. The 90 percent target allows

for some flexibility by allowing a limited

number of proceedings to have longer

timelines, if necessary.

The BCUC’s target is to issue decisions

within 90 days (from the start of the

deliberation period) for 90 percent of

proceedings. This target was achieved

in F2017; 93 percent of decisions were

issued within 90 days.

Minimum target: 90% issued in 90 calendar days or less

100

80

60

40

20

0

Percent of decisions issued within 90 days

93% 88% 78% 71% 92% 97% 93%

F2011 F2012 F2013 F2014 F2015 F2016 F2017

No target

70

60

50

40

30

20

10

0

Average number of days

61 43 45 54

F2014 F2015 F2016 F2017 Average

51

Percent of Decisions Issued within 90 Days

Average Annual Decision Cycle Time (days)


The BCUC also reports on the Average Annual Decision

Cycle Time (in calendar days). For this measure, there

is no accompanying target; however, it helps provide

transparency and accountability, and gives an indication

of how the BCUC is performing year to year. This year’s

average decision cycle time was 51 days, compared with

45 in F2016, 43 in F2015, and 61 in F2014.

27


Decision Cycle Time and Total Cycle Time for Hearing Proceedings

The charts below summarize the Total Cycle Times and the Decision Cycle Times for each hearing

proceeding. It is important to note that there are a number of circumstances that affect the time it

takes to review an application or complete an inquiry.

G-129-16 FortisBC Energy Inc. Application for its Common Equity Component and Return on Equity for 2016

G-5-7 British Columbia Hydro and Power Authority 2015 Rate Design Application

89224

88396

Application to Reply Argument

Reply Argument to Decision

G-133-16 FortisBC Energy Inc. Application for Approval of Biomethane Energy Recovery Charge (BERC) Rate Methodology

A-9-16 FortisBC Energy Inc. Application for the Customer Choice Program Cost Recovery

86264

61126



G-47-16 British Columbia Hydro and Power Authority 2015 Rate Design Application Module 1 Cost of Service Study and Rate Class Segmentation Negotiated Settlement Agreement

11

189



Oral Hearing Cycle Times

Streamlined Review Process Cycle Time

Negotiated Settlement Process Hearing Cycle Time



28

G-48-16A Corix Multi-Utility Services Inc. Application for a Certificate of Public Convenience and Necessity for Additional Capital and Amended Rates for UniverCity Neighbourhood Utility Service on Burnaby Mountain

G-74-16 Insurance Corporation of British Columbia Application for Revenue Requirements for Universal Compulsory Automobile Insurance for the Policy Year Commencing November 1, 2015

79

57213

Application to Reply Argument Reply Argument to Decision

G-78-16 British Columbia Hydro and Power Authority W.A.C. Bennett Dam Riprap Upgrade Project

G-88-16 Creative Energy Vancouver Platforms Inc. Application for Approval of the Restated and Amended Northeast False Creek and Chinatown Neighbourhood Energy Agreement

187

4983

E-10-16 FortisBC Energy Inc. 2015 Price Risk Management

G-119-16 FortisBC Energy Inc. Proposal for Depreciation and Net Salvage Rate Changes

41109

G-131-16 Pacific Northern Gas Ltd. 2016-2017 Revenue Requirements Application for the PNG-West Service Area

G-132-16 Pacific Northern Gas (N.E.) Ltd. 2016-2017 Revenue Requirements Application for the PNG (N.E.) Service Area

48

41213

G-147-16 FortisBC Energy Inc. 2015 System Extension Application

G-149-16 Sun Peaks Utilities Co., Ltd. Application for Approval of a Delivery Rate Increase

224

8887

G-151-16 Creative Energy Vancouver Platforms Inc. Application for Reconsideration and Variance of Order G-88-16

G-162-16 FortisBC Energy Inc. Application for Approval of 2017-2018 Revenue Requirements and Rates for the Fort Nelson Service Area

4092

G-167-16 Creative Energy Vancouver Platforms Inc. 2016-2017 Revenue Requirements Application and Rate Design for Northeast False Creek Hot Water Service

224

3

9

14

56121

206

123

47

321

35

95136

Written Hearing Cycle Times


29



Application to Reply Argument Reply Argument to Decision

G-172-16 Superior Propane Rate Application for Seascapes Grid System

G-175-16 Spirit Bay Utilities Ltd. Application for Exemption pursuant to section 88(3) of the Utilities Commission Act

215 70

8583

G-199-16 FortisBC Inc. Net Metering Program Tariff Update Application

G-2-17 Insurance Corporation of British Columbia Application for Approval of the Revenue Requirements for Universal Compulsory Automobile Insurance Effective November 1, 2016

168

132

G-9-17 FortisBC Inc. Application for Acceptance of Demand Side Management Expenditures for 2017

C-1-17 FortisBC Inc. Application for a Certificate of Public Convenience and Necessity for the Corra Linn Dam Spillway Gate Replacement Project

G-25-17 FortisBC Energy Inc. All-Inclusive Code of Conduct and Transfer Pricing Policy Application

57

75169

G-34-17 Port Alice Gas Inc. Application for Approval to Increase the Basic Charge and Facility Charge

G-42-17 Creative Energy Vancouver Platforms Inc. Application for Approval of Northeast False Creek Connection Agreement

231

G-48-17 Seascapes Strata Corporation BCS776 Application for Reconsideration and Variance of Order G-172-16

G-182-16 FortisBC Energy Inc. Annual Review for 2017 Delivery Rates3592

G-8-17 FortisBC Inc. Annual Review for 2017 Rates224

20

4

8

8486

166

121

88

7293

90

50

Written Hearing Cycle Times


30

Decision Cycle Time

The BCUC met the Decision Cycle Time target,

with 90 percent of decisions being issued in 90

days. Two hearings in F2017 did not meet the

90-day Decision Cycle Time target.

There are a number of circumstances that can

cause missed targets, and they are not always

within the BCUC’s control. Furthermore, the

BCUC is committed to ensuring that efficiency

does not adversely affect the quality of a

decision.

The following two proceedings did not meet

the decision cycle target time as both occurred

during a period where the BCUC was working

with an exceptionally high workload and

prioritization was necessary. In these rare

instances the Panel and lead staff chose to

exceed the target time to ensure a fair, thorough

and quality decision was reached.

• Creative Energy Vancouver Platforms Inc. 2016-2017 Revenue Requirements Application and Rate Design for Northeast False Creek Hot Water Service

Creative Energy Vancouver Platforms

Inc. 2016-2017 Revenue Requirements

Application and Rate Design for Northeast

False Creek Hot Water Service had a 95-day

Decision Cycle Time.

Start date: August 16, 2016

Target date: November 14, 2016

Decision: November 18, 2016

Decision Cycle Time: 95

Days over target: 5

• FortisBC Energy Inc. 2015 System Extension Application

FortisBC Energy Inc. 2015 System Extension

Application had a 123-day Decision Cycle

Time.

Start date: May 16, 2016

Target date: August 14, 2016

Decision: September 16, 2016

Decision Cycle Time: 123

Days over target: 33


31


2. Other Proceedings Total Cycle Time

Other Proceedings Total Cycle Time

measures the average duration in calendar

days for processing orders or letters for

applications/filings/items not handled

through a proceeding with an argument.

This is typically measured from the date the

application is received to the date the order/

decision is issued.

The intent of this performance measure is

to monitor the timeliness of processing non-

hearing proceeding items. The objective is to

promote effective and efficient operations

by ensuring transparency and accountability

for the timely issuance of decisions for

hearings.

50

40

30

20

10

0

Annual average number of calendar days

39 40 35 39

F2014 F2015 F2016 F2017

Maximum target: Annual average of 40 calendar days

Annual Average Number of Calendar Days for Non-Hearing Total Cycle

3. Complaint and Enquiry Response Time

Complaint and Enquiry Response Time

measures the business days from the receipt

of a complaint, an enquiry, or Freedom of

Information Request to the date of the

BCUC’s first substantive response. This

measure includes complaints and enquiries

from regulated company customers as

well as complaints regarding the Customer

Choice program and associated gas

marketers. However, this does not include

correspondence where the BCUC has been

copied on a complaint or enquiry addressed

to another party.

This measure aims to increase transparency

surrounding the BCUC’s responsiveness

towards customers and stakeholders. We

recognize the importance of timely, tailored

and appropriate responses to complaints

and enquiries and Freedom of Information

requests from utility customers, utilities and

other stakeholders.

100

80

60

40

20

0

Complaint and enquiry responses within 5 business days

86% 76% 86%

F2015 F2016 F2017

Minimum target: 85% in 5 business days or less

Complaint and Enquiry Responses within 5 Business Days

The BCUC’s target is to complete non-hearing

proceedings within 40 days on average. In F2017,

this target was achieved with an annual average

of 39 calendar days.

The BCUC’s target is to respond to complaints and

enquiries within 5 business days 85 percent of the time.

In F2017, this target was achieved with 86 percent of

complaints and enquiries meeting this target.



32

4. Participant Assistance/Cost Awards (PACA) Cycle Time

Participant Assistance/Cost Awards Cycle

Time measures the calendar days from the

completion of a proceeding (or the date of the

final intervener application, if it came after) to

the date the PACA order was issued.

The objective of this performance measure is to

ensure the timely issuance of orders regarding

intervener expenses for each proceeding.

Meeting this target ensures that the BCUC

will consistently give participants appropriate

expectations as to cost award timelines.

The BCUC set an ambitious target to issue

PACAs within 60 days for 100 percent of

proceedings. The BCUC narrowly missed this

target, with 90 percent of PACA Cycle Times

being under 60 days.

Minimum target: 100% issued in 60 calendar days or less

100

80

60

40

20

0

Percent of PACA Cycle Times in 60 days or less

63% 76% 77% 97% 90%

F2013 F2014 F2015 F2016 F2017

Percent of PACA Cycle Times Under 60 Days


33


PACA Cycle Times Missed Targets

As with the Decision Cycle Times, the BCUC

monitors the PACA orders that are not issued

within the 60-day target. When this target

is missed, BCUC staff and Commissioners

are required to fill out a report explaining

the circumstances that led to the missed

target. This helps build internal awareness

of targets, and accountability among staff

and Commissioners. Furthermore, identifying

missed targets can create an opportunity for

organizational learning, more effective resource

utilization, and process innovation within the

BCUC. However, it is important to note that

there are a number of circumstances that can

cause missed targets, and they are not always

within the BCUC’s control.

The following outlines the instances of missed

PACA Cycle Time targets, and the reasons for

these missed targets.

• FortisBC Inc. Application for a Certificate of Public Convenience and Necessity for Construction of the Kootenay Operations Centre

The PACA Cycle Time target for this

proceeding was not met because there

were documentation issues with one of the

intervener’s applications, leading to a delay

in processing the application.

Start date: March 4, 2016

Target date: May 3, 2016

PACA Order Date: May 5, 2016

PACA Cycle Time: 62

Days over target: 2

• British Columbia Hydro and Power Authority Application for Approval of Debt Management Regulatory Account

The PACA Cycle Time target for this

proceeding was not met because the Panel

and lead staff had substantial workload on

other proceedings that occurred during the

same time period.

Start date: April 12, 2016

Target date: June 11, 2016

PACA Order Date: June 16, 2016

PACA Cycle Time: 65

Days over target: 5

• British Columbia Hydro and Power Authority W.A.C. Bennett Dam Riprap Upgrade Project

The PACA Cycle Time target was not met

because the intervener filed its application

64 days after the filing deadline; therefore,

the application was not processed with

the other PACA applications. In addition,

the entity that was asked to provide

reimbursement took 24 days to comment on

the application. Finally, the PACA application

was complex and involved a request for

confidential treatment of documentation.

Start date: August 19, 2016

Target date: October 18, 2016

PACA Order Date: November 4, 2016

PACA Cycle Time: 77

Days over target: 17



34

5. Employee Engagement

The purpose of this performance measure is to

encourage a healthy workplace environment

that fosters employee development and

empowerment. A healthy workplace

environment encourages employees to work

efficiently and effectively to achieve the BCUC’s

goals. This performance measure is based on

the premise that a balanced approach should

focus on financial performance, business

processes and the environment for the people

who carry out these processes.

Employee Engagement is determined by the

BCUC’s overall Engagement score from the

Work Environment Survey (WES), an employee

engagement survey designed by the central

statistical agency of the province of British

Columbia (BC Stats).

The WES is a biennial online survey that seeks

to determine an overall Engagement score that

represents the health of the work environment

by taking into consideration areas including, but

not limited to, satisfaction, workplace tools,

professional development and management.

The Engagement score ranges from 0 to 100,

with 100 being the optimal score.

The BCUC achieved a score of 73 out of 100,

with a response rate of 90 percent and the

survey completion rate of 82 percent. The

BCUC 2015 Engagement score compares

favourably with the BC Public Service

Engagement score of 66.

No target

80

60

40

20

0

Engagement score

73 66

BCUC BC Public Service

Work Environment Survey Results (2015)


35


6. Total Expenditure per Capita

Total Expenditure per Capita

($/capita) is the BCUC’s total

expenditure in a given fiscal year

divided by the population of British

Columbia at the end of that fiscal

year. Real values are used measured

in F2017 dollars. The population

is obtained from the Population

Estimates web page on the BC Stats

website.

The intent of this performance

measure is to provide information to

stakeholders regarding the BCUC’s

total annual expenditure relative to the

population of British Columbia.

No target

2.0

1.6

1.2

0.8

0.4

0.0

$ per capita

1.64

F2010

1.44

F2011 F2012

1.81

F2013

1.73

F2014

1.45

F2015 F2016

1.67

F2017

1.61

Average

1.551.57

No target

0.020

0.015

0.010

0.005

0.000

$ per gigajoule

0.0164

F2010

0.0149

F2011 F2012

0.0185

F2013

0.0156

F2014

0.0144

F2015 F2016

0.0181

F2017

0.0161

Average

0.01670.0146

Cost of Regulation per Capita

Energy Regulation Expenditure per Gigajoule7. Energy Regulation Expenditure per Gigajoule

Energy Regulations Expenditure per

Gigajoule ($/GJ) is a calculation

of the BCUC’s total expenditure

(excluding expenditure related to

the Insurance Corporation of British

Columbia) for a given fiscal year,

divided by the amount of domestic

energy delivered by regulated

utilities in the previous calendar

year. Real values are used measured

in F2017 dollars.

This indicative financial performance

measure serves similar purposes

as the previous financial measure.

It drives the BCUC to monitor

expenditures while maintaining the

flexibility to incur costs, given unique

situations.

This accountability drives the BCUC to monitor its

expenditure, while the lack of a specific target provides the

flexibility to incur reasonable costs given unique situations.

It also increases transparency for stakeholders by

expressing the cost of the BCUC’s energy regulation

expenditure relative to the amount of domestic

energy delivered.



36

Mandatory Reliability Standards Metrics

Mandatory Reliability Standards (MRS) help

ensure the reliability and security of the bulk

power system in North America. The 2007

British Columbia Energy Plan stated that,

because B.C.’s transmission system is part of a

much larger, interconnected grid, B.C. needs to

work with other jurisdictions to maximize the

benefits of interconnection, remain consistent

with evolving North American reliability

standards, and ensure B.C.’s infrastructure

remains capable of meeting customer needs.

The BCUC’s role is to approve reliability

standards it deems suitable for adoption in B.C.

and to monitor and enforce compliance with

these standards for the entities registered with

the BC MRS Program. The BCUC is responsible

for the issuance of orders pertaining to entity

registration, the confirmation of Alleged

Violations and the acceptance of Mitigation

Plans. The BCUC also accepts the Find, Fix,

Track processing of Possible Violations and

recognizes Attestations of Mitigation Plan

Completion as compliance filings for the BC

MRS Program. The BCUC administered the

following items in the past year:

Violations

Confirmed Violations 4

Violations Processed Under Find, Fix, Track 3

Mitigation Plans

Mitigation Plans Accepted 25

Attestations of Mitigation Plan

Completion Accepted

34

Registration

New Entity Registration 2

Changes to Functional Registration 12

Deregistration 5

There were also several changes to the BC MRS

legislation that are worth noting. The Rules of

Procedure for Reliability Standards in B.C. (ROP)

were amended twice in F2017. In addition to

minor housekeeping changes:

• BCUC Order R-28-16 approved

revisions Appendix 2: Penalty

Guidelines, to include a B.C. penalty

process; and

• BCUC Order R-12-17, approved

revisions to Appendix 1: Registration

Manual, to include amended

registration criteria that generally

align with the North American

Electric Reliability Corporation

(NERC) Statement of Compliance

Registry Criteria.


37


Business Plan Project Update

The BCUC’s 2016-19 Business Plan sets out the

goals, strategies and initiatives that will enable

us to become more efficient and effective

through a strong employee and Commissioner

workforce that executes the BCUC’s mandate

collaboratively with engaged stakeholders. It

marks a renewed focus in the organization

towards more transparent and accountable

performance.

Underlying these strategies and initiatives is

the recognition that we must ensure that the

current culture of pride in the BCUC is sustained

by staff and Commissioners. A key objective is to

reduce silo thinking and increase communication

and collaboration across working groups to

improve our efficiency and effectiveness, and

enhance consistency in decision making.

The BCUC’s F2017 Implementation Plan sets

out 15 initiatives towards three goals aimed at

improving overall efficiency and effectiveness.

The BCUC’s progress on the 15 Implementation

Plan initiatives is reported on pages 38 – 40.


Improve Effectiveness and Efficiency

Initiative Complete review and revision of

Participant Assistance/Cost Award (PACA)

guidelines and conversion to rules.

Completion August 2016

Deliverables New PACA Guidelines Approved

August 31, 2016 (G-72-07).

Initiative Commence review of the decision

reconsideration process and establish related

rules.

Completion March 2017

Deliverables The project team and scope

definition was under consideration by BCUC

management at the end of the fiscal year.

Initiative Complete internal resource allocation

review and implement required changes,

including necessary recruitment.

Completion N/A

Deliverables Rescheduled until completion of the

organizational effectiveness assessment.

Initiative Recruit a Chief Operating Officer in

accordance with the 2015 revision to the Utilities

Commission Act.


Deliverables Engaged external services in the

recruitment of the Chief Operating Officer and

finalized the short list. Recruitment efforts were

continued and completed in F2018.

Goal 1


38

Initiative Provide leadership and team-building

training for senior management.


Deliverables Leadership and team-building

training for senior management included

attending workshops in Navigating Challenging

Conversations, Building Teams that Trust,

Resilience and Change, and Promoting

Empowerment in a Culture of Change.

Initiative Working with government, recruit

additional Commissioners with necessary,

diverse and high-quality skill sets/competencies.


Deliverables Consulted with Board Resourcing

and Development Office to develop a

framework to recruit Commissioners with

the necessary skills and competencies to be

successful.

Initiative Develop an in-house knowledge-

sharing framework to leverage internal

expertise.

Completion April 2016

Deliverables The framework was developed

internally and was presented at an all-staff

meeting.

Strengthen Internal Communication and Collaboration

Initiative Continue performance measurement

work to develop internal measures and targets.


Deliverables Compiled data to complete first

performance measures report.

Initiative Develop better internal awareness of

our Vision, Mission and Values.


Deliverables Vision, Mission and Values are now

included on job postings, and work is underway

to display these within the BCUC offices.

Initiative Commence planning for staff team-

building workshops.


Deliverables Staff team-building workshops

included: Navigating Challenging Conversations,

Building Teams that Trust, Resilience and

Change, and Promoting Empowerment in a

Culture of Change.

Goal 2

Goal 1 continued


39


Engage Stakeholders

Initiative Continue performance measurement

work to develop methods to obtain stakeholder

feedback on the BCUC’s performance.


Deliverables Stakeholder feedback

questionnaire completed.

Initiative Begin planning to develop a public

relations strategy to address issues such as

public engagement, public notice channels and

use of social media.

Completion September 2016

Deliverables Engaged consultants who

developed and delivered a communications plan.

Initiative Ensure Participant Assistance/Cost

Awards (PACAs) are provided in a timely and

consistent manner.


Deliverables 90 percent of PACAs were issued

in 60 days or less, with an average PACA cycle

time of 28 days.

Initiative Ensure complaints and enquiries are

responded to in a timely manner.


Deliverables 86 percent of complaints were

responded to in under five days, with an average

response time of three days.

Initiative Work with the provincial government

towards agreement on financial management.

Completion N/A

Deliverables Work was initiated towards an

agreement on financial management but was

not completed, as government is no longer

entering into memorandums of understanding

with tribunals.

Goal 3



40


The BCUC is committed to transparency in its cost recovery practices and in its reporting of expenses.

The BCUC is authorized to recover costs from

regulated entities by fixing levies according to

section 125 of the Utilities Commission Act and

parameters set out in Levy Regulation, BC Reg.

283/88.

Most costs are recovered by way of a “per

gigajoule” levy assessed on each regulated utility,

based on the amount of energy the utility sold in

the previous calendar year (calculation is provided

below). Entities that do not sell power, such as

ICBC, are billed according to a set rate that is

reviewed to ensure appropriate annual regulatory

costs are applied. Recoveries are also collected

from intra-provincial pipeline companies, upstream

gas processors and natural gas marketers.

The BCUC also recovers the costs of proceedings

directly from regulated entities, including

expenditures attributable to public hearings and

other proceedings under the Utilities Commission

Act. Direct recoveries have varied significantly

from year to year, depending on the number and

duration of regulatory hearings and inquiries.

Summary of 2016/2017 Recoveries and ExpensesTotal Recoveries $ 9,261,507.71

Less Expenses $ 8,028,475.42

Over Recovery $ 1,233,032.291

Recoveries

Commission recoveries are listed on the following pages. Corresponding

levy order for the figures is G-82-16. If applicable, over recoveries, deferred

recoveries or expenses are applied as a credit or debit to the regulated

entities in the levy order the following fiscal year.

Levy Calculation for 2016/2017 2016/2017 Forecasted Expenses $ 8,946,562.00

2016/2017 Forecasted Strategic Initiatives $ 201,250.00

Less 2016/2017 Forecasted Direct Recoveries $ (1,200,000.00)

Less 2016/2017 Over Recovery $ (1,342,004.21)

$ 6,605,807.79

Less Fixed Annual Fees:

Natural Gas Marketers $ (9,000.00)

Intra-Provincial Pipeline Companies & Upstream Gas Processors $ (18,000.00)

Insurance Corporation of British Columbia $ (700,000.00)

2016/2017 Net Forecasted Expenses to be recovered through the Levy $ 5,878,807.79

Divided by gigajoules of energy sold in the previous calendar year ÷ 385,070,363.00

Levy = $0.0152668404/GJ

1 To be carried forward and returned to the regulated utilities by way of the F2018 Levy as a credit.



42


BCUC RecoveriesAmounts Recovered ($) Amounts Recovered ($)

2015/2016 2016/2017

British Columbia Hydro and Power Authority $ 2,693,533.42 2,723,237.93

Cal-Gas Inc. 324.88 294.87

Creative Energy Vancouver Platforms Ltd. 18,473.54 13,245.06

Corix Multi-Utility Services Inc.

Gas 929.14 969.44

Electric 852.00 916.01

UBC - 9.82

UniverCity NUS 155.99 219.83

Corporation of the City of Nelson 3,363.94 3,343.44

Dockside Green Energy 92.03 90.29

FortisBC Alternative Energy Services Inc. 254.82 538.82

FortisBC Inc. 137,436.87 139,325.19

FortisBC Energy Inc.

Lower Mainland, Vancouver Island, Whistler, Revelstoke 2,566,702.52 2,837,128.56

Fort Nelson Division 9,636.45 8,564.70

FortisBC Energy (Vancouver Island) Inc. 283,702.24 -

FortisBC Energy (Whistler) Inc. 10,576.59 -

Hemlock Utility Services Limited 88.14 76.33

Insurance Corporation of British Columbia 700,000.00 700,000.00

Pacific Northern Gas (includes Granisle Grid) 58,415.85 62,834.54

Pacific Northern Gas (N.E.) Ltd.

Dawson Creek and Fort St. John 71,647.81 66,551.67

Tumbler Ridge 12,171.20 14,419.79

Port Alice Gas Inc. 156.25 126.20

River District Energy Limited Partnership 65.00 106.87

Big White Gas Utility Ltd. 506.57 435.24

Stargas Utilities Ltd. 582.76 572.48

Sun Peaks Utilities Co., Ltd. 1.16 1,103.24

Sun Peaks Utilities Co., Ltd. Levy Correction 1,159.10 -

The Yukon Electrical Company Limited 44.07 45.80

$ 6,570,872.34 6,574,156.12

2 Creative Energy Vancouver Platforms Inc.’s final payment was provided in F2017-18

3 Big White Gas Utility Ltd.’s final payment was provided in F2017-18

2

3

43


Licenses for Natural Gas MarketersAmounts Recovered ($) Amounts Recovered ($)

2015/2016 2016/2017

Access Gas Services Inc. $ 1,500.00 1,000.00

AltaGas Ltd. 1,000.00 -

Bluestream Energy Inc. 1,500.00 1,000.00

Direct Energy (BC) Ltd. 1,500.00 1,000.00

Just Energy (BC) Limited 1,500.00 1,000.00

Planet Energy (BC) Corp. 1,500.00 1,000.00

Smart Energy (BC) Ltd. - -

Summit Energy (BC) LP 1,000.00 1,000.00

Superior Energy 1,500.00 -

$ 11,000.00 6,000.00

Intra-Provincial Pipelines and Common Gas Processors

Amounts Recovered ($) Amounts Recovered ($)

2015/2016 2016/2017

Canadian Natural Resources Limited $ 1,000.00 1,000.00

Canadian Natural Resources Limited - Inga Oil Pipeline 1,000.00 1,000.00

Trans Mountain (Jet Fuel) Inc. 1,000.00 1,000.00

Plateau Pipeline - Blueberry 1,000.00 1,000.00

Plateau Pipeline - Northeast B.C. & Boundary Lake 1,000.00 1,000.00

Plateau Pipeline - Sunset Prairie 1,000.00 1,000.00

Plateau Pipeline - Taylor to Dawson Creek 1,000.00 1,000.00

Plateau Pipeline - Western System 1,000.00 1,000.00

Spectra Energy - Boundary Lake 1,000.00 1,000.00

Spectra Energy - Jedney I 1,000.00 1,000.00

Spectra Energy - Jedney II 1,000.00 1,000.00

Spectra Energy - Midwinter 1,000.00 1,000.00

Spectra Energy - Peggo 1,000.00 1,000.00

Spectra Energy - Sunrise 1,000.00 1,000.00

Spectra Energy - Sunrise 1,000.00 1,000.00

Spectra Energy - Tooga 1,000.00 1,000.00

Spectra Energy - West Doe & Hwy Processing & Pipeline Facilities 1,000.00 1,000.00

Spectra Energy - West Doe & Hwy Transportation & Processing Facilities 1,000.00 1,000.00

$ 18,000.00 18,000.00



44


Miscellaneous and Total RecoveriesAmounts Recovered ($) Amounts Recovered ($)

2015/2016 2016/2017

BCUC Levies Collected $ 6,570,872.34 6,574,156.12

Licenses for Natural Gas Marketers 11,000.00 6,000.00

Intra-Provincial Pipelines and Common Gas Processors 18,000.00 18,000.00

Recovery of Proceeding Costs from Utilities 1,192,351.53 1,346,886.24

Less: GST Transferred to Provincial Government (18,534.07) (25,801.46)

Previous Year Over or Under Recovery 760,958.01 1,342,004.21

Miscellaneous 141.60 262.60

Total Recoveries $ 8,534,789.41 9,261,507.71

BCUC Expenditures2015/2016 2016/2017

Salaries & Benefits $ 4,513,507.82 4,744,933.58

Operating Costs 1,896,349.19 2,215,408.93

Professional Services 782,928.19 1,068,132.91

Total Expenditures $ 7,192,785.20 8,028,475.42

Over or Under Recovery Carried Forward to Next Fiscal Year 1,342,004.21 1,233,032.29

45




46

Shannon Wall Centre Rental Apartments Limited Partnership

Application for a Certificate of Public Convenience and Necessity for the Shannon Estates Thermal Energy Systems

Order C-4-16 dated April 21, 2016

On February 5, 2016, the Shannon Wall Centre

Rental Apartments Limited Partnership filed

an application for a Certificate of Public

Convenience and Necessity (CPCN) to own and

operate the thermal energy system plant at

the rental property known as Shannon Mews

& Apartments, under BCUC's Thermal Energy

Systems Regulatory Framework Guidelines for

Stream B. The application followed a previous

denial for a Stream A exemption under the

Thermal Energy Systems Regulatory Framework

Guidelines in 2015 due to the specific nature of

the project.

Following a written hearing process, the BCUC

granted the CPCN for the Shannon Estates

Thermal Energy System, pursuant to sections

45 and 46 of the Utilities Commission Act

(UCA). An exemption from section 44.1 of the

UCA pertaining to long-term resource and

conservation planning for the Shannon Estates

Thermal Energy System was also approved.


2015 Price Risk Management Application

Order E-10-16 and Decision dated June 17, 2016

On December 23, 2015, FortisBC Energy Inc.

(FEI) filed its 2015 Price Risk Management

Application. The Application included requests

for approval of the implementation of

enhancements to FEI’s quarterly commodity

rate setting mechanism and the implementation

of a medium-term hedging strategy.

On June 17, 2016, with regard to the BCUC’s

guidelines for quarterly commodity rate setting

(set out in letters L-5-01 and L-40-11), the

BCUC approved FEI’s proposed changes to its

Mainland, Vancouver Island and Whistler service

areas. The BCUC also approved FEI’s proposed

three-year medium term fixed-price hedging

strategy with predefined market price targets

and maximum volume limits for the three-year

period ending March 31, 2019. Extending the

hedging program beyond March 31, 2019 was

denied.

FortisBC Inc.

Annual Review for 2016 Rates All Injury Frequency Rate Compliance Filing

Order G-44-16 and Reasons for Decision dated April 1, 2016

On January 7, 2016, the BCUC issued Order

G-202-15 approving permanent 2016 rates

for FortisBC Inc. (FBC). The reasons for

decision attached to Order G-202-15 included

a discussion of the service quality indicators,

with particular focus on results for the All

Injury Frequency Rate (AIFR) that were below

threshold. The BCUC made no finding on the

question of serious degradation of service;

however, it directed FBC to file its 2015 actual

AIFR results as soon as they were available and

indicated that the BCUC would make further

determinations after the actual results were

filed.

On February 12, 2016, FBC submitted its AIFR

Compliance Filing. The BCUC sought from

interveners their comments on this filing and,

on April 1, 2016, issued Order G-44-16 directing

FBC to address its 2015 service quality and/or

penalties in its next Annual Review filing, which

was anticipated to take place in the summer or

fall of 2016.


47


British Columbia Hydro and Power Authority

2015 Rate Design Application – Cost of Service Study and Rate Class Segmentation Negotiated Settlement Agreement

Order G-47-16 dated April 11, 2016 and Settlement Agreement dated March 31, 2016

On September 24, 2015, the British Columbia

Hydro and Power Authority (BC Hydro)

filed its 2015 Rate Design Application that

included its cost of service study and rate class

segmentation. By Order G-12-16, the BCUC

established a negotiated settlement process

(NSP) to review the proposed cost of service

study and rate class segmentation, separate

from the main rate design application.

Following the NSP, a final negotiated settlement

agreement was circulated and letters of

support were received from all participants. On

March 31, 2016, the settlement agreement was

submitted to the Panel for approval.

On April 11, 2016, the BCUC issued Order G-47-16

accepting the negotiated settlement agreement

pertaining to BC Hydro’s F2016 cost of service

study and rate class segmentation.


Application for a Certificate of Public Convenience and Necessity for Additional Capital and Amended Rates for UniverCity Neighbourhood Utility Service on Burnaby Mountain

Order G-48-16A dated April 11, 2016

On January 20, 2016, Corix Multi-Utility Services

Inc. (Corix) filed a new application in response

to Commission Order G-215-15, informing the

BCUC that it had elected not to proceed with

the project as approved by the order. Instead,

Corix elected to change its capital plan, resulting

in an increase to the UniverCity Neighbourhood

Utility System (NUS) levelized rate of 1.6 percent

(Application).

The BCUC reviewed the Application, evidence

and submissions from registered parties and

on April 11, 2016, issued Order G-48-16A. The

BCUC approved the updated rate base, revenue

requirements and rate schedules as outlined

in the Application, and varied the approvals

granted in Directive 6 of Order G-215-15 to

reflect the updates to each of these categories.

Directive 3 through 5 of Order G-215-15 were

rescinded, as the directives were no longer

applicable under the revised capital plan.

Insurance Corporation of British Columbia

2015 Revenue Requirements Application

Order G-74-16 and Decision dated May 27, 2016

On August 31, 2015 and October 15, 2015, the


(ICBC) filed, in two parts, its 2015 Revenue

Requirements Application for Universal

Compulsory Automobile Insurance (Basic

insurance) for the policy year commencing

November 1, 2015 (Application). ICBC requested

a 5.5 percent Basic insurance rate increase for

the 2015 Policy Year.

The BCUC accepted the actuarial analysis

prepared by ICBC in support of its Application

of the requested 11.2 percent increase to cover

Basic insurance costs. As required by Special

Direction IC2 as amended in October 2015,

the BCUC excluded a 5.8 percent Loss Cost

Forecast Variance in full to set Basic insurance

rates in 2015. The resulting 5.5 percent Basic

insurance rate increase was approved for the

2015 Policy Year.



48


W.A.C. Bennett Dam Riprap Upgrade Project

Order G-78-16 dated May 27, 2016 and Reasons for Decision dated July 13, 2016

On November 13, 2015, BC Hydro filed the

W.A.C. Bennett Dam (Dam) Riprap Upgrade

Project application and statement of capital

expenditures with the BCUC, requesting

acceptance of the expenditure schedule

(Application).

The Application addressed inadequate long-

term erosion protection of the Dam located

on the Peace River approximately eighteen

kilometres west of the town of Hudson’s Hope

within Treaty 8 First Nations’ territories.

The BCUC found that BC Hydro’s consultation

with First Nations had been adequate and

that the project expenditure schedule was in

the public interest, with the exception of the

temporary stockpiling of riprap for possible

future use. Therefore, on May 22, 2016, by Order

G-78-16, the BCUC accepted the main part of

the expenditure schedule and rejected the part

concerning the stockpiling of riprap for possible

future use.

FortisBC Inc.

Application for Treatment for Major Project Capital Expenditures under the Multi-Year Performance Based Ratemaking Plan for 2014-2019

Order G-80-16 and Reasons for Decision dated June 3, 2016

On March 15, 2016, FortisBC Inc. (FBC) filed

an application for the Treatment of Capital

Expenditures for major projects that had been

proposed as a Certificate of Public Convenience

and Necessity (CPCN) project by FBC under

its Performance Based Ratemaking Plan (PBR

Plan) for 2014 through 2019 (Application).

The major projects were defined as Upper

Bonnington Old Units Refurbishment, Ruckles

Substation Upgrade, Grand Forks to Warfield

Fibre and Grand Forks Terminal Station

Transformer Addition (the Projects).

The BCUC established a comment process

for the review of the application and

received comments from the BC Sustainable

Energy Association and the Sierra Club

BC, the Commercial Energy Consumers

Association of British Columbia, the British

Columbia Old Age Pensioners’ Organization

et al. and Mr. N. Gabana.

On June 3, 2016, the BCUC determined that

clarification of the treatment of the Projects

within the PBR Plan was required and issued

Order G-80-16 with accompanying reasons for

decision directing FBC to:

• File an application for a CPCN for the Grand

Forks to Warfield Fibre and Grand Forks

Terminal Station Transformer Addition

projects should those projects proceed.

• Seek approval of the Ruckles Substation

Upgrade and Upper Bonnington Old Units

Refurbishment projects, as part of the PBR

Annual Review.

• To the extent that the Projects are granted

a CPCN or pre-approval in the PBR Annual

Review, FBC is approved to flow through the

actual capital expenditures outside of the

formula-driven capital under the PBR Plan.

Project final costs will be reviewed as part

of the PBR Annual Review before adding the

capital expenditures to rate base on January

1 of the year following the in-service date of

the Projects.


49


Creative Energy Vancouver Platforms Inc.

Application for Approval of the Restated and Amended Northeast False Creek and Chinatown Neighbourhood Energy Agreement

Order G-88-16 and Decision dated June 16, 2016

On April 17, 2015, Creative Energy Vancouver

Platforms Inc. (Creative Energy) applied for

approval of a Neighbourhood Energy Agreement

between Creative Energy and the City of

Vancouver (Prior NEA) and the granting of a

Certificate of Public Convenience and Necessity

(CPCN) to construct and operate a new

Neighbourhood Energy System to serve new

developments in the Northeast False Creek

(NEFC) and Chinatown neighbourhoods of

Vancouver. By Order C-12-15, the BCUC granted

a CPCN for the NEFC area excluding the

Chinatown area. However, it did not approve

the Prior NEA for reasons relating to a Carbon

Reduction Rider and Cost Premium Cap, and

noted that while there is no specific clause in

the Prior NEA that provides for mandatory

connection, the wording of the agreement

suggests that the BCUC is approving the

Neighbourhood Energy Bylaw (NE Bylaw). The

BCUC also denied a Connection Agreement and

noted that Creative Energy may resubmit it with

its next rate application (Prior Decision).

In response to Order C-12-15, on February 5,

2016, Creative Energy applied for approval of a

Restated and Amended NEFC and Chinatown

NEA (Amended NEA), filed a Bylaw Enactment

Agreement (BEA) (for information only) and

explained that it was consulting customers

and may file a revised Connection Agreement

with its next rate application or separately. The

Decision and accompanying Order G-88-16 were

issued on June 16, 2016 wherein the BCUC did

not approve the applied-for franchise.

The BCUC found that the applied-for franchise

was constituted by the rights, privileges and

concessions set out in the Amended NEA, the

BEA and the NE Bylaw, and, consistent with

the Prior Decision, did not find the applied-for

franchise to be acceptable in its current form, as

it implies Commission approval of the provisions

in the NE Bylaw as well as those provisions

contained in the Amended NEA. In addition,

the Panel did not approve the inclusion of the

Chinatown area in the franchise agreement,

placing considerable weight on the comments

and findings in the Prior Decision. In respect to

the Carbon Reduction Rider, the Cost Premium

Cap and the Connection Agreement, the

BCUC found that the revisions contained in the

Amended NEA provided sufficient remedies to

the Prior Decision’s findings.


Proposal for Depreciation and Net Salvage Rate Changes

Order G-119-16 and Reasons for Decision dated July 28, 2016

On February 29, 2016, FortisBC Energy Inc.

(FEI) filed additional information and analysis

on its proposed depreciation and net salvage

rate changes, as directed by the BCUC in Order

G-193-15 (Application).

On July 28, 2016, the BCUC issued Order G-119-

16 with accompanying reasons for decision. The

BCUC approved FEI’s proposed depreciation

and net salvage rate changes, effective January

1, 2017. Additionally, the BCUC directed FEI to

include the following information as part of

its next Depreciation Study: (i) an analysis of

the costs and benefits of converting from the

Average Service Life group depreciation method

to the Equal Life Group depreciation method,

including calculations of the rate impact; and (ii)

a discussion of the group depreciation method

used by each of the major regulated gas utilities

in Canada.



50


Application for its Common Equity Component and Return on Equity for 2016

Order G-129-16 and Decision dated August 10, 2016

FortisBC Energy Inc. (FEI) requested approval

of a capital structure of 40 percent equity and

60 percent debt and a return on common equity

(ROE) of 9.5 percent for 2016 by application to

the BCUC dated October 2, 2015. This request

compares to FEI’s allowed ROE at the time of

the application of 8.75 percent and common

equity component of 38.5 percent.

The evidence for this proceeding included two

parts: company evidence on FEI’s business and

financial risks, and expert evidence on financial

models used to estimate the fair return to FEI’s

investors.

Following the oral hearing on the expert

evidence and the written hearing on the

company evidence, the BCUC determined that

FEI’s common equity component shall be set

at 38.5 percent and its ROE shall be set at 8.75

percent. This cost of capital is effective as of

January 1, 2016 and will remain in effect until

otherwise determined by the BCUC. The BCUC

also determined that the use of the automatic

adjustment mechanism to estimate ROE shall

be suspended indefinitely.

Pacific Northern Gas Ltd.

2016-2017 Revenue Requirements Application for the PNG-West and Granisle Service Areas

Order G-131-16 and Reasons for Decision dated August 10, 2016

On November 30, 2015, Pacific Northern

Gas Ltd. (PNG) filed its 2016-2017 Revenue

Requirements Application seeking, among

other things, approval to increase 2016 delivery

rates (Application). By Order G-207-15 dated

December 18, 2015, the BCUC approved the

delivery rates and the Rate Stabilization

Adjustment Mechanism rider set forth in the

Application on an interim and refundable

basis, effective January 1, 2016. By Order

G-13-16 dated February 4, 2016, the BCUC

established a written public hearing process

that directed PNG to file its updated application

on February 29, 2016, and included two rounds

of Commission and intervener information

requests, followed by written final and reply

arguments.


G-131-16 with accompanying reasons for

decision approving, among other things, the

2016 and 2017 revenue requirements and

resultant delivery rate increases for PNG on a

permanent basis, subject to the adjustments

identified by PNG in information requests and

in argument, as well as to the adjustments

directed by the BCUC. The BCUC did not

accept PNG’s proposed method for developing

Residential and Small Commercial customer

load forecasts for the purpose of calculating

the annual revenue deficiency/(sufficiency)

and the resulting delivery rate changes in

revenue requirements applications. The BCUC

directed PNG to recalculate its load forecasts

using its existing load forecasting method, and

to use those forecasts to calculate the 2016

and 2017 revenue deficiencies and resultant

delivery rate changes. PNG was directed

to file the revised load forecasts and rate

calculations as part of its compliance filing

containing its final regulatory schedules with

the BCUC by no later than 30 days from

the date of Order G-131-16. PNG was also

directed to file its next revenue requirements

application for a period of two years

encompassing a test period of 2018 and 2019.


51



2016-2017 Revenue Requirements Application for the PNG (N.E.) Service Areas

Order G-132-16 and Reasons for Decision dated August 10, 2016

On November 30, 2015, Pacific Northern Gas

(N.E.) Ltd. [PNG (N.E.)] filed its 2016-2017

Revenue Requirements Applications for the

Fort St. John/Dawson Creek (FSJ/DC) and

Tumbler Ridge (TR) service areas seeking,

among other things, approval to increase 2016

delivery rates (Applications). By Order G-208-15

dated December 18, 2015, the BCUC approved

the delivery rates and the Rate Stabilization

Adjustment Mechanism riders set forth in the

Applications on an interim and refundable basis,

effective January 1, 2016. By Order G-14-16

dated February 4, 2016, the BCUC established

a written public hearing process that directed

PNG (N.E.) to file its updated applications on

February 29, 2016, and included two rounds

of Commission and intervener information

requests, followed by written final and reply

arguments.



decision approving, among other things, the

2016 and 2017 revenue requirements and

resultant delivery rate increases for the PNG

(N.E.) FSJ/DC and TR services areas on a

permanent basis, subject to the adjustments

identified by PNG (N.E.) in information requests

and in argument, as well as to the adjustments

directed by the BCUC. The BCUC did not accept

PNG (N.E.)’s proposed method for developing

Residential and Small Commercial customer

load forecasts for the purpose of calculating the

annual revenue deficiencies/(sufficiencies) and

the resulting delivery rate changes in revenue

requirements applications. The BCUC directed

PNG (N.E.) to recalculate its load forecasts

using its existing load forecasting method, and

to use those forecasts to calculate the 2016 and

2017 revenue deficiencies and resultant delivery

rate changes. PNG (N.E.) was directed to file

the revised load forecasts and rate calculations

as part of its compliance filing containing its

final regulatory schedules with the BCUC by

no later than 30 days from the date of Order

G-132-16. PNG (N.E.) was also directed to file

its next revenue requirements applications for a

period of two years encompassing a test period

of 2018 and 2019.


Application for Biomethane Energy Recovery Charge Rate Methodology

Order G-133-16 and Decision dated August 12, 2016

On August 28, 2015, FortisBC Energy Inc. (FEI)

filed an application with the BCUC seeking

approval of a non-cost-based Biomethane

Energy Recovery Charge (BERC) rate

methodology with two renewable natural gas

(RNG) offerings, a mechanism for transferring

costs and unsold biomethane volumes out of

the Biomethane Variance Account (BVA) for

recovery from non-RNG customers, and revised

reporting requirements.

By Order G-147-15, the BCUC established a

regulatory review process that included direction

for FEI to file supplementary information, a

round of written information requests and

a procedural conference. Following written

argument by the parties, the BCUC issued

Order G-60-16 requesting supplemental written

argument in regard to the need for including

floor and/or ceiling prices in the BERC rate

methodology.



52

On August 12, 2016, the BCUC issued its decision

and accompanying Order G-133-16 approving

the Short Term Contract BERC rate, as applied

for, equal to the BCUC-approved January 1

Commodity Cost Recovery Charge plus the

current applicable carbon tax plus a premium

of $7.00 per gigajoule and approving the

Long Term Contract BERC rate at a $1.00 per

gigajoule discount to the Short Term Contract

BERC rate subject to three conditions. The

BCUC also approved the amortization of the

forecast December 31 balance in the BVA, net

of any transfer of unsold biomethane inventory

and remaining supply costs, for recovery through

the delivery rates of all non-bypass customers.

FEI is to file a comprehensive Assessment

Report as set out in the Decision to enable the

BCUC to determine whether the revised BERC

rate methodology is achieving the objective of

minimizing the rate impact on customers who

have not voluntarily elected to purchase RNG.


Application to Extend the Gas Supply Mitigation Incentive Program for the Period November 1, 2016 to October 31, 2019

Order G-141-16 dated August 29, 2016

On May 6, 2016, FortisBC Energy Inc. (FEI) filed

an application to seek approval of an extension

of the Gas Supply Mitigation Incentive Program

(GSMIP) (Application). In the Application, FEI

proposed continuing the GSMIP model, which

was approved by Order G-174-13, for a three-

year period from November 1, 2016 to October

31, 2019. Additionally, FEI proposed two revisions

in the GSMIP Term Sheet with respect to

the fixed adjustment amount and reporting

requirements.

The BCUC reviewed the Application and sought

written comments from stakeholders. The

BCUC approved the proposed GSMIP extension

by Order G-141-16 and accepted a revised 2016-

2019 GSMIP Term Sheet by letter L-27-16.


2015 System Extension Application

Order G-147-16 and Decision dated September 16, 2016

On June 30, 2015, FortisBC Energy Inc.

(FEI) applied to the BCUC for approval of

changes to its mains extension test (MX Test),

customer connection policies and related

reporting requirements. The BCUC reviewed

the Application, two rounds of Commission

and intervener information requests, written

arguments, one round of Panel information

requests, and supplemental written arguments

and found that changes to FEI’s MX Test,

customer connection policies and related

reporting requirements were warranted.

For the MX test, the Panel accepted FEI’s

proposals, including extending the discounted

cash flow period to 40 years, using a 10-

year forecast period for certain customer

attachments, and applying a sliding-scale

overhead methodology to calculate the

overhead rate. The BCUC also approved FEI’s

proposal for a $1.0 million annual system

extension fund as a pilot program commencing

in 2017 through December 31, 2020. For FEI’s

customer connection policies, the BCUC

approved FEI’s proposal to increase the service

line cost allowances.


53


For reporting, the BCUC accepted the use of

a modified rate impact analysis to evaluate

the economic impact of main extensions and

infill customers on existing ratepayers. FEI

was directed to report annually on extensions

and the system extension fund, and to file an

updated rate impact analysis by June 30, 2020,

incorporating the results to the end of 2019.

Sun Peaks Utilities Co., Ltd.

Application for Approval of a Delivery Rate Increase

Order G-149-16 dated September 22, 2016

On June 13, 2016, Sun Peaks Utilities Co., Ltd.

(SPUCL) filed an application for approval of

an increase of $0.33 per gigajoule in the Gas

Delivery Charge effective August 1, 2016, for all

Rate Groups (Residential, Small Commercial

and Large Commercial) (Application). SPUCL

also applied for approval of certain changes to

its Terms and Conditions of the Gas Tariff and

updates to fees charged for specific services.

The Application was reviewed through a written

hearing process that included one round of

information requests. No interveners registered

for the SPUCL proceeding.

The BCUC issued Order G-149-16 on September

22, 2016, approving an increase of $0.33

per gigajoule in the Sun Peaks’ Gas Delivery

Charge, effective August 1, 2016, resulting in the

following new rates:

a. Rate Group 1 Residential:

$2.8175 per gigajoule

b. Rate Group 2 Small Commercial:


c. Rate Group 3 Large Commercial:


The BCUC also approved the requested changes

to the Terms and Conditions as filed in the

Application, with the exception of section 2.4.

The proposed wording in section 2.4 of the

Terms and Conditions was denied on the basis

that no persuasive evidence was provided

to demonstrate that it is within the BCUC’s

jurisdiction to approve this section.

Big White Gas Utility Ltd.

Application for Approval of Changes to Propane Supply Agreement

Order G-150-16 dated September 22, 2016

On August 2, 2016, Big White Gas Utility Ltd.

(Big White) filed an application for approval of

changes to its Propane Supply Agreement to

amend the current Minimum Monthly Charge,

effective September 1, 2016, from $45.00

for all customers to $45.00 for Commercial

customers and $10.00 for Residential customers

(Application).

The Application was reviewed through a written

review process, which provided an opportunity

for customer comments on the Application. No

customer comments were received on the Big

White Application.

On September 22, 2016, the BCUC issued

Order G-150-16 approving Big White’s

application to amend the current Minimum

Monthly Charge from $45.00 for all customers

to $45.00 for Commercial customers and

$10.00 for Residential customers, effective

September 1, 2016.



54


Application for Reconsideration and Variance of Order G-88-16

Order G-151-16 and Reasons for Decision dated September 26, 2016

On July 6, 2016, Creative Energy Vancouver

Platforms Inc. (Creative Energy) applied for

Reconsideration and Variance of Commission

Order G-88-16, which denied approval of

Creative Energy’s amended Neighbourhood

Energy Agreement (NEA) with the City of

Vancouver. Reconsideration may be warranted

where it can be shown that the BCUC made an

error in fact or in law or where new evidence has

come to light. The BCUC found that an error in

fact or law had not been made and reiterated

that the BCUC has not approved Creative

Energy’s NEA with the City of Vancouver

because approval would grant a monopoly over

the supply of heat and hot water in Northeast

False Creek and Chinatown, which is not in the

public interest. The reconsideration and variance

application was denied by the BCUC by Order

G-151-16 dated September 26, 2016.

While the BCUC considered the City of

Vancouver’s stated objective to establish a

district energy system in Northeast False Creek

and Chinatown area, in not approving this

agreement, the Panel’s intent is not to prevent

the City of Vancouver from achieving its energy

policy objectives.

The BCUC released its first decision on Creative

Energy’s application for approval of its NEA with

the City of Vancouver in December 2015. In that

decision, the BCUC granted Creative Energy

approval to build and operate the Northeast

False Creek Neighbourhood Energy System, an

extension of Creative Energy’s gas fired district

energy system that currently provides heat in

the downtown core and into the False Creek

flats. However, the BCUC did not approve the

NEA between Creative Energy and the City of

Vancouver at that time.

In March 2016, after the BCUC required Creative

Energy to reapply with specific changes to its

NEA, the BCUC released a second decision,

again denying the revised application on the

grounds that it did not substantively deal with

the concerns of the panel from the original

decision, specifically, considerations in the NEA

that referenced exclusive end-use provisions in a

City of Vancouver bylaw on the Northeast False

Creek Neighbourhood Energy System. On July

6, 2016, Creative Energy asked for the BCUC to

reconsider their decisions from December 2015

and March 2016 and by Order G-151-16 with

accompanying reasons for decision, the BCUC

denied Creative Energy’s application to vary

Order G-88-16.


2017-2018 Revenue Requirements and Rates Application for the Fort Nelson Service Area

Order G-162-16 and Reasons for Decision dated November 9, 2016

On June 30, 2016, FortisBC Energy Inc. (FEI)

submitted its 2017-2018 Revenue Requirements

and Rates Application for the Fort Nelson

service area seeking, among other things,

Commission approval of delivery rates for the

2017 and 2018 test periods (Application).

On November 9, 2016, the BCUC issued Order


decision.

The BCUC approved the following: (a) FortisBC

Energy Inc.’s requested delivery rate increase of

6.86 percent effective January 1, 2017 and an


55


additional delivery rate increase of 6.94 percent

effective January 1, 2018 for the Fort Nelson

service area; (b) The Revenue Stabilization

Adjustment Mechanism Rate Rider to be set

at $0.268 per gigajoule effective January 1,

2017; (c) Adoption of updated depreciation

and net salvage rates as provided in the

Application, effective January 1, 2017; and (d)

The establishment of the following deferral

accounts:

a. A rate base deferral account for the 2017-

2018 Revenue Requirement Application costs

with an amortization period of two years

commencing in 2017;

b. A rate base deferral account for the 2016

Cost of Capital Application costs with

an amortization period of three years

commencing in 2017;

c. A rate base deferral account for the 2017

Rate Design Application costs; and

d. A non-rate base deferral account to transfer

a portion of the 2017 revenue deficiency to

2018.

Also, the BCUC approved a delay to the

disposition of the non-rate base Fort Nelson

First Nations Right-of-Way Agreement deferral

account to the next revenue requirement

proceeding.

The BCUC rejected the British Columbia Old

Age Pensioners’ Organization et al.’s proposal

to record in a deferral account the annual

variances between forecast and actual Shared

Services fees allocated from FEI to the FEI Fort

Nelson service area.

In addition, FEI was directed to file the

supporting calculations for the residential

and small commercial use per customer and

customer additions forecasts in its future

revenue requirement applications for the Fort

Nelson service area and to file as a compliance

filing, the finalized financial schedules for the

2017 and 2018 test periods no later than 60

days from the date of Order G-162-16.


2016-2017 Revenue Requirements Application and Rate Design for Northeast False Creek Hot Water Service

Order G-167-16 and Decision dated November 18, 2016

On April 1, 2016, Creative Energy Vancouver

Platforms Inc. (Creative Energy) filed with the

BCUC its 2016-2017 Revenue Requirements

Application requesting an increase in steam

service (Steam Service) rates effective

May 1, 2016; an interim increase effective

January 1, 2017; to set initial rates for Northeast

False Creek hot water service (NEFC Service)

effective August 1, 2016; and for approval of a

rate design (Application).

For Steam Service, the BCUC approved the

6.23 percent rate increase effective May 1, 2016

but denied the recovery of the 2016 revenue

deficiency from January 1 to March 31, 2016,

representing the period prior to the filing of the

Application. The BCUC approved the request to

set rates effective January 1, 2017, on an interim

and refundable basis pending the BCUC’s review

of the updated 2017 load forecast; however,

the request for an interim rate increase of 7.15

percent was denied and Creative Energy was

directed to recalculate the 2017 rate impact

reflecting the adjustments outlined in the

Decision. The BCUC also directed changes to the

calculation of the fuel Cost Adjustment Charge

and set it at $9.92 per thousand pounds (M#)

effective January 1, 2017 on an interim basis.



56

For NEFC Service, the BCUC denied the rate

design as filed and directed that a 40 percent

fixed and 60 percent variable rate design

be implemented. The BCUC approved the

NEFC rates for 2016 and 2017, subject to the

adjustments outlined in the Decision, effective

the date the BCUC approves the Terms and

Conditions for NEFC.

Spirit Bay Utilities Ltd.

Application for Exemption pursuant to section 88(3) of the Utilities Commission Act

Order G-175-16 and Reasons for Decision dated December 1, 2016

On June 1, 2016, Spirit Bay Utilities Ltd. filed an

application with the BCUC for an exemption

pursuant to section 88(3) of the Utilities

Commission Act (UCA) from the application

of Part 3, Regulation of Public Utilities, with

respect to the proposed provision of electricity,

gaseous propane, and a heated or cooled fluid

produced by an ocean thermal energy system.

The BCUC determined that if Spirit Bay Utilities

Ltd. were to provide the proposed energy

services for compensation, it would be a public

utility and its application for an exemption was

denied. Spirit Bay Utilities Ltd.’s alternative

request that it be declared a municipality or

regional district for purposes of the UCA was

also denied. Spirit Bay Utilities Ltd. was ordered

to produce a plan to ensure compliance with the

UCA on a prospective basis.

Superior Propane

Rate Application for Seascapes Propane Grid System

Order G-172-16 and Reasons for Decision dated November 28, 2016

On February 17, 2016, Superior Propane

filed with the BCUC a rate application for

the Seascapes propane grid system seeking

approval of its tariff and changes to its rate

schedule (Application). On November 28,

2016, the BCUC issued Order G-172-16 with

accompanying reasons for decision. The BCUC’s

determinations included establishing the

revenue requirement for 2016, approving the

rate structure, establishing the cost of propane

calculations and approving Superior Propane’s

gas tariff for its operation at the Seascapes

Development. The BCUC also directed that

future rate increases will be determined using

the Vancouver B.C. Consumer Price Index.

Superior Propane is required to submit various

annual reporting and rate-related filings

outlined in the reasons for decision.


Annual Review for 2017 Delivery Rates


By letter dated July 15, 2016, FortisBC Energy

Inc. (FEI) proposed a regulatory timetable for its

annual review for 2017 delivery rates. By Order

G-122-16, the BCUC established a regulatory

timetable that included the anticipated date

for FEI to file its annual review materials

(Application).

On December 7, 2016, the BCUC issued Order


decision which approved, among things, FEI’s

request to maintain 2017 delivery rates at the

approved 2016 levels, before consideration of

rate riders, effective January 1, 2017. The BCUC

also approved the establishment of the 2017

Revenue Surplus deferral account to record the

2017 revenue surplus resulting from maintaining

2017 delivery rates at existing 2016 levels. The

BCUC directed FEI to accrue carrying charges

on the 2017 Revenue Surplus deferral account


57


based on FEI’s approved weighted average cost

of capital. FEI was further directed to propose

an amortization period for the 2017 Revenue

Surplus deferral account as part of its annual

review for 2018 delivery rates application.

The BCUC approved the Rate Stabilization

Deferral Account, Phase-In Rate, and Revenue

Stabilization Adjustment Mechanism riders for

2017 in the amounts set out in the Application.

The following deferral account requests

were approved: (i) creation of a rate base

deferral account for the All-Inclusive Code of

Conduct/Transfer Pricing Policy regulatory

proceeding with a one year amortization

period commencing in 2017; (ii) a five-year

amortization period for the Emissions

Regulations deferral account commencing in

2017; and (iii) discontinuance of the non-rate

base deferral account for the Kingsvale-Oliver

Reinforcement Project Feasibility Costs.

FEI’s application for a three-year amortization

for the 2016 Cost of Capital Application

deferral account was not approved and FEI

was directed to provide additional information

and explanations for the amount of expert/

consultant costs and legal costs incurred for the

2016 Cost of Capital proceeding in its annual

review for 2018 delivery rates application.

FEI was also directed to provide additional

information on its capital expenditures and its

head count/full-time equivalent staffing levels,

as outlined in the reasons for decision, in its

annual review for 2018 delivery rates application.

FortisBC Inc.

Net Metering Program Tariff Update Application


On April 15, 2016, FortisBC Inc. (FBC) submitted

its Net Metering Tariff Update Application

seeking Commission approval of: (i) changes to

Rate Schedule 95 (RS 95) to clarify the intent of

the Net Metering Program; (ii) the use of a kWh

bank to carry forward Net Excess Generation

(NEG) for an annual period with compensation

at the end of the annual period ending on

March 31 of each year; and (iii) compensating

customers for that remaining unused NEG at

the British Columbia Hydro and Power Authority

Rate Schedule 3808 Tranche 1 rate instead of

the excess being valued at rates specified in

the applicable rate schedule and credited to

the customer’s account as a dollar value that

contributes to the overall financial standing

of the account. In addition, FBC requested

Commission acceptance of its approach to the

billing calculation method.

By Order G-199-16 with accompanying reasons

for decision dated December 29, 2016, the BCUC

approved FBC’s proposed changes to the RS 95

tariff that clarify that new customers will not

be accepted into the Net Metering Program if

their proposed generating capacity exceeds their

anticipated annual consumption, rejected the

proposed change in the purchase price of Net

Excess Generation, rejected FBC’s application to

create a kWh bank to carry forward Net Excess

Generation, and accepted FBC’s proposed

interpretation of the billing method. FBC was

directed to submit to the Panel proposed

changes to RS 95 within 90 days of the date of

Order G-199-16 to clarify that:

• Customers who are already participants

in the Net Metering Program and wish to

remain in the Net Metering Program must

not increase their generating capacity

without prior approval of FBC, which shall

be granted on the same basis as new

customer evaluations for entry into the Net

Metering Program; and



58

• RS 95 customers cannot be removed from

the Net Metering Program solely on the

basis of producing annual Net Excess

Generation.


2015 Price Risk Management Application

Order E-10-16 and Decision and Letter L-15-16 dated June 17, 2016

On December 23, 2015, FortisBC Energy Inc.

(FEI) filed with the BCUC its 2015 Price Risk

Management Application (Application). The

Application included requests for approval of

the implementation of enhancements to the

quarterly commodity rate setting mechanism,

as it applies to FEI, and the implementation of a

medium-term hedging strategy for FEI.

On June 17, 2016, the BCUC issued its decision

and accompanying Order E-10-16 and letter

L-15-16. With regard to the BCUC’s guidelines

for quarterly commodity rate setting, the

BCUC approved FEI’s proposed changes as

they pertain to FEI’s Mainland, Vancouver

Island and Whistler service areas. Specifically,

a commodity rate change cap of +/- $1.00

per gigajoule will apply for a maximum of two

consecutive quarters so long as the Commodity

Cost Reconciliation Account balance remains

within +/- $60 million after tax and criteria

are established for determining when a longer

24-month amortization period is appropriate.

The BCUC also approved FEI’s proposed

three-year medium term fixed-price hedging

strategy with predefined market price targets

and maximum volume limits for the three-year

period ending March 31, 2019. The BCUC denied

extension of the hedging program beyond

March 31, 2019.


2015 Rate Design Application

Order G-5-17 and Module 1 Decision dated January 20, 2017. Decision Errata dated February 6, 2017

On September 14, 2015, BC Hydro filed with

the BCUC the first module of a rate design

application (2015 RDA) that included approvals

sought related to residential, general service and

transmission service rates as well as approval

to amend BC Hydro’s Electric Tariff terms and

conditions.

The regulatory process included intervener and

interested party registration (36 interveners

and 6 interested parties registered in the

proceeding), two rounds of information requests

(IRs), a procedural conference, the filing of

intervener evidence, information requests on

intervener evidence, written arguments, and an

oral hearing. In addition, a number of approvals

sought were addressed through the following

expedited review processes:

• By Order G-16-16 and accompanying reasons

for decision dated February 9, 2016, the

BCUC approved BC Hydro’s proposed

amendments to certain Medium General

Service (MGS) and Large General Service

(LGS) rate schedules, including approval of

the pricing for customers without historical

baselines from 85/15 pricing to 100 percent

Part 1 Pricing. This expedited review process

included one round of IRs and written final

and reply arguments.

• By Order G-17-16 and accompanying reasons

for decision dated February 9, 2016, the

BCUC approved a two-year freshet rate

pilot effective for the period March 1, 2016 to

October 31, 2017.


59


• The expedited review process for the two-

year freshet rate pilot included one round of

IRs and a Streamlined Review Process held

on January 25, 2016.

• By Order G-20-16 and accompanying

reasons for decision dated February 19, 2016,

the BCUC approved amendments to certain

transmission rate schedules. This expedited

review process included one round of IRs and

written final and reply arguments.

• By Order G-47-16 dated April 11, 2016, the

BCUC approved the Negotiated Settlement

Agreement pertaining to BC Hydro’s F2016

Cost of Service Study and proposed Street

Lighting rate class segmentation. The

Negotiated Settlement Process was held on

March 7 and March 8, 2016.

The BCUC considered the Application, evidence

and submissions from the parties and on

January 20, 2017, the BCUC issued its Decision

and Order G-5-17. The BCUC approved, effective

April 1, 2017, the Residential Inclining Block (RIB)

Pricing Principles for each of F2017-F2019, BC

Hydro’s rate proposals for Small General Service,

MGS and LGS customers, the Transmission

Service Rate Schedule 1823 Pricing Principles

for each of F2017-F2019, and BC Hydro’s

proposals regarding its Electric Tariff Terms and

Conditions, including standard charges.

The BCUC directed BC Hydro to phase out

the Residential E-Plus rate program over five

years, commencing April 1, 2017, and to submit

a compliance filing within 30 days of the date of

the decision outlining a proposal for achieving

the five-year phase-out period and that results

in rates being charged to E-Plus customers at

the end of the five-year phase-out period that

equate to other B.C. residential customers. The

BCUC further directed BC Hydro to waive the

requirement of having an alternative heating

system in working order and to eliminate the

possibility of service being interrupted during

the five-year phase-out period.

The BCUC made the following determinations

regarding a number of British Columbia Old

Age Pensioners’ Organization et al.’s (BCOAPO)

requests with respect to proposals for low-

income customers:

• BCOAPO’s request to establish an essential

services usage block (ESUB) rate for

qualified low-income ratepayers is denied.

• The establishment of a pilot Crisis

Intervention Fund for residential customers

is approved.

• BCOAPO’s proposals to amend BC Hydro’s

Electric Tariff to exempt low-income

customers from the minimum reconnection

and account charge and to waive security

deposits for low-income customers are

denied.

• BCOAPO’s proposal to exempt low-income

customers from late payment charges and

to ban the use of external credit scores is

denied.

• BC Hydro is directed to provide an analysis

to the BCUC of the costs and benefits

associated with BCOAPO’s requested

customer segmentation analysis and data

collection and reporting within six months

of the establishment of the low-income

advisory group.



60

FortisBC Inc.

Annual Review for 2017 Rates

Order G-8-17 and Reasons for Decision dated January 20, 2017 and Order G-11-17 dated January 27, 2017

By letter dated July 15, 2016, FortisBC Inc. (FBC)

proposed a regulatory timetable for its annual

review for 2017 rates. By Order G-123-16, the

BCUC established a regulatory timetable that

included the anticipated date for FBC to file its

annual review materials (Application).


G-8-17 with accompanying reasons for decision

that, among other things, granted acceptance

of the capital expenditure schedules for the

Ruckles Substation Rebuild project and the

Upper Bonnington Old Units Refurbishment

project. The BCUC also approved FBC’s

deferral account requests, which included the

establishment of five non-rate base deferral

accounts. The BCUC directed that the 2017

rates, previously approved by Order G-180-16

dated December 5, 2016, shall remain interim

pending the completion of the FBC Demand

Side Management for 2017 Expenditures

proceeding. FBC was further directed to

address various issues arising as part of its

annual review for 2018 rates application.

On January 27, 2017, subsequent to the BCUC’s

issuance of its decision regarding FBC’s

Application for Acceptance of Demand Side

Management for 2017 Expenditures, the BCUC

approved, by Order G-11-17, FBC’s application

for a general rate increase of 2.76 percent

to be applied to all components of rates for

all customer classes on a permanent basis,

effective January 1, 2017.

FortisBC Inc.

Application for Acceptance of Demand Side Management Expenditures for 2017

Order G-9-17 and Reasons for Decision dated January 25, 2017

On August 8, 2016, FortisBC Inc. (FBC) applied

to the BCUC for acceptance of demand side

management expenditures for 2017.


G-9-17 with accompanying reasons for decision

accepting FBC’s demand side management

expenditure schedule in Appendix A of the

Application setting out expenditures of up to

$7.6 million for 2017.

FortisBC Inc.

Application for a Certificate of Public Convenience and Necessity for the Corra Linn Dam Spillway Gate Replacement Project

Order C-1-17 and Reasons for Decision dated February 7, 2017

On June 29, 2016, FortisBC Inc. (FBC) submitted

an application for a Certificate of Public

Convenience and Necessity (CPCN) to the

BCUC for the construction and operation of

14 upgraded replacement spillway gates and

improvements to the associated gate structures

at the Corra Linn Dam.

The upgrades will increase the ability of the

Corra Linn Dam to withstand earthquakes and

floods reducing downstream risks to people,

infrastructure and the environment. The scope

of the work includes the:

• Replacement of the 84-year-old steel

spillway gates with new and more robust

gates;

• Reinforcement of the gate lifting towers and

bridges;


61


• Refurbishment of the gate lifting hoists; and

• Replacement of the embedded gate parts

(gate guides, sill, etc.) that are set in the

dam’s concrete structure.

FBC estimates the capital cost for the Corra

Linn Dam Spillway Gate Replacement Project to

be $62.3 million and the in-service date to be in

December 2020.

The BCUC found the Corra Linn Dam Spillway

Gate Replacement Project to be in the public

interest and granted FBC a CPCN for the

project by Order C-1-17 on February 7, 2017.

Port Alice Gas Inc.

Application for Exemption from Part 3 of the Utilities Commission Act for the Operation of the Propane Air Grid Assets and Sale of Propane in the Village of Port Alice

Order G-21-17 dated February 22, 2017

On July 22, 2016, Port Alice Gas Inc. (PAG) filed

an application for an exemption from Part 3 of

the Utilities Commission Act (UCA) in relation to

PAG’s operation of the propane air grid assets

and sale of propane in the Village of Port Alice,

B.C. (Exemption Application). A written review

of the Exemption Application was established

on August 15, 2016 and the BCUC requested

approval from the Minister responsible for the

administration of the Hydro and Power Authority

Act to grant the exemption on November 18,

2016.

On February 8, 2017, the Minister responsible

for the administration of the Hydro and Power

Authority Act issued Ministerial Order No. 044

granting advance approval to the BCUC to

exempt PAG from the requirements of Part 3

of the UCA, except for sections 25, 38, 42, 43

and 44.

On February 22, 2017, pursuant to section 88(3)

of the UCA and Ministerial Order No. 044,

the BCUC exempted PAG with respect to its

operation of the propane air grid assets and sale

of propane in the Village of Port Alice from Part

3 of the UCA, except for sections 25, 38, 42, 43

and 44.


All-Inclusive Code of Conduct and Transfer Pricing Policy Application

Order G-25-17 and Reasons for Decision dated March 1, 2017

On June 30, 2016, FortisBC Energy Inc. (FEI)

filed an application with the BCUC for the

approval of its draft all-inclusive Code of

Conduct (CoC) and Transfer Pricing Policy

(TPP) application. Concurrent to the FEI CoC

and TPP application, an affiliate of FEI, Aitken

Creek Gas Storage (ACGS), filed its all-inclusive

CoC and TPP application. After inviting a

round of submission on the review process,

the BCUC advised parties that FEI’s CoC and

TPP application would be reviewed first and,

following its decision, the BCUC would then

proceed with a separate review of ACGS’ CoC

and TPP application.

Order G-25-17 with accompanying reasons for

decision was issued on March 1, 2017. The BCUC

approved FEI’s draft all-inclusive CoC and TPP

subject to the following changes: FEI is directed

to update the Definitions sections of the

proposed CoC/TPP to include the definition of

customer as being synonymous with ratepayer;

and FEI is directed to amend the last sentence

of Principle ii of the Code of Conduct Principals

to read as follows: The control of FEI Customer

Information should not provide an inappropriate

competitive advantage to an Affiliate.



62

Port Alice Gas Inc.

Application for Approval to Increase the Basic Charge and Facility Charge

Order G-34-17 dated March 15, 2017

On December 7, 2015, Port Alice Gas Inc.

(PAG) applied for approval of an increase

in the Basic Charge from $6.00 per month

to $0.40 per day (nominally $12.00 per

month) and to increase the Facility Charge to

$0.389 per litre of propane for all customers,

effective January 1, 2016 (Application). The

Application was subsequently suspended until

a determination could be made on PAG’s July

22, 2016 application for an exemption from

Part 3 of the Utilities Commission Act (UCA) in

relation to PAG’s operation of the propane air

grid assets and sale of propane in the Village

of Port Alice.

On May 6, 2016, PAG filed a Variance Request

of Order G-211-15 and notice related to section

88(3) of the UCA requesting approval to: (i)

decrease the interim Facility Charge, (ii) increase

the interim Basic Charge for Commercial

Customers, and (iii) an extension of its

application for relief under section 88(3) of the

UCA to June 30, 2016 (Variance Request).

On February 22, 2017, the BCUC issued Order

G-21-17 approving PAG’s exemption from Part

3 of the UCA, except for sections 25, 38, 42, 43

and 44. Order G-34-17 was issued on March 15,

2017, pursuant to sections 59 to 61 of the UCA,

wherein the BCUC:

• Approved an increase to the Basic Charge

of $6.00 per month by $0.40 per day

(nominally $12.00 per month) effective

January 1, 2016 to February 21, 2017.

• Approved an increase to the Facility Charge

to $0.389 per litre of propane effective

January 1, 2016 to May 31, 2016.

• Approved a decrease to the Facility Charge

from $0.389 per litre to $0.289 per litre of

propane, effective June 1, 2016 to February

21, 2017.

• Approved an increase to the Basic Charge

for Commercial Customers from $0.40 per

day to $0.50 per day, effective June 1, 2016

to February 21, 2017.


63



A – Gas Supply Marketing C – Certificates of Public Convenience and Necessity E – Energy Supply

Contracts F – Participant Assistance / Cost Awards G – General Orders L – Commission Letters

R Mandatory Reliability Standards


64

Access Gas Services Inc.

A-6-16 Application to Renew Gas Marketer Licence for the period November 1, 2016 through October 31, 2016

Axsiom GeoEnergy (Richmond) Corporation

G-194-16 Registration of Stream A Thermal Energy Systems – The Pier and Parc Riviera

Bakerview EcoDairy Ltd.

G-71-16 Application for Exemption from Part 3 of the Utilities Commission Act for Electric Vehicle Charging Service Providers


E-5-16 Filing of an Electricity Purchase Agreement between BC Hydro and the Kwadacha Nation

F-14-16 Application for Debt Management Regulatory Account – Participant Assistance/Cost Award

F-18-16 Application for the W.A.C. Bennett Dam Riprap Upgrade Project – Participant Assistance/Cost Award

F-26-16 Application for the W.A.C. Bennett Dam Riprap Upgrade Project – Participant Assistance/Cost Award

F-32-16 Application for an Interim Participant Assistance/ Cost Award Denied in the BC Hydro SAP Expenditure Inquiry

G-47-16 2015 Rate Design Application – Cost of Service Study Negotiated Settlement Agreement

G-50-16 2015 Rate Design Application – Amended Regulatory Timetable

G-54-16 Application for the W.A.C. Bennett Dam Riprap Upgrade Project – Regulatory Timetable

G-58-16 British Columbia Utilities Commission Action on Complaint (A. Dix)

G-61-16 2015 Rate Design Application – Amended Regulatory Timetable

G-62-16 Inquiry of Expenditures related to the adoption of the SAP Platform – Regulatory Timetable

G-63-16 Review of the Regulatory Oversight of Capital Expenditures and Projects

G-76-16 Application for Rate Schedule 1892 – Freshet Energy Baselines

G-78-16 Application for the W.A.C. Bennett Dam Riprap Upgrade Project – Reasons for Decision

G-81-16 Inquiry of Expenditures related to the adoption of the SAP Platform – Interim Participant Assistance/Cost Award

G-86-16 Capital Expenditures and Projects Review – Procedural Conference

G-103-16 Application for the Tilbury Island Liquefied Natural Gas Facility Tariff Supplement No. 91 – Electricity Supply Agreement and Tariff Supplement No. 92 – Load Interconnection Agreement with FortisBC Energy Inc.

G-112-16 Application to Extend the Filing Date for the Interior to Lower Mainland Project Final Report

G-124-16 Smart Meter Safety Complaint

G-128-16 2015 Rate Design Application – Reasons for Decision regarding Commercial Energy Consumers Association of British Columbia’s Rate Pilot Proposal

G-130-16 Application for F2017 to F2019 Revenue Requirements – Regulatory Timetable

G-144-16 Application for F2017-F2019 Revenue Requirements – Amended Regulatory Timetable

G-146-16 Inquiry of Expenditures related to the adoption of the SAP Platform – Amended Timetable

G-154-16 Review of the Regulatory Oversight of Capital Expenditures and Projects – Procedural

Conference



65


G-174-16 Review of the Regulatory Oversight of Capital Expenditures and Projects – Scope of Review

G-186-16 Application for a Bypass Rate for West Fraser Mills Ltd. (Pacific Inland Resources Division) Special Electric Service Agreement – Tariff Supplement No. 93

G-198-16 Application to Cease Operations of Burrard Thermal Generating Station

L-9-16 Review of Information Technology Expenditures – BCUC Response to A. Dix Complaint

L-28-16 Filing of Electricity Purchase Agreements – Akolkolex and Soo River – Request for Submissions

R-14-16 Mandatory Reliability Standard BAL-001-2 Assessment Report

R-15-16 Mandatory Reliability Standards Assessment Report No. 9 – Regulatory Timetable

R-32-16A Mandatory Reliability Standards Assessment Report No. 9 – Final Order

R-40-16 Application for Extension to file the Mandatory Reliability Standards Assessment Report No. 10

E-1-17 Section 71 Filing of the Electricity Purchase Agreements – Akolkolex and Soo River

E-4-17 Filing of Electricity Purchase Amendment Agreements for East Toba and Montrose, Kwalsa, Upper Stave and Tyson Creek Hydro Projects

F-5-17 2015 Rate Design Application – Participant Assistance/Cost Award

G-4-17 Application for the Supply Chain Applications Project – Regulatory Timetable

G-5-17 2015 Rate Design Application – Decision

G-7-17 Application for F2017-F2019 Revenue Requirements – Regulatory Timetable

G-10-17 Application for Variance to Order C-4-80 – Extension to filing date for the Interior to Lower Mainland Final Project Report

G-20-17 Application for F2017-F2019 Revenue Requirements – Regulatory Timetable


G-32-17 Supply Chain Application – Regulatory Timetable

G-39-17 Application for F2017-F2019 Revenue Requirements – Interim rates

G-43-17 Extension Request regarding the Compliance Filing pursuant to Order G-177-10 Final Report for the Hugh

L Keenleyside Spillway Gates Project

G-45-17 Application for Transmission Service Rate Customer Baseline Loads F2016 and F2017

G-46-17 Application for F2017-F2019 Revenue Requirements – Interim rates

G-49-17 Application for Salmon River Diversion Ceasing of Operations – Regulatory Timetable

G-50-17 Application for F2017-F2019 Revenue Requirements – Procedural Order

R-23-17 Change in registration with the BC MRS program – Deregistration from Purchase Selling Entity Function and Load Serving Entity Function


G-82-16 Recovery of Commission Costs for the 2016/17 Fiscal Year

G-143-16 Participant Assistance/Cost Award Guidelines revised August 31,

2016

G-191-16 Class Exemption for BC Hydro Customers that Resell Electricity under Certain Lease Arrangements

R-19-16 BC Mandatory Reliability Standards Program – MRS Regulation Amendment



66

R-28-16 Rules of Procedure Revised Appendix 3: Penalty Guidelines for BC Mandatory Reliability Standards

R-39-16 2017 Implementation Plan for Monitoring Compliance with BC Reliability Standards

G-38-17 Class Exemption for BC Hydro Customers that Resell Electricity Under Certain Lease Arrangements – Regulatory Timetable

R-9-17 Application to Revise 2017 Audit Schedule to remove Catalyst Paper-Powell River

R-12-17 British Columbia Mandatory Reliability Standards Program – Revisions to the Rules of Procedure for Reliability Standards in British Columbia

Bear Mountain Wind Limited Partnership

R-42-16 Application to Change Registration required for compliance with Mandatory Reliability Standards

Big White Gas Utility Ltd.

G-136-16 Application for Changes to Propane Supply Agreement – Regulatory Timetable

G-150-16 Application for Changes to the Propane Supply Agreement – Decision

Bluestream Energy Inc.


Cape Scott Wind LP

R-17-16 Application to Deregister for the function of Transmission Owner under the BC MRS program

Catalyst Paper

R-20-16 Mitigation Plan (Version 3) Acceptance for PRC-008-0_R2 for the Crofton Division

R-21-16 Mitigation Plan (Version 3) Acceptance for PRC-017-0_R2 for the Crofton Division

R-29-16 Application to Change Registration required for compliance with Mandatory Reliability Standards for the Crofton Division

R-30-16 Application to Change Registration required for compliance with Mandatory Reliability Standards for the Port Alberni Division

R-43-16 Application to Change Registration required for compliance with Mandatory Reliability Standards for the Powell River Division

R-2-17 Mitigation Plan (Version 2) Acceptance for PRC-008-0_R2 for the Port Alberni Division

R-3-17 Mitigation Plan (Version 2) Acceptance for PRC-017-0_R2 for the Port Alberni Division

Coast Mountain Hydro Limited Partnership

R-34-16 Mitigation Plans (Version 1) Acceptance for FAC-003-3_R3_R7


F-10-16A Application for a Certificate of Public Convenience and Necessity for Additional Capital and Amended Rates for UniverCity Neighbourhood Utility Service on Burnaby Mountain

G-48-16A Application for a Certificate of Public Convenience and Necessity for Additional Capital and Amended Rates for UniverCity Neighbourhood Utility Service on Burnaby Mountain

G-40-17 Application for a Certificate of Public Convenience and Necessity for the Burnaby Mountain District Energy Utility – Regulatory Timetable


F-15-16 Application for Approval of the Restated and Amended Northeast False Creek and Chinatown Neighbourhood Energy Agreement – Participant Assistance/Cost Award

F-27-16 Application for Reconsideration and Variance of Order G-88-16 – Participant Assistance/Cost Award

F-29-16 Application for Approval of 2016-2017 Revenue Requirements and Rate Design for Northeast False Creek – Participant Assistance/Cost Award


67


G-49-16 Application for Approval of 2016-2017 Revenue Requirements and Rate Design for Northeast False Creek – Regulatory Timetable and Notice

G-51-16 Application to Vary Decision Order G-98-15 to Extend the Filing Date of the Fuel Cost Adjustment Charge

G-66-16 Application for Approval of 2016-2017 Revenue Requirements and Rate Design for Northeast False Creek Hot Water Service – Filing Extension Request for a Phase I Rate Design Application

G-67-16 Application for Approval of 2016-2017 Revenue Requirements and Rate Design for Northeast False Creek Hot Water Service – Regulatory Timetable

G-70-16 Application for Approval of 2016-2017 Revenue Requirements and Rate Design for Northeast False Creek Hot Water Service – Amended Regulatory Timetable

G-79-16 Application for 2016-2017 Revenue Requirements and Rate Design for Northeast False Creek Hot Water Service – Procedural Order

G-88-16 Application for Approval of the Restated and Amended Northeast False Creek and Chinatown Neighbourhood Energy Agreement – Decision

G-92-16 Application for 2016-2017 Revenue Requirements and Rate Design for Northeast False Creek Application – Regulatory Timetable

G-109-16 Application for Approval of Northeast False Creek Connection Agreement (Terms and Conditions) – Adjournment of Proceeding

G-114-16 Application for Reconsideration and Variance of Order G-88-16 – Phase 2

G-151-16 Application for Reconsideration and Variance of Order G-88-16 – Reasons for Decision

G-153-16 Application for Approval of Northeast False Creek Connection Agreement (Terms and Conditions) – Regulatory Timetable

G-167-16 Application for 2016-2017 Revenue Requirements and Rate Design for NEFC Hot Water Service – Decision

G-169-16 Application for Approval of Northeast False Creek Connection Agreement (Terms and Conditions) – Regulatory Timetable

G-170-16 Application for Phase 1 Rate Design Fuel Costs

G-184-16 Application to Amend and Restate the Credit Facilities Agreement

L-19-16 Compliance Filing pursuant to Letter L-33-15 – 2016/17 Annual Contracting Plan

G-13-17 Application for 2016-2017 Revenue Requirements and Rate Design for North East False Creek Hot Water Service - Compliance Filing to Orders G-167-16 and G-170-16

G-28-17 Application for Stream A Registration for the 1480 Howe Street Thermal Energy System

G-41-17 Application for Stream A Registration for the 2200 Kingsway Thermal Energy System

G-42-17 Application for Approval of Northeast False Creek Connection Agreement – Reasons for Decision

Direct Energy (B.C.) Limited

A-8-16 Application to Renew Gas Marketer Licence for the period November 1, 2016

through October 31, 2016

FortisBC Alternative Energy Services Inc.

G-53-16 Application for Compliance Filing to Orders G-146-15A and G-213-15 and Variance and Reconsideration to Orders G-100-14, G-146-15A and G-213-15 for Thermal Energy Service to Delta School District Number 37

G-113-16 Application to Extend the Filing Date for the Compliance Filing required by Order G-53-16

G-1-17 Application for Stream A Registration for the Aperture Thermal Energy System



68

G-19-17 Application for Stream A Registration for the Seylynn II Thermal Energy System

FortisBC Inc.

E-11-16 Filing of Energy Supply Contracts with Powerex Corporation

F-11-16 Annual Review for 2016 Rates All Injury Frequency Rate Compliance Filing – Participant Assistance/Cost Award

F-12-16 Application for Self-Generation Policy – Participant Assistance/Cost Award

F-13-16 Application for a Certificate of Public Convenience and Necessity for the Kootenay Operations Centre – Participant Assistance/Cost Award

G-44-16 Annual Review for 2016 Rates All Injury Frequency Rate Compliance Filing – Reasons for Decision

G-59-16 Application for Net Metering Program Tariff Update Regulatory Timetable

G-75-16 Application for Net Metering Program Tariff Update – Amended Regulatory Timetable

G-80-16 Application for Treatment for Major Project Capital Expenditures under the Multi-Year Performance Based Ratemaking Plan for 2014-2019 – Reasons for Decision


G-107-16 Application for a Certificate of Public Convenience and Necessity for the Corra Linn Dam Spillway Gate Replacement Project – Regulatory Timetable

G-123-16 Annual Review of 2017 Rates – Regulatory Timetable


G-135-16 Application for Acceptance of Demand Side Management Expenditures for 2017

G-180-16 Annual Review for 2017 Rates – Interim Rates

G-197-16 2016 Long Term Electric Resource Plan and 2016 Long Term Demand Side Management Plan – Regulatory Timetable and Public Notice

G-199-16 Application for Net Metering Program Tariff Update – Reasons for Decision

L-7-16 Application for Treatment for Major Project Capital Expenditures – Request for Comments and Timetable

L-8-16 Filing of 2016/2017 Annual Electric Contracting Plan (October 2016 – September 2017)

C-1-17 Application for a Certificate of Public Convenience and Necessity for the Corra Linn Dam Spillway Gate Replacement Project –Reasons for Decision

F-1-17 Application for Net Metering Program Tariff Update – Participant Assistance/Cost Award

F-2-17 Application for Acceptance of Demand Side Management Expenditures for 2017 – Participant Assistance/Cost Award

F-3-17 Application for a Certificate of Public Convenience and Necessity for the Corra Linn Dam Spillway Gate Replacement Project – Participant Assistance/Cost Award

F-4-17 Annual Review for 2017 Rates – Participant Assistance/Cost Award

G-8-17 Annual Review for 2017 Rates - Reasons for Decision

G-9-17 Application for Acceptance of Demand Side Management Expenditures for 2017 – Reasons for Decision

G-11-17 Annual Review for 2017 Rates – General Rate increase All Customer Classes

G-14-17 Application for Self-Generation Policy Stage II – Regulatory Timetable

R-22-17 Change in registration with the BC MRS program – Deregistration from Purchase Selling Entity Function and Load Serving Entity Function


69


R-24-17 Mitigation Plan (Version 1) Acceptance for VAR-002-WECC-1_R1


A-2-16 Customer Choice Program Annual General Meeting Cancellation

A-3-16 Application for the Customer Choice Program Cost Recovery – Regulatory Timetable

A-4-16 Application for the Customer Choice Program Cost Recovery – Regulatory Timetable

A-5-16 Application for the Customer Choice Program Cost Recovery – Amended Regulatory Timetable

A-9-16 Application for the Customer Choice Program Cost Recovery – Decision

A-13-16 Customer Choice Program Cost Recovery Compliance Filing to Order A-9-16 – Regulatory Timetable

E-7-16 Filing of Mist Storage Agreement H between FEI and Northwest Natural Gas Company

E-8-16 Filing of Remaining Commodity Baseload Contracts for Summer 2016 (April 2016 to October 2016)

E-9-16 Filing of a GasEDI Base Contract with Black Swan Energy Ltd.

E-10-16 Application for 2015 Price Risk Management – Decision

E-14-16 Section 71 Filing of a GasEDI Base Contract with Absolute Energy Inc.

E-15-16 Section 71 Filing of a GasEDI Base Contract with Sentinel Energy Management Inc.

E-16-16 Section 71 Filing of a GasEDI Base Contract with Cargill, Incorporated

E-17-16 Section 71 Filing of a GasEDI Base Contract with Access Gas Services Inc.

E-19-16 Section 71 Filing of the Commodity Exchange Agreement between Tenaska Marketing Canada and FEI

E-20-16 Section 71 Filing of Natural Gas Supply Contracts for the Commodity and Midstream Portfolios for the 2016/17 Contract Year

E-21-16 Section 71 Filing of Baseload and Seasonal Purchases for Natural Gas Supply Contracts Beyond the 2015/16 Contract Year

F-8-16 Application for Acceptance of the Biomethane Purchase Agreement Between FEI and the City of Surrey and Approval of the Monthly Facility Fee – Participant Assistance/Cost Award

F-17-16 Application for 2015 Price Risk Management – Participant Assistance/Cost Award

F-19-16 Proposal for Depreciation and Net Salvage Rate Changes – Participant Assistance/Cost Award

F-22-16 Application for 2015 System Extension – Participant Assistance/Cost Award

F-23-16 Application to Extend the Gas Supply Mitigation Incentive Program for the Period November 1, 2016 to October 31, 2019 – Participant Assistance/Cost Award

F-24-16 Application for its Common Equity Component and Return on Equity for 2016 – Participant Assistance/Cost

Award

F-25-16 Application for Biomethane Energy Charge Rate Methodology – Participant Assistance/Cost Award

F-28-16 Application for the Customer Choice Program Cost Recovery – Participant Assistance/Cost Award

F-30-16 Application for 2017-2018 Revenue Requirements and Rates for the Fort Nelson service area – Participant Assistance/Cost Award

F-31-16 Annual Review for 2017 Delivery Rates – Participant Assistance/Cost Award

G-52-16 Application for a Code of Conduct and Transfer Pricing Policy for Affiliated Regulated Businesses Operating in a Non-Natural Monopoly Environment Compliance Filing Pursuant to Order G-65-15 – Request for Extension



70

G-57-16 Application for 2015 System Extension – Regulatory Timetable

G-60-16 Application for Biomethane Energy Recovery Charge Rate Methodology – Regulatory Timetable

G-64-16 Application for Expenditures for the Expanded Compressed Natural Gas Fueling Station for Waste Management of Canada Corporation

G-65-16 Application for Proposal for Depreciation and Net Salvage Rate Changes

G-68-16 Application for Common Equity Component and Return on Equity for 2016 – Reasons regarding Sur-reply

G-73-16 Application for Rates for Constructing and Operating a Liquefied Natural Gas Fueling Station under the Province’s Greenhouse Gas Reduction Regulation for Vedder Resources Ltd. at Cool Creek Energy Ltd. (rescinded by G-83-16)

G-83-16 Application for Rates for Constructing and Operating a Liquefied Natural Gas Fueling Station under the Province’s Greenhouse Gas Reduction Regulation for Vedder Resources Ltd. at Cool Creek Energy Ltd.

G-84-16 A Filing regarding the 2016 Second Quarter Report on the Biomethane Variance Account and Biomethane Energy Recovery Charge Rate effective July 1, 2016

G-85-16 Application for Amendments to Rate Schedule 46 Liquefied Natural Gas Sales, Dispensing and Transportation Service effective April 1, 2016

G-91-16 Application for Rates for Constructing and Operating a Compressed Natural Gas Fueling Station under the Province’s Greenhouse Gas Reduction (Clean Energy) Regulation for Canadian Linen and Uniform Services Co. and for SF Disposal Queen Ltd. at FEI’s Operations Centre in Burnaby – SF Disposal Queen Ltd. Interim Rates

G-93-16 Application for Recovery of Price Risk Management Workshop Participant Funding Requests

G-96-16 Application for Rates for Constructing and Operating a Compressed Natural Gas Fueling Station under the Province’s Greenhouse Gas Reduction (Clean Energy) Regulation for Canadian Linen and Uniform Services Co. and for SF Disposal Queen Ltd. at FEI’s Operations Centre in Burnaby – Canadian Linen and Uniform Services Co. Interim Rates

G-99-16 Application for Rates for Constructing and Operating a Liquefied Natural Gas Fueling Station under the Province’s Greenhouse Gas Reduction (Clean Energy) Regulation for Nanaimo Cold Storage and Trucking Ltd. and

for the City of Nanaimo at Mid Island Consumer Services Co-operative – City of Nanaimo Interim Rates

G-100-16 Application for Rates for Constructing and Operating a Liquefied Natural Gas Fueling Station under the Province’s Greenhouse Gas Reduction (Clean Energy) Regulation for Nanaimo Cold Storage and Trucking Ltd. and for the City of Nanaimo at Mid Island Consumer Services Co-operative – Nanaimo Cold Storage and Trucking Ltd. Interim Rates

G-101-16 Application for Rates for Constructing and Operating a Liquefied Natural Gas Fueling Station under the Province’s Greenhouse Gas Reduction (Clean Energy) Regulation for Nanaimo Cold Storage and Trucking Ltd. and for the City of Nanaimo at Mid Island Consumer Services Co-operative – Mid Island Consumer Services Co-operative Interim Rates

G-105-16 Application to extend the Maturity Date of Indebtedness under the FEI Term Credit Agreement

G-108-16 Application for 2017-2018 revenue Requirements and Rates for the Fort Nelson service area

G-111-16 Application to Extend the 2016-2019 Gas Supply Mitigation Incentive Program for the period November 1, 2016 to October 31, 2019


71


G-116-16 Application for Rates and Contract for Liquefied Natural Gas Fueling Service from the Liquefied Natural Gas Fueling Station located at Cool Creek Energy Ltd. for Arrow Transportation Systems Inc.

G-117-16 Application for Rates and Contract for Liquefied Natural Gas Fueling Service from the Liquefied Natural Gas Fueling Station located at Cool Creek Energy Ltd. for Denwill Enterprises Inc.

G-119-16 Application for Proposal for Depreciation and Net Salvage Rate Changes – Reasons for Decision

G-122-16 Annual Review of 2017 Delivery Rates – Regulatory Timetable

G-129-16 Application for Common Equity Component and Return on Equity for 2016 – Decision

G-133-16 Application for Biomethane Energy Recovery Charge Rate Methodology – Decision

G-138-16 Application to Transfer Specific Liquefied Natural Gas Assets to the Natural Gas Rate Base

G-141-16 Application to Extend the Gas Supply Mitigation Incentive Program for the Period November 1, 2016 to October 31, 2019

G-145-16 Filing of the Third Quarter 2016 Gas Cost Report

for the Commodity Cost Reconciliation Account and midstream Cost Reconciliation Account for the Mainland, Vancouver Island and Whistler service areas

G-147-16 Application for 2015 System Extension – Decision

G-152-16 Application to Increase Receipt Point Fuel Gas Percentages effective November 1, 2016

G-156-16 Application for Rates and Contract for Compressed Natural Gas (CNG) Fueling Service from the CNG Fueling Station Located at FEI’s Burnaby Operations Facility for Smithrite Disposal Ltd. – Interim Rates

G-157-16 Application for All-Inclusive Code of Conduct and Transfer Pricing Policy – Regulatory Timetable

G-162-16 Application for 2017-2018 Revenue Requirements and Rates for Fort Nelson service area

G-164-16 Application for Rates and Contract for Compressed Natural Gas (CNG) Fueling Service from the CNG Fueling Station Located at FEI’s Burnaby Operations Facility for Pemberton Transport Co. Ltd. – Interim Rates

G-166-16 Application for Rates and Contract for Compressed Natural Gas (CNG) Fueling Service from the CNG Fueling Station Located at Mid Island Consumer Services

Co-operative for Coldstar Solutions Inc. – Interim Rates

G-173-16 Application for 2017-2018 Revenue Requirements and Rates for the Fort Nelson service area – Variance of Order G-162-16 Rates and Final Financial Schedules Compliance Filing

G-177-16 Filing of the Fourth Quarter 2016 Gas Cost Report for the Commodity Cost Reconciliation Account, Midstream Cost Reconciliation Account Quarterly Gas Costs and Biomethane Energy Recovery Charge for the Mainland, Vancouver Island and Whistler service areas

G-178-16 Filing of the 2016 Fourth Quarter Report on the Gas Cost Reconciliation Account and Gas Cost Recovery Rates for the Fort Nelson service area

G-179-16 Filing of the 2016 Fourth Quarter Gas Cost Report for the Revelstoke service area

G-181-16 British Columbia Utilities Commission Decision and Order G-147-16 – Revised Tariff Pages

G-182-16 Annual Review of 2017 Delivery Rates – Reasons for Decision

G-183-16 Application for a Rate to provide Short-Term Liquefied Natural Gas (LNG) Fueling Services using specified LNG Assets



72

G-185-16 Application for Rates and Agreements for Liquefied Natural Gas (LNG) Fueling Service from the LNG Fueling Station located at Vedder Transport Ltd. for Clark Reefer Lines Ltd. – Permanent Rates

G-187-16 Application for Interim Rates regarding Rate Schedule 46-Liquefied Natural Gas Sales, Dispensing and Transportation Service effective January 1, 2017

L-12-16 Filing of 2016 Second Quarter Gas Cost Report on the Commodity Cost Reconciliation Account and Midstream Cost Reconciliation Account for the Mainland, Vancouver Island, and Whistler service areas

L-13-16 Filing of the 2016 Second Quarter Gas Cost Report on the Gas Cost Reconciliation Account for the Fort Nelson service area

L-14-16 Filing of the 2016 Second Quarter Gas Cost Report on the Gas Cost Reconciliation Account for the Revelstoke service area

L-15-16 Application for 2015 Price Risk Management – Decision

L-16-16 Application to Issue $30 million in Common Shares

L-17-16 Filing of the Annual Contracting Plan (November 2016-October 2017) for Revelstoke

L-20-16 Filing of the 2016/17 Annual Contracting Plan (November 2016-October 2017)

L-22-16 Filing of the 2016 Third Quarter Gas Cost Report for the Revelstoke service area

L-23-16 Filing of the 2016 Third Quarter Gas Cost Report on the Gas Cost Reconciliation Account for the Fort Nelson service area

L-27-16 Gas Supply Mitigation Incentive Program for the Period November 1, 2016 to October 31, 2019 – Order G-141-16 – GSMIP Term Sheet Compliance Filing

L-29-16 Application for Exemption from Order G-161-15 for the ENERGY STAR Portfolio Manager

A-1-17 Customer Choice Program Cost Recovery Compliance Filing to Order A-9-16

C-2-17 Application for an Amending Agreement to the Franchise Agreement between the Corporation of the Village of Salmo and FortisBC Energy Inc.

E-6-17 Section 71 Filing of a GasEDI Base Contract with Saguaro Resources Ltd.

G-3-17 Application regarding the 2017 Core Market Administration Expense Budget

G-6-17 Application for 2016 Rate Design – Regulatory Timetable and Public Notice

G-15-17 Application for Two Percent Increase in Rate Schedule 46 Table of Charges for Liquefied Natural Gas Transportation Service and Table of Charges for LNG Service

G-16-17 Application for Rates and Agreement for Liquefied Natural Gas (LNG) Fueling Service from the LNG Fueling Station located at Denwill Enterprises Inc. for Vedder Transport Ltd. – Permanent Rates

G-18-17A Application for Amended Rates for Compressed Natural Gas Fueling Service between Smithrite Disposal Ltd. and FortisBC Energy Inc. for the 2016 Fueling Station Expansion and Amending Agreement No. 5 for the Fueling Station under the Province’s Greenhouse Gas Reduction Regulation – Interim Rates

G-24-17 Application to Amend the Capital Rate for the Vedder Transport Ltd. (Vedder) Liquefied Natural Gas (LNG) Fueling Station Established in the Third Amending Agreement between FEI and Vedder

G-25-17 Application for All-Inclusive Code of Conduct and Transfer Pricing Policy – Reasons for Decision


73


G-30-17 Application for 2016 Rate Design – Regulatory Timetable

G-31-17 Filing of 2017 First Quarter Gas Cost Report and Rate Changes effective April 1, 2017 for the Revelstoke service area

G-44-17 Application for a Rate to Provide Short-term Liquefied Natural Gas Fueling Services using Specified LNG Assets – Permanent Rate

L-1-17 Application to Amend the 2016-2017 Annual Contracting Plan

L-2-17 Filing of the Gas Supply Mitigation Incentive Program Year End Report for November 2016 – October 2016

L-3-17 Filing of 2017 First Quarter Gas Cost Report for the Mainland, Vancouver Island, and Whistler service areas

L-4-17 Filing of 2017 First Quarter Gas Cost Report for the Fort Nelson service area

FortisBC Midstream Inc.

F-9-16 Application for the Acquisition of the Shares of Aitken Creek Gas Storage ULC – Participant Assistance/Cost Award

Howe Sound Pulp and Paper Corporation

R-13-17 Change in Registration with the BC MRS program – Deregistration from Load Serving Entity Function


F-16-16 Application for 2015 Revenue Requirements – Participant Assistance/Cost Award

G-74-16 Application for 2015 Revenue Requirements – Decision

G-121-16 Application for Basic Insurance Tariff Amendments Application

G-139-16 Application to Amend the Basic Insurance Tariff pursuant to the Motor Vehicle Act Regulations

G-140-16 Application to Amend the Basic Insurance Tariff to take effect with the Implementation of the New Policy Administration System

G-142-16 Application for Revenue Requirements for Universal Compulsory Automobile Insurance effective November 1, 2016 – Regulatory Timetable

G-163-16 Application for Revenue Requirements for Universal Compulsory Automobile Insurance Effective November 1, 2016 – Regulatory Timetable

G-165-16 Application for Revenue Requirements for Universal Compulsory Automobile Insurance Effective November 1, 2016 – Request for Confidentiality

G-188-16 Application to Amend the Tariff pursuant to Order in Council 908 regarding the High-value Vehicle Charge

G-195-16 Application for Revenue Requirements for Universal Compulsory Automobile Insurance Effective November 1, 2016 – Timetable Suspended

L-10-16 Application to Modify Statutory Year-End Reporting Requirements

L-11-16 Filing of Online Claims Services Project Information Technology Capital Report

L-18-16 Filing of the Insurance Business Capability Project Information Technology Capital Report

G-2-17 Application for Revenue Requirements for Universal Compulsory Automobile Insurance effective November 1, 2016 - Reasons for Decision

G-23-17 Application for 2016 Revenue Requirements Application – Regulatory Timetable

G-35-17 Application for Changes in Relation to the Claim-Rated Scale and Amendments to the Basic Insurance Tariff

G-37-17 Application to Transition APV 44 Vintage Motor Vehicle Certificate into New Policy Administration System



74

Innergex Renewable Energy Inc.

R-31-16 Application to Change Registration required for compliance with Mandatory Reliability Standards

R-37-16 Mitigation Plan (Version 1) Acceptance for PRC-005-1_R2

Jimmie Creek Limited Partnership

R-16-16 Application for Registration as Generator Owner and Generator Operator under the BC MRS Program

Just Energy (BC) Limited Partnership


Kyuquot Power Ltd.

G-97-16 Application for Variance in Debt Financing

Meikle Wind Energy Limited Partnership

R-41-16 Application to Register for the functions of Generator Owner and Generator Operator under the BC Mandatory Reliability Standards Program

Nelson Hydro/City of Nelson

L-26-16 Service Extension Complaint by the Kootenay Lake Estates Development Corporation

G-27-17 Application for 2017 Rates Regulatory Timetable

G-47-17 Application for 2017 Rates Amended Regulatory Timetable

Pacific Northern Gas Ltd.

E-12-16 Filing of a Gas Storage Contract with Tenaska Marketing Canada

E-13-16 Filing of Gas Supply Contracting Report for June 2016 to September 2016

E-18-16 Application for the Energy Management Services Agreement with Tenaska Marketing Canada

F-20-16 Application for 2016-2017 Revenue Requirements for the PNG-West service area – Participant Assistance/Cost Award

G-89-16 Filing of the Second Quarter 2016 Report on Gas Supply Costs for the PNG-West and Granisle service areas

G-131-16 Application for 2016-2017 Revenue Requirements for the PNG-West service area – Reasons for Decision

G-159-16 Application to Extend Operating Line and Treasury/Commodity Hedge Line

G-189-16 Filing of the Fourth Quarter 2016 Report on Gas Supply Costs and Application to amend the Rate Stabilization Adjustment Mechanism Rate Rider effective January 1, 2017 for the PNG-West and Granisle service areas

L-25-16 Filing of the 2016 Third Quarter Report on Gas Supply Costs for PNG-West and Granisle service areas

E-2-17 Section 71 Filing of 2016/2017 Natural Gas Energy Supply Contracts

G-36-17 Filing of First Quarter 2017 Report on Gas Supply Costs for PNG-West and Granisle service areas


F-21-16 Application for 2016-2017 Revenue Requirements for the PNG (N.E.) service area – Participant Assistance/Cost Award

G-90-16 Filing of the Second Quarter 2016 Report on Gas Supply Costs for the Fort St. John/Dawson Creek and Tumbler Ridge service areas

G-132-16 Application for 2016-2017 Revenue Requirements for the PNG (N.E.) service area – Reasons for Decision

G-160-16A Application to Extend Operating Line and Treasury/Commodity Hedge Line

G-190-16 Filing of the Fourth Quarter 2016 Report on Gas Supply Costs and Application to amend the Rate Stabilization Adjustment Mechanism Rate Rider effective January 1, 2017 for the Fort St. John/Dawson Creek and Tumbler Ridge service areas


75


L-24-16 Filing of the 2016 Third Quarter Report on Gas Supply Costs for Fort St. John/Dawson Creek and Tumbler Ridge service areas

L-5-17 Filing of First Quarter 2017 Report on Gas Supply Costs for Fort St. John/Dawson Creek and Tumbler Ridge service areas

Pacific Northern Gas Ltd./Pacific Northern Gas (N.E.) Ltd.

L-21-16 Filing of the 2016 Annual Gas Contracting Plan (November 2016 - October 2017)

Pingston Power Inc.

G-51-17 Application for an Exemption from Part 3 of the Utilities Commission Act

Planet Energy (B.C.) Corp.


Plateau Pipe Line Ltd.

G-55-16 Application for Revised 2016 Tolls on the Western Pipeline System effective May 1, 2016

G-137-16 Application for Revised Tolls on the Western Pipeline System effective September 1, 2016

G-148-16 Application to Revise Tolls on the Western Pipeline System effective October 1, 2016

Port Alice Gas Inc.

G-45-16 Application for Approval to Increase the Basic Charge and Facility Charge – Timetable Suspended

G-69-16 Application for Approval to Increase the Basic Charge and Facility Charge – Corrected Interim Rates

G-72-16A Application for Approval to Increase the Basic Charge and Facility Charge – Revised Interim Rates

G-104-16 Application to Increase the Basic Charge and Facility Charge – Amended Regulatory Timetable

G-134-16 Application for Approval to Increase the Basic Charge and Facility Charge – Utilities Commission Act Exemption Application

G-21-17 Application for Exemption from Part 3 of the Utilities Commission Act for the Operation of the Propane Air Grid Assets and Sale of Propane in the Village of Port Alice – Exemption granted

G-34-17 Application for Approval to Increase the Basic Charge and Facility Charge – Rates

Powell River Energy Inc.

G-98-16 Application for an Exemption pursuant to section 88(3) of the Utilities Commission Act – Regulatory Timetable

G-17-17 Application for an Exemption pursuant to section 88(3) of the Utilities Commission Act – Exemption granted

Powerex Corporation

R-19-17 Change in Registration with the BC MRS program Deregistration from Purchase Selling Entity Function

Quesnel River Pulp and Paper


Rio Tinto Alcan

R-7-17 Mitigation Plan (Version 1) Acceptance for PER-005-1_R3


Seascapes Strata Corporation BCS 776

G-29-17 Application for Reconsideration and Variance of Order G-172-16 – Regulatory Timetable

G-33-17 Application for Reconsideration and Variance of Order G-172-16 – Amend Regulatory Timetable

G-48-17 Application for Reconsideration and Variance of Order G-172-16 – Decision



76

Shannon Wall Centre Rental Apartments Limited Partnership

C-4-16 Application for a Certificate of Public Convenience and Necessity for the Shannon Estates Thermal Energy Systems – Decision

G-77-16A Application for Rates for the Shannon Estates Thermal Energy Systems – Interim Rates

G-118-16 Application for Rates for the Shannon Estates Thermal Energy Systems – Regulatory Timetable

G-161-16A Application for Rates for the Shannon Estates Thermal Energy System – Amended Regulatory Timetable

G-193-16 Application for Rates for the Shannon Estates Thermal Energy System – Amended Regulatory Timetable

Shell Energy North America (Canada)

R-17-17 Change in Registration with the BC MRS program – Deregistration from Purchase Selling Entity Function

Shell Energy North America (US) L.P.


Spirit Bay Utilities Ltd.

G-95-16 Application for Exemption pursuant to Section 88(3) of the Utilities Commission Act – Regulatory Timetable

G-125-16 Application for Exemption pursuant to Section 88(3) of the Utilities Commission Act – Amended Regulatory Timetable

G-175-16 Application for Exemption pursuant to section 88(3) of the Utilities Commission Act – Reasons for Decision

SSL-Sustainable Services Ltd.

G-87-16 Status as a Public Utility under the Utilities Commission Act – Regulatory Timetable

G-127-16 Status as a Public Utility under the Utilities Commission Act – Amended Regulatory Timetable

G-171-16 Status as a Public Utility under the Utilities Commission Act – Workshop and Procedural Conference Timetable

G-12-17 Status as a Public Utility under the Utilities Commission Act – Regulatory Timetable

G-22-17 Status as a Public Utility under the Utilities Commission Act – Amended Regulatory Timetable

Stargas Utilities Ltd.

G-155-16 Application to Vary Delivery Rate, Amend Cost of Service Formula and Approve Replacement Term Financing/Redemption of Preferred Shares – Regulatory Timetable

G-158-16 Application to Vary Commodity Rates

G-176-16 Application to Vary Delivery Rate, Amend Cost of Service Formula and Approve Replacement Term Financing/Redemption of Preferred Shares – Streamlined Review Process

G-192-16 Application to Vary Delivery Rate, Amend Cost of Service Formula and Approve Replacement Term Financing/Redemption of Preferred Shares – Share Redemption

G-196-16 Application to Vary Delivery Rate, Amend Cost of Service Formula and Approve Replacement Term Financing/Redemption of Preferred Shares – Amended Regulatory Timetable

E-3-17 Application for Acceptance of 2016-2017 Annual Contracting Plan

E-5-17 Application to Vary and Extend Natural Gas Purchase Plan

Summitt Energy BC LP



77


Sun Peaks Utilities Co. Ltd.

E-6-16 Filing of a Propane Supply Agreement with Superior Gas Liquids through FortisBC Alternative Energy Services Inc.

G-102-16 Application for a Gas Delivery Rate Increase – Interim Rate and Regulatory Timetable

G-106-16 Application to Decrease the Gas Commodity Rate effective August 1, 2016

G-110-16 Application for a Gas Delivery Rate Increase – Amended Regulatory Timetable

G-149-16 Application for a Gas Delivery Rate Increase Decision

L-30-16A Gas Cost Reconciliation Account Compliance Filing and Application to maintain the Commodity Rates at current levels

Superior Propane

C-5-16 Certificate of Public Convenience and Necessity for the Seascapes Development propane grid

G-56-16 Rate Application for Seascapes Grid System – Regulatory Timetable

G-115-16 Rate Application for Seascapes Grid System – Amended Regulatory Timetable

G-172-16 Rate Application for Seascapes Grid System – Reasons for Decision

Teck Metals Limited





Tolko Industries Ltd.

R-18-16 Application for Dismissal of a Confirmed Violation PRC-011-0_R1_R2


R-36-16 Application for Dismissal of Mitigation Plans PRC-005-1_R1_R2

R-14-17 Change in Registration with the BC MRS program Deregistration from Load Serving Entity Function

TransAlta Energy Marketing Corporation

R-21-17 Change in Registration with the BC MRS program Deregistration from Purchase Selling Entity Function

TransCanada Energy Sales Limited


Whitecap Resources Inc.

G-120-16 Application for Exemption from Part 3 and Section 71 of the Utilities Commission Act for Electrical Distribution Facilities in the Boundary Lake Area and Authorization to Sell Electricity

to ATCO Electric Ltd.



78

Energy Costs

79


Customers #Revenue ($)

ActualSales Actual

(kWh)Sales Actual

(GWh)

Crown-Owned Electric Utility

BC Hydro and Power Authority 1,981,544 4,466,039,937.00 49,554,816,231.00 49,554.82

Municipally Owned Electric Utilities

City of Grand Forks 2,651 4,167,000.00 34,890,000.00 34.89

City of Nelson (urban) 6,095 10,168,662.00 92,480,404.59 92.48

City of Nelson (rural) 4,176 6,679,968.15 63,249,040.21 63.25

City of New Westminster 33,523 43,889,000.00 432,704,000.00 423.70

City of Penticton 17,857 43,668,576.87 318,435,258.00 318.44

District of Summerland 5,644 10,165,750.00 80,875,822.00 80.88

Total Municipally Owned Utilities 69,946 118,738,957.02 1,022,634,524.80 1,022.63

Investor-Owned Electric Utilities

FortisBC Inc. 133,544 290,644,119.45 2,568,696,310.13 2,568.70

Hemlock Utility Services Limited 247 234,388.00 1,818,673.00 1.82

Kyuquot Power Ltd. 42 370,305.11 1,482,266.00 1.48

Silversmith Light and Power Corporation 11 43,064.28 1,130,477.00 1.13


Sun Rivers 851 1,420,813.00 12,504,883.00 12.50

Sonoma Pines 498 437,605.00 4,246,710.00 4.25

ATCO Electric Yukon - Lower Post BC1 77 136,220.00 884,482.00 0.88

Total Investor-Owned 135,270 293,286,514.84 2,590,763,801.13 2,590.76

Total All Electric Utilities 2,186,760 4,878,065,408.86 53,168,214,556.93 53,168.21

1 Effective June 14, 2014, the Yukon Electrical Company Limited changed its name to ATCO Electric Yukon


ActualSales (GJ)

Actual

Stream B Thermal Energy Utilities

FortisBC Alternative Energy Services Inc.

Tsawwassen Springs 1 59,677.00 3,127.00

Delta School District #37 1 378,070.00 16,595.00

Glen Valley 1 61,065.00 3,200.00

Brant 1 17,340.00 909.00

Camden Green 1 30,970.00 1,523.00

Helen Gorman 1 22,673.00 915.00

Artemisia 1 23,706.00 874.00

Telus Gardens 3 700,592.00 22,124.00

Sovereign 3 878,861.00 28,381.00

Domestic Electricity Sales (2016)

Domestic Thermal Energy Sales (2016)

Energy Costs


80

Flatiron 1 131,746.00 2,866.00

Pomaria 1 92,005.00 4,732.00

The Hudson 1 59,153.00 5,515.00

Alysen Place 1 115,762.00 8,428.00

Waterstone Pier 1 114,000.00 5,863.00

Seylynn Phase 1 1 175,699.00 5,272.00

Marine Gateway 4 1,022,120.00 32,277.00

SOLO Phase 1 2 629,772.00 20,064.00

Empire at QE Park 1 143,423.00 4,529.00


UniverCity NUS 8 739,339.00 20,355.62

UBC Neighbourhood Energy System 3 257,438.00 8,950.61

Creative Energy Vancouver Platforms Inc. 202 8,290,725.00 1,286,445.00

Shannon Wall Centre Rental Apartments LP 218 56,904.84 7,732.31

Dockside Green Energy 5 191,807.00 6,027.18

River District Energy 2 292,316.67 8996.00

Total All Stream B Thermal Energy Utilities 464 12,485,164.51 1,505,700.72


ActualSales (GJ)

Actual

Investor-Owned Natural Gas or Propane Gas Utilities


Mainland, Vancouver Island, Whistler, Revelstoke 991,573 1,120,031,544.00 196,418,570.00

Fort Nelson Division 2,431 2,818,078.00 539,923.00


Fort St. John/Dawson Creek Division 19,871 19,912,988.00 3,833,901.00

Tumbler Ridge Division 1,246 1,692,483.00 712,865.00

Pacific Northern Gas Ltd. (includes Granisle Grid) 20,513 40,319,666.00 4,327,119.00


Sun Rivers 560 154,888.00 11,261.00

Sonoma Pines 496 231,604.00 22,530.00

Panorama 237 679,449.00 31,190.00

Calgas Inc.

Kickinghorse 143 172,447.01 18,256.50

Canyon Ridge 27 10,652.22 1,365.70

Big White Gas Utility Ltd. 337 894,320.52 44,887.14

Port Alice Gas Inc. 232 284,849.00 8,261.63

Sun Peaks Utilities Co. Ltd. 909 1,299,461.00 79,952.00

Stargas Utilities Ltd. 292 153,507.78 42,352.90

Superior Propane (Seascapes) 100 103,181.77 5,295.26

Total All Gas Utilities 1,038,967 1,188,759,119.30 206,097,730.13

Energy Costs

Domestic Gas Sales (2016)

81


Directions The following is a general description of the Directions received from the Provincial Government during 2016/2017.

The complete text is available on the BCUC’s website at

www.bcuc.com/proceedings-orders-decisions/special-directions-regulations.html


82

http://www.bcuc.com/proceedings-orders-decisions/special-directions-regulations.html

Orders in Council

Order in Council 397Approved June 9, 2016 –

Direction respecting Liquefied

Natural Gas Customers.

Order in Council 589Approved July 28, 2016 –

Amendment to section 3 of the

Heritage Special Directive No.

HC1.

Order in Council 590Approved July 28, 2016 –

Amendment to Direction No.

7 to the British Columbia

Utilities Commission, BC Reg.

28/2014.

Order in Council 609Approved August 19, 2016

– Amendments to the

Greenhouse Gas Reduction

(Clean Energy) Regulation, BC

Reg. 102/2012.


– Amendments to Special

Direction IC2 to the British

Columbia Utilities Commission,

BC Reg. 207-2004.


– Direction to the Insurance

Corporation of British

Columbia regarding the

transfer of both capital and

income from ICBC’s optional

vehicle insurance business to

its universal compulsory vehicle

insurance business.

Order in Council 908Approved December 6, 2016

– Direction to the Insurance


Columbia to implement tariff

pages for a high-value vehicle

charge.


– Amendments to section

3(1) of Special Direction

IC2 to the British Columbia


307/2004 regarding approval

for the high-value vehicle

charge.


– Amendments to Division

2 of part 3 of the Insurance

(Vehicle) Regulation, BC Reg.

447/83, regarding the high-

value vehicle charge.


– Amendments to Special

Direction IC2 to the British

Columbia Utilities Commission,

BC Reg. 307/2004.

Order in Council 100Approved March 1, 2017

– Direction to the British

Columbia Utilities Commission

respecting Undertaking Costs.





Reg. 102/2012.

Order in Council 105Approved March 2, 2017 –

Direction to the Insurance


Columbia regarding changes

to its claim-rated scale for One

Free Crash/Reduced Crash

Forgiveness.


Amendments to section

3(1) of Special Direction



307/2004.





Reg. 102/2012.


Amendments to Direction

No. 5 to the British Columbia


245/2013.


Repeal and replace section

3(1)(c)(ii) of Special Direction



307/2004.

Directions

83


Ministerial Orders

Ministerial Order 167Approved May 9, 2016

- Approval to grant an

exemption to Bakerview

EcoDairy Ltd.

Ministerial Order 171Approved May 18, 2016


Mandatory Reliability

Regulation, BC Reg. 32/2009.

Ministerial Order 282Approved July 20, 2016

– Approval to grant an

exemption to Whitecap

Resources Inc. from the

application of Part 3 and

section 71 of the Utilities

Commission Act.

Ministerial Order 294Approved July 28, 2016

– Silversmith Exemption

Regulation.

Ministerial Order 362Approved September 20,

2016 – Long Lake Exemption

Regulation.

Ministerial Order 417Approved October 20, 2016

– Apollo Forest Products Ltd.

Exemption Regulation.

Ministerial Order 36Approved January 27, 2017


exemption to Powell River

Energy Inc.

Ministerial Order 039Approved January 27, 2017 –

Repealing Ministerial Order

26/2001 and the creation of

PREI Exemption Regulation.

Ministerial Order 44Approved February 8, 2017


exemption to Port Alice Gas

Inc.

Ministerial Order 55Approved February 16, 2017

– Amendments to QCS

Exemption Regulation, BC Reg.

239/2012.

Ministerial Order 138Approved March 22, 2017 –

Amendments to the Demand

Side Measures Regulation, BC

Reg. 326/2008.

Ministerial Order 148Approved March 30, 2017


exemption to Pingston Power

Inc. from Part 3 of the Utilities

Commission Act.

Exemptions

Order G-71-16Issued May 19, 2016

Exempts Bakerview EcoDairy

Ltd. from Part 3 of the Utilities

Commission Act, except for

sections 25, 38, 42, 43, 44, and

49, for the resale of electricity

via the Electric Vehicle Direct

Current Fast Charging station

on its property at 1356 Sumas

Way, Abbotsford, B.C.

Order G-120-16Issued July 28, 2016

Exempts Whitecap Resources

Inc., its successors or assigns

as owner or operator of the

electrical substation and

distribution facilities located

in the Boundary Lake area of

British Columbia (collectively,

the Goodlow substation and

the distribution facilities in

British Columbia are the

Boundary Lake Distribution

Facilities), and the Boundary

Lake Distribution Facilities

as those facilities may be

modified or expanded from

time to time from section 71

and Part 3 except section 38 of

the Utilities Commission Act.

Directions


84

Order G-17-17Issued January 27, 2017

Exempts Powell River Energy

Limited Partnership and any

Wholesale Marketing Affiliate

who enters into an Energy

Supply Contract with Powell

River Energy Inc. from section

71 of the Utilities Commission

Act for:

1. the purchase of Surplus

Power from Powell River

Energy Inc.;

2. any subsequent sale

of that Surplus Power

to a Public Utility or a

Wholesale Customer;

and

3. any Wholesale

Customer who

purchases Surplus

Power from Powell

River Energy Inc., Powell

River Energy Limited

Partnership, Brookfield

Power, or a Wholesale

Marketing Affiliate.

Exempts the Power Facilities

from Part 3 of the Act, except

for sections 25, 38, 42 and 43.

Order G-21-17Issued February 22, 2017

Exempts Port Alice Gas Inc.

from Part 3 of the Utilities

Commission Act, except for

sections 25, 38, 42, 43, and

44, for its operation of the

propane air grid assets and

sale of propane in the Village

of Port Alice.

Order G-51-17Issued March 31, 2017

Exempts Pingston Power Inc.

from the requirements of Part

3 of the Utilities Commission

Act except for sections 25, 38,

42, and 43 for its transmission

and interconnection facilities

used to deliver the Fosthall

Creek Hydro Project electricity

to the British Columbia Hydro

and Power Authority electrical

system.

Directions

85


Regulated EntitiesCrown-Owned Electric Utilities

British Columbia Hydro and Power Authority Lower Mainland, Vancouver

Island, Central and Northern

B.C. and East Kootenay

Regions

Investor-Owned Electric Utilities

Corix Multi-Utility Services Inc. Lot 152, CLSR Plan 78619

Kamloops

Hemlock Utility Services Ltd. Hemlock Valley

Silversmith Power & Light Corporation

Sandon

FortisBC Inc. West Kootenay and Okanagan

Regions of B.C., Princeton,

Osprey Lake and Missezula

Lake Areas and Kelowna

Kyuquot Power Ltd. Kyuquot

The Yukon Electrical Company Limited (operating as ATCO Electric

Yukon) Lower Post


86

Municipally Owned Electric Utilities

Municipally owned electric

utilities are not regulated

under the Utilities Commission

Act. Only the City of Nelson’s

electric utility with service

outside of the Municipal

boundaries is subject to

regulation by the BCUC.

City of Nelson (also known as Nelson Hydro)

Stream A Thermal Energy Systems

FortisBC Alternative Energy Services Inc. Marine Gateway, Queen

Elizabeth Park Thermal

Energy System, Seylynn

Village Development

Phase 1 & 2, SOLO Phase

1, Waterstone Pier, Alysen

Place, Flatiron, Pomaria, The

Hudson, Aperture

Creative Energy Vancouver Platforms Inc. 188 Keefer Street, 2200

Kingsway, 1480 Howe Street

Corix Multi-Utility Services Inc. Talasa Central Energy Plant/

Sun Rivers Resort Community,

Belmonte Central Energy

Plant/Sun Rivers Resort

Community

Connect TES (Richmond) Holdings Inc.The Pier, Parc Riviera

Stream B Thermal Energy Systems

Corix Multi-Utility Services Inc. UBC NES-Phase 1 Westwood

UniverCity NUS

Creative Energy Vancouver Platforms Ltd. NES-Northeast False Creek

Dockside Green Energy LLP. District Energy System,

Victoria

FortisBC Alternative Energy Services Inc. Tsawwassen Springs

Development, Delta School

District No. 37, Telus Garden

Development, Glen Valley,

Brant, Camden Green, Helen

Gorman, Artemisia and

Sovereign

River District Energy LP District Energy Utility at the

River District, Vancouver, B.C.

Shannon Wall CentreShannon Estates Thermal

Energy System

Investor-Owned Natural Gas, or Propane Utilities

Big White Gas Utility Big White Ski Resort

Cal-Gas Inc. Canyon Ridge and Kicking

Horse

Corix Multi-Utility Services Inc. Panorama, Sonoma Pines

and Sun Rivers

FortisBC Energy Inc. Lower Mainland, Fort Nelson,

Central and Northern

Interior, the Kootenays, the

Okanagan, Whistler, Sunshine

Coast, Powell River, and

Vancouver Island north to

Campbell River, west to Port

Alberni, and south to Victoria

Pacific Northern Gas Ltd. Summit Lake to Prince Rupert

and Kitimat and Granisle

(Propane Grid System)

Pacific Northern Gas (N.E.) Ltd. Dawson Creek, Rolla, Pouce

Coupe, Tumbler Ridge and

Fort St. John

Port Alice Gas Inc.Port Alice (Propane Grid

System)

Stargas Utilities Ltd.

Silver Star resort community

Sun Peaks Utilities Co., Ltd. Resort area north of

Kamloops

Superior Propane Seascapes Development Ltd.

Compulsory Automobile Insurance

Insurance Corporation of British Columbia Province of B.C.


87



Mandatory Reliability Standards RegistrantsBear Mountain Wind Limited

Partnership

British Columbia Hydro and

Power Authority

Cape Scott Wind LP

Capital Power LP (Quality

Wind Farm)

Cariboo Pulp & Paper

Company

Catalyst Paper – Crofton

Division

Catalyst Paper – Port Alberni

Division

Catalyst Paper – Powell River

Division

Coast Mountain Hydro Limited

Partnership

Dokie General Partnership

FortisBC Inc.

Howe Sound Pulp & Paper

Corporation

Innergex Renewable Energy

Inc.

Intercontinental Pulp Mill

Jimmie Creek

Lehigh Cement

Meikle Wind Energy Limited

Partnership

Northwood Pulp Mill

Prince George Pulp & Paper

Mill

Quesnel River Pulp and Paper

Rio Tinto Alcan

Teck Metals Ltd

Toba Montrose General

Partnership

Tolko Industries Limited

V.I. Power Limited Partnership

WESCUP McMahon

Generation Plant

Licensed Gas MarketersAccess Gas Services Inc.

Bluestream Energy Inc.

Direct Energy (BC) Ltd.

Just Energy (BC) LP

Planet Energy (BC) Corp.

Summitt Energy BC LP


88

British Columbia Utilities CommissionSuite 410, 900 Howe Street

Vancouver, BC Canada V6Z 2N3

Phone: 604.660.4700

BC Toll-free: 1.800.663.1385

Fax: 604.660.1102

Email: [email protected]

bcuc.com

British ColumbiaUtilities Commission

mailto:[email protected]

http://WWW.bcuc.com

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