David Curtis Direct 604 631 4827

Facsimile 604 632 4827 dcurtis@fasken.com

June 9, 2011 File No.: 240148.00677/15951

ELECTRONIC FILING British Columbia Utilities Commission 6th Floor, 900 Howe Street Vancouver, BC V6Z 2N3

Attention: Eric Hamilton Commission Secretary

Dear Sirs/Mesdames:

Re: An Inquiry into FortisBC Energy Inc. regarding the Offering of Products and Services in Alternative Energy Solutions and Other New Initiatives (the “Inquiry”)

We enclose for filing in the above referenced proceeding the electronic version of the Submissions regarding the scope of the Inquiry and Exhibit Book on behalf of the FortisBC Energy Utilities.

Fifteen hard copies of the Submissions and Exhibit Book will follow by courier.

Yours truly,

FASKEN MARTINEAU DuMOULIN LLP [original signed by David Curtis] David Curtis

DHC

646 Pages B-1

IN THE MATTER OF The Utilities Commission Act, R.S.B.C. 1996, Chapter 473

and

An Inquiry into FortisBC Energy Inc.

regarding the Offering of Products and Services in Alternative Energy Solutions and Other New Initiatives

Written Submission of the FortisBC Energy Utilities for Procedural Conference on June 15, 2011

June 9, 2011

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TABLE OF CONTENTS

Page

PART ONE: INTRODUCTION AND OVERVIEW ...................................................................................... 1

A. INTRODUCTION .................................................................................................................... 1

B. CONTEXT FOR FEU’S PROCEDURAL SUBMISSIONS .............................................................. 2

C. ORGANIZATION OF SUBMISSION ......................................................................................... 6

PART TWO: INQUIRY ISSUES AND SCOPE ............................................................................................ 8

A. INTRODUCTION .................................................................................................................... 8

B. FEU MUST BE FREE TO PROCEED ACCORDING TO EXISTING APPROVALS ........................... 8

(a) Approved 2010-2011 RRA NSA Contemplated Rate Structures Continuing ................ 9 (b) Issue Amounts to Re-Litigation of the 2010-2011 RRA Approval ............................... 11 (c) New AES Projects to be Submitted According to NSA................................................ 12 (d) Summary ..................................................................................................................... 12

C. NON-ISSUES THAT SHOULD BE SET ASIDE AT THE OUTSET ............................................... 13

(a) AES is a Regulated Public Utility Service ..................................................................... 13 (b) RMDM Do Not Govern the Relationship Between Two Regulated Classes of

Service ......................................................................................................................... 16 (c) Use of FortisBC Name ................................................................................................. 19 (d) Section 18 “Prescribed Undertakings” ....................................................................... 20 (e) Summary ..................................................................................................................... 21

D. NGV, BIOMETHANE, AND EEC BEST ADDRESSED IN ANOTHER CONTEXT ......................... 21

(a) Introduction ................................................................................................................ 21 (b) Staff Working Paper Issues Relating to Biomethane, NGV and EEC .......................... 21 (c) Overlap is at the Long-Term Planning Level ............................................................... 22 (d) Upholding Prior Determinations on NGV, EEC and Biomethane ............................... 23 (e) Comprehensive Regulatory Review of Biomethane Completed ................................ 23 (f) Comprehensive Review of NGV Completed ............................................................... 25 (g) EEC Issues Addressed in Comprehensive EEC Application, RRA, and EEC-NGV

Proceeding .................................................................................................................. 27 (h) Summary Regarding NGV, Biomethane and EEC ........................................................ 28

E. FOCUS OF THE GUIDELINES................................................................................................ 28

(a) Section 72 Concerns What a Public Utility “Has Done, is Doing, or Has Failed to Do” .......................................................................................................................... 29

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(b) The Limits of the Commission’s Jurisdiction Over Utility Management and Competition ................................................................................................................ 29

(c) Summary ..................................................................................................................... 31 F. BALANCED INQUIRY SCOPE AND BALANCED FORMULATION OF THE INQUIRY

ISSUES ................................................................................................................................. 31

(a) Introduction ................................................................................................................ 31 (b) Additional Issues that should be Included Within Inquiry Scope ............................... 31 (c) Need for Reformulation of Inquiry Issues in Neutral Manner ................................... 32

PART THREE: INQUIRY PROCESS ....................................................................................................... 33

(a) Proposed Hearing Process (Assuming Scope is as FEU Proposes).............................. 33 (b) Other Process Matters ................................................................................................ 33

PART FOUR: INQUIRY TIMING .......................................................................................................... 34

PART FIVE: CONCLUSION .................................................................................................................. 35

APPENDIX “A”: REFORMULATION OF INQUIRY ISSUES ...................................................................... 37

APPENDIX “B” TABLE OF CONCORDANCE .......................................................................................... 41

FEU EXHIBIT LIST

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PART ONE: INTRODUCTION AND OVERVIEW

A. INTRODUCTION

1. The Commission has recently received two complaints (the “Complaints”)1 from

competitors of the FortisBC Energy Utilities (the “FEU” or the “Companies”) regarding its

provision of thermal energy (geothermal, solar-thermal and district energy) services, also

referred to as Alternative Energy Solutions (“AES”), to the public.2 These Complaints are

generally directed at limiting the extent and nature of the FEU’s participation in AES.3

2. In Order G-95-11 (the “Inquiry Order”), the Commission established an Inquiry

under sections 23, 72, 82 and 83 of the Utilities Commission Act (the “UCA”) to consider “FEI

offering Products and Services in Alternative Energy Solutions and New Initiatives”. Appendix B

of the Inquiry Order is a Staff Working Paper on Scope of the Issues (the “Staff Working Paper”).

The issues identified by the Staff Working Paper extend well beyond the issues described in the

Complaints, and touch on matters such as Energy Efficiency and Conservation or demand side

management (“EEC”), Natural Gas Vehicle (“NGV”) fuelling services, and Biomethane. The Staff

Working Paper also refers to the Resource Planning Guidelines. The Inquiry Order directed that

FEU and registered interveners could provide written submissions on the “preliminary issues,

scope and process of this Inquiry by Thursday, June 9, 2011.” These Procedural Conference

Submissions are filed on behalf of the FEU and address the preliminary issues, scope and

process of this Inquiry.

1 A2-1, letter dated May 25, 2011, filing Energy Services Association of Canada (“ESAC”) application dated April

27, 2011; A2-2, letter dated May 25, 2011, filing Corix Utilities (“Corix”) May 6, 2011, letter supporting the ESAC application.

2 The FEU are using the term AES to refer to the services described in the approved General Terms and Conditions (“GT&C’s”) Section 12A as follows: “FortisBC Energy will make extensions to the FortisBC Energy System using technology that produces alternative energy, in accordance with the provisions of this section. The alternative energy extensions include geo-exchange, solar thermal and district energy systems which are described below…” AES does not include in this definition Natural Gas Vehicles or its fuelling infrastructure (“NGV”), Biomethane, or Energy Efficiency and Conservation (“EEC”). These service offerings and their costs are part of the natural gas class of service within FEI. AES costs are tracked separately and recovered from AES customers. For further detail, see the FEU’s Exhibit Book, tab 18.

3 AES or Thermal Energy Solution (“TES”) projects are carried out under Fortis BC Energy Inc. (“FEI”) according to the terms of the Negotiated Settlement Agreement (“NSA”) for FEI dated November 26, 2009. No AES or TES projects are to occur within FEVI according to the NSA.

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3. The FEU recognizes the Commission’s desire to have a comprehensive review of

issues raised in applications relating to new initiatives being pursued by the FEU.4

4. In light of the importance to the FEU and their customers of the issues raised by

the Complaints and the Staff Working Paper, the Inquiry process set by the Commission must

ensure that the FEU has a full opportunity to provide comprehensive evidence, respond to

appropriate questions, cross-examine both Complainants, and make submissions. The FEU

have proposed a process and timetable that meet these procedural fairness considerations.

The FEU look forward to a constructive and efficient Inquiry for the benefit of all stakeholders

and, most importantly, for the benefit of FEU’s customers.

The FEU

welcomes the opportunity to resolve some of the issues raised in the Staff Working Paper in an

Inquiry. However, the FEU submits that the final scope of the Inquiry should differ from that

set out in the Staff Working Paper, with a focus on issues relating to AES.

B. CONTEXT FOR FEU’S PROCEDURAL SUBMISSIONS

5. The FEU initially articulated their intention to pursue NGV fuelling service,

Biomethane, and AES in the 2008 Long-Term Resource Plan (“LTRP”), filed June 27, 2008. The

FEU submitted a comprehensive EEC Application at approximately the same time. The 2008

LTRP was the FEU’s response to government’s 2007 Energy Plan, the introduction of the Carbon

Tax, and a new environment where energy consumers increasingly have choices regarding

energy sources and are interested in low-carbon solutions.5 The three low-carbon initiatives

were an integral part of the Companies’ long-term plan to ensure that natural gas and its

infrastructure remains part of the energy mix for the benefit of both natural gas customers and

the Companies, while at the same time responding to the public policy and legislative mandate

to reduce greenhouse gas (“GHG”) emissions in BC.6

4 2010 FEU LTRP Decision (Order G-14-11), pages 26-28; FEU Exhibit Book, tab 7.

The FEU maintain that the Biomethane,

NGV, and AES initiatives deliver tangible benefits to existing and potential customers. The

customers of the FEU, which will continue to be primarily gas customers for some time into the

future, benefit from optimizing the use of the existing infrastructure, sharing delivery costs and

5 2008 FEU Resource Plan, pages 9-27 and 89-105. 6 FEI 2010-2011 RRA pages 46-47.

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overheads, and access to innovative low carbon offerings as a growing number of the FEU’s

customers want more than just traditional natural gas service. Further, the initiatives are fully

aligned with government policy reflected in “British Columbia’s energy objectives” and the

2007 Energy Plan.7

6. The Commission has indicated a desire to consider all new initiatives in a

comprehensive way. The FEU submit that, given the nature of the overlap, future LTRPs remain

the appropriate venue for that type of review. Although the FEU’s EEC, Biomethane, AES and

NGV initiatives have common objectives and affect resource requirements, each of these

initiatives requires a more nuanced consideration at the level of rate design and public interest

assessment.

The FEU submit that the customer and policy impetus for the FEU’s

involvement in AES is essential context that must also be understood and accounted for in any

balanced Inquiry addressing AES.

7. In the intervening three years since the FEU stated their intention to pursue

Biomethane, NGV, and AES initiatives in the 2008 LTRP, FEU have brought forward specific

proposals in respect of each of the following initiatives:

(a) Biomethane: FEI filed a comprehensive business model for a Biomethane program in 2010 and obtained Commission approval for a two-year pilot. FEI has two supply projects approved (Salmon Arm and Catalyst) and residential customers will begin to enrol in the program shortly.8

(b) NGV: FEI filed a comprehensive NGV Application in December 2010, for which a final decision is outstanding. This business model was supported by a commercial contract for CNG (Waste Management) that produced the first new natural gas fuelling infrastructure built in BC in 10 years. Another commercial contract (Vedder Transport) for LNG service will be filed with the Commission for approval in the near future.

9

7 For example, see the Biomethane Application Decision at p. 27, where the Commission found that the

Application is consistent with British Columbia’s energy objectives and Provincial Government energy policy.

8 FEI filed the Biomethane Application on June 8, 2010; the decision approving the application was made on December 14, 2010 (Order No. G-194-10); FEU Exhibit Book, tab 13.

9 FEI filed the Application for Approval of a Service Agreement for Compressed Natural Gas Service and for Approval of General Terms and Conditions for CNG and Liquefied Natural Gas Service, on December 10, 2010; the decision is currently pending (the NGV Application).

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(c) AES: FEI obtained approval in the 2010-2011 Revenue Requirements Application (“2010-2011 RRA”) for rate constructs for offering AES.10

(d) EEC: The FEU filed an EEC Application in 2008 that resulted in the Commission establishing a framework for EEC funding. The FEU sought and obtained additional EEC funding in the 2010-2011 RRA, and addressed the EEC framework again as part of the Commission-initiated process to consider EEC funding for NGV initiatives that is still underway.

FEI will bring forward signed contract(s) (projects) shortly for BCUC approval according to the terms and conditions of the Negotiated Settlement Agreement.

11

8. As a result of these Applications, many issues raised by the Staff Working

Paper—particularly those related to NGV, Biomethane and EEC—have already been heard or

decided based on facts and policy that remain the same today. The Companies have taken the

approvals granted at face value and have proceeded with the approved initiatives in good faith.

There are customers that have taken steps to avail themselves of approved services in the

reasonable expectation that the services will continue to be available. There will be business

implications for FEU and stakeholders if this Inquiry includes issues that have been reasonably

understood to have been settled through prior proceedings. FEU and potential customers

must, as a matter of basic fairness, be able to rely on these past Commission decisions and the

policies inherent in them without having to re-justify the initiatives based on substantially the

same policy and factual evidence. The law requires consistency in decision making and finality

of decisions.

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9. FEU submits that AES should be the focus of this Inquiry, which is really at the

heart of the Complaints. Furthermore, the Staff Working Paper issues relating to AES should be

Respecting past decisions made on the basis of still applicable facts, law, and

policy ensures that subsequent regulatory processes can be conducted efficiently and cost-

effectively, protects customers, and ensures that the utility is not unnecessarily subjected to

additional unanticipated regulatory-related business risk.

10 Which the approved rate schedule refers to collectively as “Alternative Energy Services” or “AES” and the FEU

refer to now as “Thermal Energy Services”. FEI filed the 2010-2011 RRA on June 15, 2009. 11 FEI filed the 2008 EEC Application on May 28, 2008. 12 The Commission has jurisdiction to reconsider decisions under s. 99 of the Act. The Commission has

established criteria that determine how and when this jurisdiction is to be exercised. Nothing set out in the Complaints meet the criteria for reconsideration, and they have not sought reconsideration. The Commission is also not subject to stare decisis, but this does not mean issues should be relitigated based on substantially the same evidence.

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expanded in two key respects. First, the FEU submit that there needs to be meaningful

discussion in this Inquiry of the potential benefits of AES to all of FEU’s existing and potential

customers (i.e. natural gas and AES customers) and how AES serves “British Columbia’s energy

objectives”. Issues related to AES should not be limited to identifying risks with AES and the

concerns of the FEU’s competitors, which are the pervasive themes in the Staff Working Paper.

In the final scoping order, all issues should be presented in a balanced way.

10. Second, the Inquiry scope must recognize that the Commission’s ability to make

certain directions and determinations contemplated in the Staff Working Paper is very much a

live issue. The Commission can only hear a complaint on, or initiate an inquiry into, matters

within its jurisdiction. The FEU will argue at the conclusion of this Inquiry that there are some

issues included in the Staff Working Paper that relate to matters over which the Commission

has no jurisdiction (for example, in respect of management decisions and competition issues),

and therefore the Commission would exceed its jurisdiction by stipulating guidelines on such

matters.

11. The aspect of the ESAC’s Complaint that focused on their ability to participate in

past processes also warrants comment. The processes relating to the 2008 and 2010 LTRPs, the

Biomethane Application, NGV Application, 2010-2011 RRA, EEC Application and EEC for NGV

were open to the public, well advertised according to Commission direction, and involved

interventions or commentary by customer groups, industry groups, and other public utilities.13

In these proceedings, the Commission had the benefit of comprehensive evidence, in the form

of filings and thousands of Information Requests.14

13 For example, in the 2008 Resource Plan proceeding, ROMS, BC Hydro, MEMPR, CEC and BCOAPO intervened; in

the Biomethane proceeding, BC Agriculture Council, BC Bioenergy Network, BC Hydro, CEC, BCSEA and BCOAPO intervened; in the NGV proceeding, BC Hydro, BCSEA, BCOAPO and CEC have intervened.

Decisions were posted online. The FEU

submits that the Commission should not accept that portion of ESAC’s Complaint premised on

the notion that the FEU has conspired to limit ESAC’s ability to participate to date, and that the

results of past proceedings are somehow invalidated by ESAC’s non-participation. The FEU are

prepared to address the ESAC Complaint head-on, but the starting point should be that ESAC

14 IR’s in these proceedings totalled 2098. This total does not include IRs from the FEI and FEVI RRA for 2010-2011.

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members, who are large, sophisticated commercial enterprises, have had sufficient opportunity

to participate in all proceedings to this point.

12. Finally, issues raised by the Complainants and the Staff Working Paper have

relevance to entities other than the FEU. The FEU submit that, to the extent that AES matters

remain within scope, the Companies should be able to probe as part of this Inquiry the business

models of Corix and ESAC members and how much they really differ from what the FEU is

doing. The FEU will submit in this Inquiry that there are in fact substantial similarities between

how these entities run their AES business (e.g. Corix operates multiple utility services within a

single entity under a common brand), and it should remain a live issue in this Inquiry whether

the outcome of this Inquiry should affect those providers of AES as well.

C. ORGANIZATION OF SUBMISSION

13. The remainder of this Submission is organized as follows:

(a) Part Two: Inquiry Issues and Scope explains why the Inquiry should be confined to AES-related issues not previously determined, and the issues should be reformulated in the scoping order with regard to the legal context and the importance of a balanced hearing.

(b) Part Three: Inquiry Process sets out an efficient process that contemplates legal and jurisdictional issues being addressed only in legal submissions filed by counsel (and not in information requests); some issues being addressed through a written hearing process; and issues that go to substance of the complaints and AES culminating in an oral hearing.

(c) Part Four: Inquiry Timing proposes a timetable based on the Inquiry scope and process articulated in these Submissions, which provides all participants with a meaningful opportunity to participate.

(d) Part Five sets out FEU’s conclusions regarding the scope of the Inquiry.

(e) Appendix “A” is a table that sets out the issues from the Staff Working Paper that FEU submits are appropriate for this Inquiry, and a reformulation of those issues in neutral terms.

(f) Appendix “B” is a table that sets out each of the issues from the Staff Working Paper, and for each issue indicates whether FEU submits that it is appropriate or

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inappropriate for the Inquiry, and the specific section of these submissions in which the issue is discussed.

14. FEU has also filed an Exhibit Book that contains the documents referred to in

these submissions, with the exception of the previously filed applications referred to, which

have not been included due to their large size and their availability on the BCUC’s website.

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PART TWO: INQUIRY ISSUES AND SCOPE

A. INTRODUCTION

15. In this Part, the FEU address the proper scope of this Inquiry with reference to

the Staff Working Paper. The FEU submit that a number of the issues identified in the Staff

Working Paper should be excluded from the scope of this Inquiry, and that the remaining issues

should better account for the legislative framework and the customer and policy rationales for

the FEU pursuing AES.

16. This Part is organized as follows:

(a) Section B discusses an issue that directly undermines business initiatives undertaken by the FEU and its customers in good faith reliance upon prior Commission approvals.

(b) Section C identifies several previously determined issues that should be excluded from the Inquiry.

(c) Section D explains why the Inquiry should focus on AES, leaving any undecided issues relating to NGV, Biomethane, EEC, and the Resource Planning Guidelines to be considered in other processes.

(d) Section E speaks to the need for the Inquiry to address the limits of the Commission’s ability to establish guidelines.

(e) Section F provides a rationale for formulating all issues in a balanced manner that reflects the legislative framework, recognizes that there are benefits to customers associated with the FEU’s initiatives, and acknowledges that the initiatives meet British Columbia’s energy objectives.

B. FEU MUST BE FREE TO PROCEED ACCORDING TO EXISTING APPROVALS

17. The Staff Working Paper identifies as an issue whether the approved rate

constructs for AES cease to have effect beyond the term of the 2010-2011 RRA Negotiated

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Settlement Agreement (NSA).15

(a) Approved 2010-2011 RRA NSA Contemplated Rate Structures Continuing

The suggestion that this is even a possibility is at odds with the

2010-2011 RRA NSA. Including this as an Inquiry issue raises serious and immediate business

concerns for the FEU and customers that have made commercial decisions, including investing

significant capital, in reliance on the approvals remaining in place. The FEU submit that

including this issue in the Inquiry is fundamentally unfair, and it should be excluded from the

Inquiry’s scope.

18. The FEI 2010-2011 RRA NSA addressed AES, as that term was defined in the

proposed Section 12A of the General Terms and Conditions (GT&C’s), i.e. solar thermal,

geothermal and district energy systems. The RRA proceeding concluded with the Commission

having approved: (a) Section 12A of the GT&C’s “Alternative Energy Extensions”; (b) a deferral

account to record the costs and revenues attributable to the AES business; and (c) an allocation

of overhead from the natural gas business to the AES business that would keep natural gas

customers whole. These were the essential rate constructs to establish and develop the AES

class of service within FEI. Moreover, the Commission approved a mechanism for the FEU to

bring forward AES projects, which involved the FEU applying an approved economic test and

filing project-specific contracts:

In evaluating AES projects, TGI will apply the economic test outlined in the Application. The Parties agree that the proposed GT&C (Section 12A – Alternative Energy Extensions) are acceptable. Pursuant to the Utilities Commission Act, within the Alternative Energy class of service, project-specific contracts with AES customers will be filed with the Commission for acceptance as a rate, at which time the Commission may review and adjust the economic test and GT&C Section 12A – Alternative Energy Extensions.

The CPCN threshold of $5 million applies to AES projects brought forward in 2010 and 2011.16

15 The particular issue of concern, with the most objectionable portion underlined, is as follows: “Do tariff

provisions, if flowing from a commission order approving an NSA, imply a regulatory policy? To what extent do issues resolved in an NSA become policy positions at the Commission? Should the Commission approval be limited to the duration of the test period?” [Issue 3, sub-issue]

16 2010-2011 RRA NSA, Order G-141-09, Appendix A, p. 9 of 110; FEU Exhibit Book, tab 5.

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19. Nothing in the NSA suggested that the approval of the rate constructs only

extended for two years.17

20. There will be serious business implications if this issue is included within the

scope of the Inquiry, including:

On the contrary, the NSA expressly contemplated that the

Companies would be pursuing AES projects, with the business development costs being

captured in a deferral account and recovered from AES (and not Natural Gas) customers.

Having the right to recover costs from future AES customers necessarily means that the

Companies will have a rate schedule in place going forward that allows the Company to charge

rates. Moreover, the NSA stated that “issues relating to the gas load and gas consumption

profiles of AES projects that incorporate a natural gas component” are to be addressed “once

TGI has sufficient AES customers that take gas so as to provide reliable information on gas load

and gas consumption profiles”. It would be incongruous with this provision for the AES rate

constructs to expire before FEU could ever hope to sign up “sufficient AES customers”.

(a) The FEU have, in reliance upon the Commission’s approvals, developed and pursued AES projects with the expectation that there is a rate mechanism in place to recover the associated costs. The current balance in the AES deferral account at the end of 2010 is $2.530 million.18 At the end of 2011 the balance will include $1 million overhead allocation that was deducted from the natural gas revenue requirement in 2010 and 2011 to the direct benefit of natural gas customers. The UCA requires that the FEU have an opportunity to earn a return on and of capital reasonably invested in reliance on a past Commission order.19

(b) Potential AES customers that want to take AES service from the FEU have entered into negotiations with the FEU in the reasonable expectation that their negotiations can actually result in being able to take service under an approved rate schedule. These customers have their own policy (e.g. GHG reduction) or commercial imperatives that require these negotiations to stay on track.

(c) The uncertainty is a significant barrier to developing projects, both from the perspective of the risk of investing further funds, and from the perspective of customer perception. The mere fact that there is an Inquiry regarding AES at all is a “win” for Corix and ESAC members, the FEU’s competitors, who have not had

17 The comment letters attached to the NSA also did not suggest this; FEU Exhibit Book, tab 6. 18 2012-2013 FEU Revenue Requirement and Rate Application, May 4, 2010, Appendix G. 19 Utilities Commission Act, section 59; FEU Exhibit Book, tab 2. See also ATCO Gas & Pipelines Ltd. v. Alberta,

2006 SCC 4, para. 63; FEU Exhibit Book, tab 14.

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to contend with this issue thus far. The commercial problems for the FEU are magnified if the Commission is seen, rightly or wrongly, to be contemplating re-writing past approvals.

(b) Issue Amounts to Re-Litigation of the 2010-2011 RRA Approval

21. The Staff Working Paper ties the question about the expiry of the approved rate

structures to the broader issue of the implications of an NSA for “Commission policy”.

Whether or not one characterizes the approval of AES rate schedules as “Commission policy” or

simply the approval of AES rate structures, the scope of this Inquiry must account for the past

Order. The FEU respectfully submit that the Commission must accept that the Commission’s

approval of AES rate constructs necessarily had lasting implications for the FEU and its

customers, and should focus the Inquiry on issues that remain outstanding.

22. The 2010-2011 RRA was resolved by way of a comprehensive NSA reached by

stakeholders, with the participation of Commission Staff, and with input from the Commission

Panel on “Issues of Particular Concern to the Commission”. The 2010-2011 RRA featured a

considerable evidentiary record on AES, which addressed policy matters, issues of cost

allocation, operational issues, rate design issues, and future review process. The Commission

Panel had to assess all of this evidence to determine whether or not the settlement, including

the AES provisions and Schedule 12A of the GT&C’s, was “just and reasonable”. The

Commission panel also considered comments on the NSA from Commission Staff20,

Government21

20 Commission Staff filed a letter of comment with the NSA which addressed AES, but only to deal with the topic

of cost allocation; there was no suggestion that it objected to the inclusion of AES within the NSA on a policy basis. There was no suggestion that the approval should be time-limited. In fact, on the issue of cost allocation Staff stated: “If Terasen Gas is able to demonstrate that the use of timesheets, direct charges and overhead allocations would result in none of the costs that are incurred for Alternative Energy Solutions including down time and the costs of consultants and studies to be borne by gas customers, then Commission staff’s concern is addressed.” The FEU objected to the comment letter on procedural grounds, but it remained a part of the NSA. FEU Exhibit Book, tab 6.

, and other participants. The Commission Panel determined that the NSA was

“just and reasonable”, without expressing any reservations or initiating a process to re-examine

21 Government filed a letter of comment that supported the inclusion of AES in the NSA: “Alternative Energy Solutions is a new type of service that TGI proposes to offer to existing and new customers. Geo-exchange, solar-thermal and district energy systems offer the potential to reduce greenhouse gas emissions, and as such, the Ministry is encouraged that TGI is proposing to offer this new type of service.” FEU Exhibit Book, tab 6.

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any aspects of the NSA.22 The Commission’s NSP Guidelines emphasize the importance of

upholding the NSA once approved.23

(c) New AES Projects to be Submitted According to NSA

A Commission order approving an NSA based on a full

consideration of the evidence is just as valid and enforceable—and carries the same weight

going forward—as an order issued following a written or oral hearing process.

23. The FEU expects that applications for approval of agreements with new AES

customers will be brought forward pursuant to the Commission’s 2010-2011 RRA Order in short

order. The Commission’s consideration of these agreements must proceed according to

commercial timelines, and not be tied up in this Inquiry. The FEU intends to file the agreements

separately, pursuant to the approved process stipulated in the NSA.24

(d) Summary

24. As set out above, the FEU have relied on, and continue to rely on the

Commission’s 2010-2011 RRA order approving AES rate structures in significant ways. The

Commission cannot, as part of this Inquiry, entertain the prospect that the Commission can

eliminate the rate schedule that is the only means of recovering costs spent to date. FEU

22 This action is contemplated in the NSP Guidelines. The Guidelines state at p.9 for instance: “The Commission

panel will normally accept or reject the entire settlement package but if the Commission panel decides to suggest changes to the settlement it will give registered intervenors full opportunity to address any proposed change, including sufficient time to make submissions on the impact of any change to the validity of the overall settlement.” FEU Exhibit Book, tab 16.

23 The NSP Guidelines state at p. 9, for instance: “The benefits of the negotiated settlement process will only be realized if participants are bound to the terms of the agreement.” And further: “Amendments will not be made once the Commission panel has reviewed and accepted the terms of a settlement.” FEU Exhibit Book, tab 16.

24 FEI has a number of Thermal Energy Service (TES) projects for which there are recently signed agreements with customers or finalizing and signing of the agreements is imminent. In terms of signed TES agreements FEI has one in place with a developer for a condominium project in Tsawwassen (Shato Holdings) and one for the Helen Gorman School in Kelowna. Signed agreements are expected to be in place soon for the Delta Schools project and two other condominium developments. In addition, FEI is actively working on District Energy Projects in Kelowna, Coquitlam, Quesnel and the District of North Vancouver. For the two projects with signed agreements FEI is in the process of preparing applications to file with the Commission for approval of the rates, in keeping with the terms of the approved FEI 2010-2011 RRA NSA. FEI anticipates filing these applications within the next 60 days. Applications for the other three nearly-complete agreements, as well as the District Energy Projects, will also be submitted for Commission approval of the rates soon after the agreements have been finalized and signed. FEI is also currently working on many other TES projects at varying stages of completion not listed above, some of which may have signed agreements in place in 2011. FEI will file for Commission approval of the rates after the signed agreements are in place.

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submits that it must be allowed to file contracts for approval as contemplated by the NSA,

without those commercial arrangements being caught up in this Inquiry. Unless there is a

preliminary determination to exclude this issue from the Inquiry, there is a real potential for the

Complainants to misuse a lengthy Inquiry process as a means of disadvantaging the FEU in

competing for customers in the interim period.

C. NON-ISSUES THAT SHOULD BE SET ASIDE AT THE OUTSET

25. The Staff Working Paper identifies as issues a number of matters that are either

long-settled and beyond doubt, founded on a misconception of the law, or concerned with

legislative matters beyond the control of any parties. These issues are as follows:

(a) Issues relating to whether AES are a regulated public utility service in British Columbia, or assume that AES are non-regulated businesses (“NRBs”);

(b) Issues relating to the applicability of the RMDM Guidelines;

(c) Issues relating to whether the FEU are or can be constrained in the use of the FortisBC name; and

(d) An issue inquiring about the potential for the LGIC to use section 18 of the CEA to identify “prescribed undertakings”.

For the reasons set out below, the FEU submit that the Staff Working Paper issues falling within

these categories should be excluded from the scope of the Inquiry in recognition of the legal

framework created by the Act and the importance of maintaining an efficient Inquiry process.

(a) AES is a Regulated Public Utility Service

26. The following issues included in the Staff Working Paper inquire, either directly

or indirectly, about whether or not AES are a regulated public utility service, or assume that AES

are, or could be, provided to the public as a non-regulated service:

• “Are members of Energy Services Association of Canada (ESAC) public utilities as defined in the Utilities Commission Act?” [Issue 1, sub-issue]

• “Can an AES and fuelling service provider remain unregulated under the UCA?” [Issue 5, sub-issue]

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• “Is there appropriate separation of regulated and non-regulated businesses in the current website of the utility fortisbc.com similar to the previous separation of business in the websites of terasengas.com (regulated) and terasen.com (non-regulated)?” [Issue 5, sub-issue]

• “What products and services related to AES and New Initiatives are in the proper domain of a public utility?” [Issue 5, sub-issue]

• “Should the transfer of assets and services from TES to FEI be subject to review?”25

27. For the reasons set out below, the FEU submit that AES are regulated public

utility services under the UCA. This issue has been decided previously on a number of occasions

in respect of other utilities and the same principles should be applied to the FEU. As a result,

the above “issues” should be excluded from the scope of this Inquiry.

[Issue 6, sub-issue]

28. The Commission’s jurisdiction to regulate an entity and its services is defined by

the definition of “public utility” in section 1 of the UCA. The key sections in Part 3 of the UCA

(e.g. sections 45, 44.1, 44.2, 59-61) are applicable only to a “public utility”. The definition of

“public utility” provides in part:

"public utility" means a person, or the person's lessee, trustee, receiver or liquidator, who owns or operates in British Columbia, equipment or facilities for

(a) the production, generation, storage, transmission, sale, delivery or provision of electricity, natural gas, steam or any other agent for the production of light, heat, cold or power to or for the public or a corporation for compensation, or… [Emphasis added.]

29. The FEU has an approved GT&C’s Section 12A “Alternative Energy Extensions”

that describes the services subject to its terms and conditions as including geothermal, solar-

thermal and district energy systems.26 In general terms, the AES systems contemplated by the

FEU use one or more fuel sources, generally including natural gas27

25 This sub-issue has been included in this group because the transfer of regulated assets are necessarily subject

to Commission review under section 52 of the UCA, and the transfer of non-regulated assets are not.

, to provide thermal energy

to customers attached to the system. The customer is charged a rate for thermal energy. AES

26 FEU Exhibit Book, tab 18. 27 Natural gas service within these AES projects would be billed under existing natural gas tariffs.

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as described in the approved GT&C’s Section 12A are, by definition, subject to regulation by the

Commission because they involve the provision of thermal energy (heat or cold) to the public or

a corporation for compensation. The same is true regardless of who – the FEU, ESAC members

or Corix—owns the infrastructure used to provide thermal (heat or cold) energy service to the

public for compensation. Instances where a thermal energy service provider will not be

regulated are if the entity does not provide thermal energy (heat or cold) to the public or a

corporation for compensation (e.g., it is using the thermal energy for its own purposes or is not

seeking compensation), if the alternative energy service fits within an exception under the

definition of “public utility” (e.g., the entity is owned by a municipality), or if the public utility is

exempted by regulation under section 22 from the application of Part 3 of the UCA by

regulation. None of these exceptions applies to the FEU, and the FEU anticipates that the

answer is the same for Corix.

30. In the case of the FEU, the Commission implicitly acknowledged its jurisdiction

over AES (geothermal, solar thermal and district energy systems) provided by the FEU in

approving GT&C Section 12A “Alternative Energy Extensions”. Even before the Commission

approved the FEU’s (public utility) rate structures for AES as part of the 2010-2011 RRA, the

Commission had been regulating similar systems as public utility services for many years. The

following systems currently provide thermal energy to the public for compensation, were

granted CPCN’s by the Commission, and have Commission-approved rates:

(a) Dockside Green - The Commission granted a CPCN to the Dockside Green Energy LLP on April 17, 2008, to construct and operate a district energy system to provide energy service to the Dockside Green development built on the Inner Harbour in Victoria. The facility applied for was a biomass facility to provide hot water heating to the development.28

(b) Corix UniverCity - Corix Multi-Utility Services Inc. filed an Application for a CPCN to construct and operate an alternative energy-based district energy system for the UniverCity residential community on Burnaby Mountain. The proposed

FortisBC Alternative Energy Services Inc. and the Complainant Corix are part owners of the Dockside Green utility.

28 In the Matter of an Application by Dockside Green Energy LLP for Approval of a CPCN to Construct and Operate

a District Energy System for the Dockside Green Project in Victoria B.C., April 17, 2008, Reconsideration Decision, June 30, 2008. FEU Exhibit Book, Tabs 10 and 11.

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district energy system would consist of a production facility and a distribution system. The production facility is planned to be built in two steps: a natural gas fuelled temporary Central Energy Plant (CEP) followed in 2016 by a permanent CEP fuelled by an alternative energy source likely to be Biomass. The Commission granted the CPCN for the temporary CEP only last month.29

(c) Central Heat Distribution Limited – Central Heat has held a CPCN since June 11, 1968, which was issued by the Public Utilities Commission to construct and operate a steam generating plant and attendant distribution system for the purpose of supplying steam for heating and cooling uses in the City of Vancouver.

30

31. Section 45 only applies to a “public utility”, and by definition a CPCN can only be

issued to a “public utility”. Similarly, the rate setting provisions relied upon to fix rates for each

of the above district energy (AES) systems only apply to a “public utility”. In each of the above

cases, it is evident that the Applicants and the Commission took for granted that the system

was regulated and required a CPCN and approved rates. For instance, in the recent Corix

UniverCity application, there was not a single IR inquiring about this issue and no mention of

the issue in the Commission’s decision granting a CPCN pursuant to section 45 of the UCA.

Rates have been approved by the Commission ever since.

32. The proper interpretation of the UCA is a legal issue that does not require

evidence in this Inquiry to determine. In light of the significant body of precedents, and the

straightforward nature of the definition of “public utility”, there is no basis to proceed with the

issues set out above at paragraph 26 any further. The Commission should find, as part of the

scoping order, that these are regulated public utility services.

(b) RMDM Do Not Govern the Relationship Between Two Regulated Classes of Service

33. Issues relating to the applicability and effect of the RMDM Guidelines are closely

related to the issue of whether AES is a public utility service. The Staff Working Paper includes

the following issues relating to RMDM in the context of the FEU providing AES:31

29 Corix Multi-Utility Services Inc., Re In the Matter of Corix Multi-Utility Services Inc. British Columbia Utilities

Commission, May 6, 2011. FEU Exhibit Book, tab 9.

30 See discussion In the Matter of the Energy Act and In the Matter of Applications by Central Heat Distribution Limited, Decision, October 22, 1975, p. 1; FEU Exhibit Book, tab 8.

31 RMDM was also raised by Corix.

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• “… Are the RMDM … Guidelines still relevant and applicable in regulating FEI’s entry into ‘new’ business or should they be updated to reflect the current energy operational and planning environment. Have there been deviations from the RMDM Guidelines by FEI in some of its activities?” [Issue 6, sub-issue]

• “Do the RMDM Guidelines adequately address generation and delivery infrastructure for thermal energy as part and parcel of ‘core utility assets’? [Issue 6, sub-issue]

• “How should the Commission deal with programs or activities that in some ways go outside the RMDM Guidelines.” [Issue 6, sub-issue]

• “Are the AES, refuelling stations, and district energy systems’ core monopoly projects as contemplated in RMDM?” [Issue 6, sub-issue]

34. RMDM addresses the relationship between a regulated and non-regulated

business, not the relationship between two regulated classes of service within a single utility. 32

35. There are specific sections of the UCA contemplating the regulation of multiple

“classes of service”

As described above, AES—whether provided by the FEU, Corix or ESAC members—is a

regulated public utility service upstream of the utility meter, just like natural gas or electricity

utility services. Hence, the relevant issue for the Inquiry is not RMDM, but rather how the UCA

addresses the relationship between two regulated “classes of service” within the same public

utility.

33

21(2) The provision by a public utility of a class of service in respect of which the public utility is not subject to the legislative authority of the Province does not make this Part inapplicable to that public utility in respect of any other class of service.

within a single utility, which although not mentioned in the Complaints or

the Staff Working Paper, should be a key focus of the Inquiry. These sections include:

32 At p. 1, the RMDM states: “This document summarizes the submissions made with respect to the staff position

paper and concludes with the findings of the Commission with respect to the participation of utilities and their NRBs in the retail market downstream of the utility meter.”; FEU Exhibit Book, tab 17. [Emphasis added.] See also the opinion of Commission Counsel; FEU Exhibit Book, tab 19.

33 The Act defines “service” as follows: “’service’ includes (a) the use and accommodation provided by a public utility, (b) a product or commodity provided by a public utility, and (c) the plant, equipment, apparatus, appliances, property and facilities employed by or in connection with a public utility in providing service or a product or commodity for the purposes in which the public utility is engaged and for the use and accommodation of the public.” FEU Exhibit Book, tab 2.

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…

60 (1) In setting a rate under this Act

(c) if the public utility provides more than one class of service, the commission must

(i) segregate the various kinds of service into distinct classes of service,

(ii) in setting a rate to be charged for the particular service provided, consider each distinct class of service as a self contained unit, and

(iii) set a rate for each unit that it considers to be just and reasonable for that unit, without regard to the rates fixed for any other unit.

36. The 2010-2011 RRA NSA expressly contemplated that AES be treated as a

separate “class of service” according to the UCA, and there have been other examples of a

public utility offering different classes of service over the years:

(a) BC Hydro had gas and electric classes of service prior to the sale of the gas assets.

(b) FEI provides propane service in Revelstoke in addition to providing natural gas service and AES service.

(c) As implied by its name, “Corix Multi-Utility Services Inc.” offers multiple services (e.g. water, wastewater, gas, heat, electricity, etc.) within a single entity. Corix’s letter describes itself as providing “multi-utility services, including alternative energy services” [Emphasis added.] Different projects within the Corix company even earn a different return on equity.

37. The Commission has acknowledged the benefits of having different classes of

service under one public utility, as opposed to a proliferation of small, but related utilities

under the same parent:

Certainly, it is likely to be less efficient and more costly from the Commission´s perspective to regulate a number of small utilities, rather than one larger utility serving the same customers. Going forward, the Commission expects TES and TGI to consider and address this concern when they are developing plans to serve new

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developments and groups of customers that are in or near TGI´s service area. The Commission is not certain that a proliferation of small, but related utilities, all under the same parent, TI or KMI, is necessarily in the public interest.34

38. For these reasons, the FEU submit that issues relating to RMDM should be

removed from the scope of this proceeding and replaced with issues addressing how the UCA

treats multiple “classes of service” within the same public utility. The FEU have formulated

appropriate issues in the list of issues included as Appendix “A” to this Submission.

(c) Use of FortisBC Name

39. The Staff Working Paper sets out two issues regarding the right of a public utility

to trade on its market profile and goodwill:

• “Do existing regulatory guidelines disallow FEI from trading on its market profile?” [Issue 5 sub-bullet]

• “Is there appropriate separation of regulated and non-regulated businesses in the current website of the utility fortisbc.com similar to the previous separation of business in the websites of terasengas.com (regulated) and terasen.com (non-regulated)?” [Issue 5, sub-issue]

The FortisBC name is owned by the non-regulated parent company and licensed to the

regulated utilities.

40. This would not be an appropriate issue even if the FortisBC name was owned by

the FEU. In the RMDM proceeding the Commission considered submissions and an opinion

from Commission Counsel (Mr. Fulton) on this issue. Mr. Fulton’s opinion stated in part:

In our opinion, regulated public utilities in B.C. have the right to own goodwill and their corporate name unless there is a specific legislative rule to the contrary. Furthermore, the shareholders of the public utility own a share of those assets, subject to legislation to the contrary. We considered the provisions of the Company Act, the Utilities Commission Act, and the B.C. Hydro and Power Authority Act. There are no provisions in any of the three statutes that specifically state that a public utility does not own its goodwill and corporate

34 Gateway Lakeview Estates CPCN Decision, December 14, 2006, p. 2; FEU Exhibit Books, tab 12.

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name, nor are there any provisions that affect the principle that shareholders own a right to share in the goodwill of a public utility upon dissolution.35

41. The FEU is using the FortisBC name for its own regulated services, something

that in Commission Counsel’s opinion (relied upon by the Commission in the RMDM process) it

would have the right to do even if the FEU owned, rather than licensed, the name.

36

42. Alternatively, in the event that the Commission includes this issue in the Inquiry,

it should not be limited to the FEU’s provision of AES. Of particular note, the Complainant

Corix, which raised the issue, uses its name to promote a variety of services that fall outside of

the Commission’s regulatory purview. If this issue remains in scope, which it should not, the

FEU should be free to pursue this issue with Corix and ESAC.

As a

result, these issues should not be included within the scope of the Inquiry.

(d) Section 18 “Prescribed Undertakings”

43. Under Issue 4 in the Staff Working Paper, the following issue is identified:

• “What is the potential of certain AES, Natural Gas Vehicles (NGV) or biogas undertakings being named as a “prescribed undertaking” for the purpose of reducing greenhouse gas emissions in British Columbia as set out in section 18 of the Clean Energy Act? In setting rates under the UCA for a public utility carrying out a prescribed undertaking, the Commission must set rates that allow the public utility to collect sufficient revenue in each fiscal year to enable it to recover its costs incurred with respect to the prescribed undertaking.” [Issue 4, sub-issue]

44. In order for an undertaking to become a section 18 “prescribed undertaking”

there must be legislative action by government, and only government knows if and when

regulations stipulating new “prescribed undertakings” will be issued. No amount of debate by

the parties in this Inquiry can resolve this issue.37

35 Memorandum of Boughton Peterson Yang Anderson (Gordon Fulton) dated March 10, 1997 to the B.C. Utilities

Commission, p. 10; FEU Exhibit Book, tab 19.

The FEU submit that this irrelevant issue

should be removed in the interest of regulatory efficiency.

36 Memorandum of Boughton Peterson Yang Anderson (Gordon Fulton) dated March 10, 1997 to the B.C. Utilities Commission, pp. 10-12; FEU Exhibit Book, tab 19.

37 Clean Energy Act, section 18; FEU Exhibit Book, tab 1.

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(e) Summary

45. FEU submits that the issues discussed in the above section should be scoped out

of the Inquiry as they have already been decided. Re-visiting these issues in the absence of a

compelling basis to do so will either result in a waste of time and expense, should the

Commission decide these issues as it has done in the past, or it will result in undermining the

Commission’s credibility, if it decides these issues in a manner inconsistent with previous

decisions.

D. NGV, BIOMETHANE, AND EEC BEST ADDRESSED IN ANOTHER CONTEXT

(a) Introduction

46. In this section, the FEU explains why issues identified in the Staff Working Paper

relating to Biomethane, NGV and EEC should be excluded from the Inquiry. An attribute that

the FEU’s EEC, NGV Biomethane and AES initiatives have in common is that they are recently-

introduced low carbon or efficiency-related initiatives designed to respond to public policy and

customer demand. While these issues share common policy and customer drivers, they are

each distinct offerings that raise unique issues at the level of public interest review, rate setting,

and other related regulatory considerations. Many of the policy, public interest and rate design

issues relating to these initiatives have been addressed in prior, initiative specific, proceedings

before the Commission. To the extent that public interest and rate design issues regarding

these offerings remain unresolved, the FEU submits that they should be addressed in another

context.

(b) Staff Working Paper Issues Relating to Biomethane, NGV and EEC

47. The matters raised in the Staff Working Paper relating to Biomethane and NGV

are as follows:

• Do regulatory issues related to AES, biogas, and Natural Gas Vehicles overlap? [Issue 2]

• Should a hearing process be limited to a single activity, e.g. AES only? Should the hearing include all “new” energy solutions but have them reviewed by phases

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within a hearing? Should all “new” energy solutions be within one hearing? [Issue 2 sub-issue]

• “Can an AES and fuelling service provider remain unregulated under the UCA?” [Issue 5 sub-issue, Staff Working Paper]

• “As a gas distribution utility, should FEI be allowed to move up the supply chain and keep this activity within the regulated format as proposed in its biogas business model?” [Issue 5, sub-issue]

• “Should there be a ‘call for energy (natural gas)’ to ensure a competitively priced supply of biogas?” [Issue 5, sub-issue]

• “Are the AES, refuelling stations, and district energy systems’ core monopoly projects as contemplated in RMDM?” [Issue 6, sub-issue]

• “Is there appropriate separation of regulated and non-regulated business and FEI? Should there be distinct separation of regulated and non-regulated businesses to avoid any potential for cross-subsidization and would that ensure a level-playing field?” [Issue 6, sub-issue]

48. The matters raised in the Staff Working Paper relating to EEC are as follows:

• “Where approval for Energy Efficiency & Conservation (EEC) funding should be examined – revenue requirements, ad hoc applications, EEC long-term plans, CPCN?” [Issue 4, sub-issue]

• “Non-discriminatory availability of EEC incentive funding to non-FEI affiliated entities.” [Issue 4, sub-issue]

• “How EEC incentive funding should be determined, applied, and monitored to ensure cost-effectiveness.” [Issue 4, sub-issue]

• “Accessibility of EEC incentive funding through a transparent call for tenders.” [Issue 4, sub-issue]

• “Should AES applications be heard before or in conjunction with an EEC funding request.” [Issue 5, sub-issue]

(c) Overlap is at the Long-Term Planning Level

49. As discussed above, the FEU believe that the EEC, NGV, Biomethane and AES

initiatives are unique, and that each initiative has had the unique aspects of its intended

market, business model proposals, and regulatory constructs extensively canvassed in prior

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proceedings before the Commission. Each initiative will continue to be examined in initiative-

specific regulatory proceedings. A significant common thread that commends the examination

of overlap issues among these initiatives in future LTRPs is that they will all affect natural gas

demand going forward as they grow and develop. Long term natural gas and thermal energy

demand forecasts, and their impact on supply resources and infrastructure, and their potential

contribution to provincial energy objectives are all appropriate aspects to deal with in future

FEU resource planning processes.

(d) Upholding Prior Determinations on NGV, EEC and Biomethane

50. The FEU submit that the Commission should strive to avoid relitigating or

duplicating prior or current proceedings based on the same policy and evidentiary framework.

Biomethane38, NGVs39 and the EEC40

(e) Comprehensive Regulatory Review of Biomethane Completed

framework have been addressed in previous or current

proceedings before the Commission. The Commission, in establishing the scope of this Inquiry,

must not assume that a further review of previously determined matters relating to the

Biomethane, NGV and EEC initiatives will yield a more accurate result than the original

proceedings. Revisiting the same issues relating to Biomethane, NGV and EEC based on an

unchanged evidentiary, legal, and policy context necessarily results in one of two undesirable

outcomes: either the same result is reached, in which case the Inquiry has been wasteful of

Commission and participant resources, or an inconsistent result on the same issue will, in and

of itself, undermine the credibility of the process. In the remaining subsections, FEU outlines

the issues that have already been resolved regarding Biomethane, NGV, and EEC.

51. The FEU brought forward a Biomethane proposal in the 2010-2011 RRA. In the

NSA, the parties agreed that the FEU would drop that proposal in the RRA, and instead bring

38 FEI filed the Biomethane Application on June 8, 2010; the decision approving the application was made on

December 14, 2010, Order No. G-194-10; FEU Exhibit Book, tab 13. 39 FEI filed the Application for Approval of a Service Agreement for Compressed Natural Gas Service and for

Approval of General Terms and Conditions for CNG and Liquified Natural Gas Service, on December 10, 2010; the decision is currently pending.

40 FEI and FEVI filed the EEC Application on May 28, 2008; the decision approving EEC funding was made on April 16, 2009 (Order No. G-36-09); FEU Exhibit Book, tab 4.

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forward a Biomethane Application during the test period.41

(a) the supply model (two supply models with the primary difference being who owns and operates the upgrader);

FEI filed the Biomethane

Application on June 8, 2010. In the Biomethane Application, the Company set out an end to

end business model that addressed:

(b) the specific rate offering allowing for a notional sale of Biomethane to FEI customers who elect the service on a voluntary basis; and

(c) a cost allocation and recovery model which provided for the recovery of costs for the product offering from various customer groups.

52. FEI filed a significant amount of evidence, and there were two substantial rounds

of information requests.42 The Biomethane proceeding was comprehensive and involved the

participation of several interveners representing both customer groups and environmental

groups.43 The Commission issued its decision on December 14, 2010. The Commission

summarized its determinations in the proceeding as follows:44

In its review of the Application, the Commission Panel raised and examined a number of issues in reaching the determinations made in this Decision. The first group of these includes the following: the alignment with British Columbia’s energy objectives and Provincial Government policy, the adequacy of supply for these and future Projects and the level of customer demand for this type of program. On the basis of this examination, the Panel is satisfied the Program is in alignment with both British Columbia’s energy objectives and Provincial Government policy and there is sufficient demand and supply to justify moving forward. Accordingly, the Panel has determined the two Projects are in the public interest and has approved both of them as well as the related capital

41 See NSA p. 11: “The Parties agree that TGI will bring forward an application (the ‘Biogas Application’) during

the test period that will: (a) address the economic assessment model; and (b) provide Biogas rates (including green rate, transportation rate, etc,); and (c) provide for recovery of costs associated with providing Biogas service. TGI may include in the Biogas Application any Biogas Projects under development at that time. TGI is, however, not precluded from applying for Commission approval in respect of individual Biogas Projects at any time, either prior to the Biogas Application or afterwards.” The resolution in the NSA regarding Biogas was driven by the “Issue of Particular Concern to the Commission Panel” identified at the outset of the NSP. It specified: “Biogas – to be reviewed by a CPCN which demonstrates market uptake of customers that are willing to pay the full cost.” FEU Exhibit Book, tab 5.

42 There were over 500 IR’s in this regulatory process. 43 The Commission received final submissions from: CEC, BC Hydro, BCSEA, and BCOAPO. 44 Biomethane Decision, p. 2; FEU Exhibit Book, tab 13.

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costs. However, the Panel in reaching this determination has noted that it would be prudent for TGI to thoroughly test the proposed model in the marketplace before reaching a conclusion as to its full market potential.

53. The Commission approved the Biomethane program on a test basis for two

years. The Commission explained the rationale of this period as follows: “We believe that

reducing this time period to a period of two years will allow TGI sufficient time to launch some

additional projects and undertake the analysis necessary to provide an adequate basis for

review.”45

54. Thus, the outcome of the Biomethane Application was that the Commission has

determined that all aspects of the Biomethane offering are regulated public utility services, and

that the offering is aligned with “British Columbia’s energy objectives”, and that the two

projects were in the public interest generally. These and the other issues decided in the

Biomethane Decision should not be re-litigated, as nothing material has changed since then.

The Commission directed FEI to file a post-implementation report within two years

of the date of the order (i.e. December 14, 2012), and to hold a post-implementation workshop

at which it will address the contents of the report.

55. There are outstanding issues that the Commission set aside for future

determination, specifically the Commission did not address an issue regarding ownership of the

upgrading facilities.46

(f) Comprehensive Review of NGV Completed

However, this Inquiry is being initiated well before the end of the two

year review period. The Biomethane program roll out to customers is set to occur this month.

The Commission recognized in the Biomethane Application Decision the need for a period of

time to elapse to allow FEI to undertake the analysis necessary to provide an adequate basis for

the Commission to review the issues identified in the decision in its post-implementation

report. FEI submits that the previously established two year review process, and not this

Inquiry, is the appropriate forum in which to address outstanding issues relating to

Biomethane.

45 Biomethane Decision, p. 56; FEU Exhibit Book, tab 13. 46 Biomethane Decision, p. 2; FEU Exhibit Book, tab 13.

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56. The approved 2010-2011 RRA NSA contemplated the FEU bringing a

comprehensive NGV Application,47 which FEI filed with the Commission on December 1, 2010.

The FEI filed a substantial body of evidence in support of the NGV Application. There were

three rounds of information requests, consisting of over 500 questions. In addition to FEI, the

Commission received final submissions from three customer groups,48

57. The scope of the NGV Application was such that the Commission has heard

evidence on, and participants have commented on, a number of issues relating to NGV

including: (a) whether the proposed GT&C’s for CNG and LNG Service are just and reasonable,

and (b) whether investment in CNG and LNG facilities are in the public interest. These two

broad issues required the Commission to consider British Columbia’s energy objectives, the

benefits and risks to customers of investing in refuelling infrastructure, the potential economic

benefits to NGV customers, and the scope of the definition of “public utility” as it applies to

CNG and LNG services.

all of whom supported

the NGV Application. The Commission’s decision on FEI’s NGV Application remains outstanding.

58. The issues identified by the Staff Working Paper are all encompassed within the

issues addressed in the NGV Application. FEI submits that it is inappropriate for the Inquiry to

address matters that have already been addressed in the NGV Application that were heard,

argued, and are currently outstanding. Such matters should be excluded from scope consistent

with administrative law principles that dictate avoiding re-litigation of issues based on the same

(or substantially similar) evidence, avoiding inconsistent decisions, and in the interest of an

efficient process for all stakeholders. The FEU included in the 2012-2013 RRA filed on May 4,

2011, the revenues and costs related to this business for FEI, which has a positive impact in

reducing delivery rates for natural gas customers. These issues must, by their very nature, be

addressed in the RRA and should not be litigated here as well.

47 See NSA at p. 10: “The Parties acknowledge that TGI intends to develop this area of business and that TGI

anticipates it will bring forward applications on NGV projects to the Commission on a case-by-case basis during the term of this Agreement and in future years. The Parties agree that TGI is at liberty to do so.” FEU Exhibit Book, tab 5.

48 BCOAPO, CEC, and BCSEA.

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(g) EEC Issues Addressed in Comprehensive EEC Application, RRA, and EEC-NGV Proceeding

59. There has been significant process on EEC issues to date, and there are processes

currently underway that are also addressing EEC issues. The FEU submit that adding EEC issues

to this Inquiry results in administrative inefficiency and re-litigating issues based on

substantially the same evidence and policy.

60. On May 28, 2008, FEI and FEVI filed the EEC Application, for EEC funding for the

2008-2010 period. On April 16, 2009, the Commission issued Order No. G-36-09. It approved

EEC funding in aggregate of $41.5 million ($34.4 million for FEI and $7.1 million for FEVI),

deferral treatment of all expenditures with an amortization period of 10 years, and approval of

a portfolio approach to evaluating the costs and benefits of the overall EEC portfolio. FEI and

FEVI obtained approval in their respective 2010-2011 RRAs for EEC funding for 2010 and 2011

based on the same EEC framework approved in the EEC Application.

61. In April 2011, the Commission initiated a further regulatory review process on

the use of EEC incentives for NGV (the “2011 NGV-EEC Proceeding”). The Commission’s review

necessitated a review of the EEC framework as a whole, as the FEU’s understanding of the

approved framework underlies its decision to allocate approved EEC funding to NGV. Customer

groups and other stakeholders (such as the Ministry of Energy and Mines) supported the

Company’s position in these matters. A decision on the 2011 NGV-EEC Proceeding is also

outstanding.

62. The Commission determined as part of the NGV-EEC Proceeding that all other

matters relating to the 2010 EEC Report should be addressed in the 2012-2013 RRA process.

The FEU have also included an EEC funding request for 2012 and 2013 in the RRA, with a

proposal to address future funding beyond 2012 and 2013 in the context of the next FEU LTRP.

63. The Staff Working Paper includes the issue: “How EEC incentive funding should

be determined, applied, and monitored to ensure cost-effectiveness”. This issue raises the very

issues that were previously addressed in the 2009 decision and are currently being clarified in

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the NGV-EEC Proceeding. EEC-related issues should be excluded from this Inquiry, and can be

dealt with as part of the current 2012-2013 FEU RRA process.

(h) Summary Regarding NGV, Biomethane and EEC

64. The appropriate venue for examining new initiatives and their impact on natural

gas demand in BC and helping to achieve BC energy objectives on a comprehensive basis is the

LTRP, as the overlap among these initiatives is most relevant in the long-term planning context.

FEU submits that the Commission should avoiding re-litigating the policy, public interest and

rate design issues canvassed in the EEC, Biomethane, NGV and EEC-NGV Applications, in order

to ensure an efficient proceeding, preserve the credibility of the Commission process, and

ensure that the FEU is able to continue participation in these areas pursuant to existing orders

without disruption. There may well be outstanding issues from the past applications that can

be considered; however, the FEU submit that there are more appropriate venues for addressing

them. All issues relating to EEC, NGV and Biomethane initiatives as set out above in paragraphs

47 and 48 should be excluded from the scope of the Inquiry.

E. FOCUS OF THE GUIDELINES

65. The Inquiry Order states that the proposed Inquiry is established pursuant to

sections 23, 72, 82 and 83 of the Act, and that the Inquiry will be a consideration of “FEI

offering Products and Services in Alternative Energy Solutions and New Initiatives”. The Staff

Working Paper states that the intended outcome of the Inquiry is to make determinations in

the form of “guidelines” for FEI “in its move towards providing Alternative Energy Services and

other New Initiatives”, but also leaves open the possibility of expanding the focus of the Inquiry

to apply to other providers of AES and new initiatives. Guidelines can be an appropriate means

of ensuring administrative consistency in decision making. However, the FEU submit that the

Commission can only issues guidelines on matters falling within its jurisdiction. FEU submits

that some of the issues raised in the Staff Working Paper invite the Commission to exceed its

jurisdiction. In this section, FEU discusses the proposed legislative basis for the Complaints and

the Inquiry, and identifies some key jurisdictional issues that the FEU will raise at the conclusion

of this Inquiry. The jurisdictional issues identified below have been included in the FEU’s

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reformulated issues list attached as Appendix “A” to this Submission. Whatever guidelines are

developed at the conclusion of the Inquiry should be applied equally to other providers of AES,

including Corix and ESAC members.

(a) Section 72 Concerns What a Public Utility “Has Done, is Doing, or Has Failed to Do”

66. Section 72, cited in the Inquiry Order, provides the Commission with a

jurisdiction to hear applications from persons complaining “that a person constructing,

maintaining, operating or controlling a public utility service or charged with a duty or power

relating to that service, has done, is doing or has failed to do anything required by this Act.”

[Emphasis added.] In this Inquiry, the FEU intend to raise the issue of how the words “has

done, is doing or has failed to do anything required by this Act” impact the Commission’s ability

to direct this Inquiry at what FEU can do in the future.

(b) The Limits of the Commission’s Jurisdiction Over Utility Management and Competition

67. Sections 82 and 83 give the Commission the power to inquire into a matter on a

Complaint or “on its own motion”, but such inquiries must be in relation to “a matter that

under this Act it may inquire into, hear or determine on application or complaint”.49

68. A number of issues in the Staff Working Paper presume that the Commission has

jurisdiction over the management of the FEU’s business, which is something that FEU disputes.

A good example of this type of issue is: “Should internal business cases be subject to regulatory

review and reporting…?”

In other

words, any inquiry initiated in response to a complaint or on the Commission’s own motion

must be based on a section of the UCA that provides the Commission with a substantive

jurisdiction to determine a particular subject matter. The FEU will be raising the issues of the

Commission’s jurisdiction over the management of the FEU’s business and its jurisdiction to

regulate competition in this Inquiry.

50

49 Act, section 82; FEU Exhibit Book, tab 2.

Other issues go further, implying that the Commission could make

50 Issue 4, sub-issue.

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determinations regarding whether or not the FEU can pursue AES.51 However, the BC Court of

Appeal’s decision in BC Hydro v. British Columbia Utilities Commission (“BC Hydro v. BCUC”)

makes clear that the management of a public utility remains the responsibility of utility

management.52

56 It is only under s. 112 [now section 97] of the Utilities Act that the Commission is authorized to assume the management of a public utility. Otherwise the management of a public utility remains the responsibility of those who by statute or the incorporating instruments are charged with that responsibility.

The Court of Appeal concluded, for instance:

…

58 Taken as a whole the Utilities Act, viewed in the purposive sense required, does not reflect any intention on the part of the legislature to confer upon the Commission a jurisdiction so to determine, punishable on default by sanctions, the manner in which the directors of a public utility manage its affairs. 53

69. FEU welcomes the opportunity to further explore the scope of the Commission’s

jurisdiction as set out in BC Hydro v. BCUC through this Inquiry. Based on the Court of Appeal’s

decision, the FEU will be arguing in this Inquiry that the Commission’s ability to review a public

utility’s AES projects and initiatives is limited to the extent contemplated in the UCA.

70. The Commission’s ability to prescribe guidelines in the area of competition must

also be addressed in this Inquiry as a number of issues presume that the Commission has

jurisdiction in this area, which FEU disputes. BC Hydro v. BCUC, for instance, makes clear that

this is a live issue:

51 For example, the following issue: “Appropriateness of FEI providing Alternative Energy Solutions (AES) and

other 'new' solutions as a traditional gas distribution utility”. 52 (1996), 20 B.C.L.R. (3d) 106 (C.A.); FEU Exhibit Book, tab 15. 53 The Court of Appeal’s decision included consideration of section 23 (then section 28), which is relied upon by

the Commission in this Inquiry. Specifically, the Court stated at paragraph 32: “Two observations can be made of this section: the first is that the class of matters referred to in s-s. (1) relates to the existing service provided the public as distinct from future service. The second is that s-s. (2) also refers to present service, that is to say, the conduct of operations in relation to the public. Neither of these subsections refers to the utility's plans for the future.”

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51 The Utilities Act runs to over 140 sections. The administration of the jurisdiction conferred upon the Commission is amply delineated by express terms. There is no need to imply terms for this purpose.

There is no express jurisdiction in the Act to regulate “fair competition” or “unfair competitive

advantage”. The FEU will submit in this Inquiry that the Commission’s jurisdiction in this area is

significantly circumscribed.

(c) Summary

71. The final Inquiry scope must account for issues that challenge the Commission’s

ability to guide the management of the FEU’s business and regulate competition. The issues

that touch on these areas should be formulated in a manner that recognizes that jurisdiction in

respect of these matters is a live issue.

F. BALANCED INQUIRY SCOPE AND BALANCED FORMULATION OF THE INQUIRY ISSUES

(a) Introduction

72. In this section, the FEU address the importance of ensuring that the Inquiry

scope permits a balanced consideration of the appropriate issues, and that these issues be

formulated in a neutral manner. The FEU submit that the Inquiry must include additional issues

relating to the benefits of AES to customers of the natural gas service and AES customers, and

how FEU’s pursuit of AES serves British Columbia’s energy objectives. In Appendix “A” to this

Submission, the FEU re-formulate the AES-related issues included in the Staff Working Paper,

and list all of the additional issues raised in this Submission.

(b) Additional Issues that should be Included Within Inquiry Scope

73. The FEU observe that not one of the issues in the Staff Working Paper is directed

to the potential benefits that might flow to customers from the Companies pursuing Thermal

Energy Services. This may be symptomatic of the fact that the Inquiry is a response to

complaints initiated by parties whose interests are in preserving their market position without

having to compete with the FEU. Regardless, the FEU respectfully submits that to the extent

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that this Inquiry is going to review the AES business (the limits of that Inquiry still being a live

issue), there has to be a greater balance in the issues.

(c) Need for Reformulation of Inquiry Issues in Neutral Manner

74. The FEU submit that issues set out in the Staff Working Paper require

reformulation in order to meet the test of fairness. The FEU set out below two examples of

why this is necessary.

75. One example is the issue: “What should be the Commission’s jurisdiction to limit

FEI’s participation in the ‘new’ solutions?” The primary problem with this issue as formulated is

that it appears to presuppose that the Commission has jurisdiction to limit “FEI’s participation”

in “new solutions”. It could also benefit from greater clarity regarding what is meant by “new

solutions”. Also, jurisdictional issues of this nature affect all public utilities, not just the FEU.

76. Another example is the following: “Appropriateness of FEI providing Alternative

Energy Solutions (AES) and other new solutions as a traditional gas distribution utility.” The

concept of a “traditional gas distribution utility” does not exist under the UCA, and as a result,

the Commission cannot regulate the FEU on the basis of this concept. Nor is it appropriate to

regulate on the basis that public utilities must be dedicated to a single service; as indicated

previously, the UCA contemplates multiple classes of service within a public utility. The issues

should be phrased in reference to the legislative framework, which necessitates eliminating any

preconceived notions regarding the appropriate nature of the FEU’s business as a public utility.

77. The FEU have, in Appendix “A” to these Submissions, reformulated the issues

that it considers appropriate for the Inquiry in a neutral fashion. Any other issues that the

Commission adds should also be framed in a neutral fashion that is consistent with the UCA. In

Appendix ”B”, FEU provides a table of concordance that lists all issues from the Staff Working

Paper and indicates whether or not the FEU considers them to be appropriate. The table also

indicates the section of this Submission where FEU discusses the issue (to the extent that FEU

considers that the issue should be excluded from the Inquiry).

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PART THREE: INQUIRY PROCESS

78. The importance of these issues, not just for the Company but for all of the FEU’s

customers, makes it vitally important that the Inquiry proceed according to a fair process that

gives the FEU a full opportunity to present evidence and respond to the two Complaints from

competitors.

(a) Proposed Hearing Process (Assuming Scope is as FEU Proposes)

79. The reformulated issues list in Appendix “A” divides the issues into “procedural

issues” and “substantive issues”.54

(a) The FEU submit that the Commission Panel will benefit from having the ability to directly engage persons specifically involved in the businesses.

FEU submits that a written procedure is most efficient for

addressing the procedural issues. However, the FEU submit that an oral hearing process to

address the “substantive” issues is appropriate in the circumstances. The oral hearing should

involve not only FEU panels but also representatives of Corix and ESAC, and any others that

choose to file evidence. There are several reasons for this:

(b) The immediate impetus for this Inquiry are the two Complaints made by ESAC and Corix that go to the heart of a significant corporate initiative. As a matter of procedural fairness, the FEU must be permitted to have full latitude to inquire into the basis for those Complaints and cross-examine their representatives under oath on the materials they have put forward. Particular issues of importance to the FEU include:

• the FEU do not accept the characterization of all of the key facts in those complaints;

• there are a number of similarities with the business model of Corix that must be explored; and

• the nature of the market in which Corix, ESAC and the FEU operate.

(b) Other Process Matters

54 In the table set out in Appendix “A”, FEU has listed the procedural issues first, followed by the substantive

issues (as indicated by the headings embedded within the table).

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80. In order to ensure an efficient Inquiry, legal issues should be addressed only

through legal submissions, and not piecemeal through IRs. If there are particular issues that the

Commission wishes to have addressed in legal submissions, those can and should be articulated

for the parties and their legal counsel in advance of final legal submissions. Avoiding

redundancy through IRs directed at legal issues will help to keep this broad Inquiry more

manageable for the participants.

PART FOUR: INQUIRY TIMING

81. The FEU propose the following preliminary timetable for discussion at the

procedural conference. It is based on the scope of the proceeding as articulated in the

Submissions, and the assumption that a determination on scope will be made in the near future

so that FEU can proceed with preparing its evidence. Should either of these assumptions prove

incorrect, FEU may require more time than indicated to make its evidentiary filing.

Procedural Conference June 15, 2011 FEU Comprehensive Evidentiary Filing August 31, 2011 Commission IR No. 1 to FEU September 14, 2011 Intervenor and Complainant (ESAC/Corix) IR No. 1 to FEU

September 21, 2011

FEU Responses to Commission, Intervenor and Complainant IR No. 1

October 21, 2011

Commission IR No. 2 to FEU November 10, 2011 Intervenor and Complainant IR No. 2 to FEU November 14, 2011 FEU Responses to Commission, Intervenor and Complainant IR No. 2

November 30, 2011

Complainant (ESAC, Corix) and Intervenor Evidence

December 20, 2011

Commission IR No. 1 to Complainants (ESAC, Corix) and Intervenors

January 14, 2012

FEU IR No. 1 to Complainants (ESAC, Corix) and Intervenors

January 20, 2012

Complainant (ESAC, Corix) and Intervenor Responses to Commission and FEU IR No. 1

February 5, 2012

Commission IR No. 2 to Complainants (ESAC, Corix) and Intervenors

February 10, 2012

FEU IR No. 2 to Complainants (ESAC, Corix) and Intervenors

February 14, 2012

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Complainant (ESAC, Corix) and Intervenor Responses to Commission and FEU IR No. 2

February 28, 2012

FEU Rebuttal Evidence March 14, 2012 Oral Hearing Commences April 15, 2012

82. The FEU submit that the following considerations support the proposed timeline:

(a) As set out above, the FEU has been addressing issues relating to AES since 2008.

For this reason, the evidentiary filing in this matter will require the review and

assimilation of a substantial amount of evidence in order to prepare a proper

and responsive evidentiary filing for the Inquiry.

(b) The issues raised in this Inquiry, even on FEU’s proposed reformulation, are

broad and sweeping. FEU will require sufficient time to prepare a proper and

responsive evidentiary filing.

(c) FEU submits that, while the Complainants may wish to push this matter ahead

expeditiously, the Commission should consider the broader interests at stake,

and in particular the interests of FEU’s ratepayers.

PART FIVE: CONCLUSION

83. The FEU have been pursuing initiatives since 2008 that are directed to ensuring

that natural gas remains a part of the energy picture for many years to come, while meeting

customer demand for new low carbon energy offerings. Legislation such as the Clean Energy

Act and amendments to the Utilities Commission Act have affirmed the role of public utilities at

the forefront of the implementation of government policy on the efficient use of energy forms

and greenhouse gas emissions (“GHGs”). However, it is evident that there remains a disconnect

between FEU’s belief that it needs to continue as an integrated energy provider to meet the

needs of all of its customers and respond to government policy, and the view suggested by the

Staff Working Paper that the FEU are still “traditional natural gas” distribution utilities. The FEU

are hopeful that this Inquiry, when properly scoped and subject to an appropriate process, will

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resolve these recurring issues from past proceedings so that FEU can move forward for the

benefit of natural gas and AES customers.

ALL OF WHICH IS RESPECTFULLY SUBMITTED.

Dated: June 9, 2011 [original signed by Matthew Ghikas] Matthew Ghikas Counsel for FortisBC Energy Utilities Dated: June 9, 2011 [original signed by David Curtis] David Curtis Counsel for FortisBC Energy Utilities

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APPENDIX “A”: REFORMULATION OF INQUIRY ISSUES

The issues listed in the left-hand column below are the remaining issues from the Staff Working

Paper, once issues that the FEU have identified as problematic have been removed. In the

right-hand column, the FEU have reformulated the issues where necessary to bring greater

clarity or balance to the issue. The issues below have been divided into procedural questions

and substantive questions because the FEU is proposing a written process for the procedural

issues and an oral process for the substantive issues.

Table A-1

Procedural Issues (written procedure)

# Staff Working Paper Formulation of Issues

FEU Reformulation of Issues

1 Whether the Inquiry should proceed as a generic proceeding or whether FEI or FortisBC Energy Utilities (FEU) should be the subject of this Inquiry. [Issue 1, sub-issue]

Whether the Inquiry should proceed as a generic proceeding or whether FEI or FortisBC Energy Utilities (FEU) should be the subject of this Inquiry.

2 Treatment of an integrated energy service provider as a public utility – what should be the appropriate regulatory format? [Issue 5, sub-issue]

What are the appropriate regulatory processes for approvals relating to regulated alternative energy services?

3 Where should the new rate structures be examined – revenue requirements, ad hoc applications, portfolios in resource plan/ action plan, certificate of Public Convenience & Necessity (CPCN)? [Issue 3, sub-issue]

Should proposed new rate structures for AES service be examined in the public utility’s revenue requirements, CPCN applications, resource plan filings, rate design applications, or in stand-alone applications?

4 Should general terms and conditions for New Initiatives be used as a framework for future AES and New Initiatives customers? [Issue 3, sub-issue]

Should proposed new AES service be subject to general terms and conditions.

5 …should subsequent filings be streamlined once the first AES and New Initiatives are approved? [Issue 4, sub-issue]

Should subsequent filings be streamlined once the first AES and New Initiatives are approved?

6 Additional issue proposed by FEU. What should the filing requirements be for AES CPCN’s and other AES filings?

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Substantive Issues (oral hearing)

# Staff Working Paper Formulation of Issues

FEU Reformulation of Issues

7 If a public utility that already provides a non-AES class of service wishes to provide an AES service…

8 Potential partners and competitors to FEI in AES and New Initiatives. Impact on FEI’s stakeholders and the role/need of public consultation with affected stakeholders. [Issue 4, sub-issue]

Should the public utility be required to engage in stakeholder consultation before being allowed to provide such service? If so, who should be consulted and with respect to what?

9 Should the products and services to be offered by a regulated public utility be defined by the Commission? What should be the Commission’s jurisdiction to limit FEI’s participation in the ‘new’ solutions? [Issue 6, sub-issue]

To what extent, if any, can the Commission prohibit a public utility from entering into the AES business?

10 The desirability of conducting new solutions under a separate regulated entity or non-regulated business entity. [Issue 3, sub-issue]

To what extent, if any, can the Commission dictate the corporate structure that a public utility must utilize to provide AES service (i.e. can the Commission require a public utility to provide such services through a separate corporate entity)? If it can dictate the corporate structure, in what circumstances should the Commission consider dictating the corporate structure?

11 Project risks, stranded assets and recovery from natural gas ratepayers; prospect and the extent of cross-subsidization; and if a project fails, who pays? [Issue 3, sub-issue] Degree of integration with the core natural gas services and how severable should the ‘new’ projects be within an entity? [Issue 3, sub-issue]

What are appropriate measures to ensure that non-AES customers do not cross-subsidize AES customers and vice versa?

12 Project risks, stranded assets and recovery from natural gas ratepayers; prospect and the extent of cross-subsidization; and if a project fails, who pays? [Issue 3, sub-issue]

How should the issue of stranding be dealt with?

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Substantive Issues (oral hearing)

# Staff Working Paper Formulation of Issues

FEU Reformulation of Issues

13 Project risks, stranded assets and recovery from natural gas ratepayers; prospect and the extent of cross-subsidization; and if a project fails, who pays? [Issue 3, sub-issue]

Are any other measures required to protect non-AES customers from any risks associated with the public utility providing a new class of AES service?

14 Are there potential conflicts of interest in FEI taking steps to transform itself into an integrated energy provider? If so, what are these? [Issue 6, sub-issue] Should there be a Code of Conduct and Transfer Pricing Policy to forbid use of market sensitive information to assist in non-core businesses? [Issue 5, sub-issue]

In circumstances where a public utility operates two or more classes of service, does market information reside with the public utility, or a particular class of service? If the latter, what steps are required to ensure that information is used appropriately?

15 Provision of district energy systems and compression and fuelling services by parties other than FEI; the importance to have FEI kick start the market? [Issue 4, sub-issue] Does the Commission have a role in its public interest decision-making to protect a competitive environment? [Issue 4, sub-issue]

What role do considerations relating to competition play with respect to the Commission’s regulation of public utilities?

16 Additional issue proposed by FEU. What factors should the Commission consider when examining the public convenience and necessity or public interest in respect of a proposed AES project?

17 Do tariff provisions, if flowing from a commission order approving an NSA, imply a regulatory policy? To what extent do issues resolved in an NSA become policy positions at the Commission? [Issue 3, sub-issue]

Do tariff provisions, if flowing from a commission order approving an NSA, imply a regulatory policy? To what extent do issues resolved in an NSA become policy positions at the Commission? In what circumstances can or should the Commission revisit past decisions upon which stakeholders may have relied?

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Substantive Issues (oral hearing)

# Staff Working Paper Formulation of Issues

FEU Reformulation of Issues

18 Are the … RP Guidelines still relevant and applicable in regulating FEI’s entry into ‘new’ business or should they be updated to reflect the current energy operational and planning environment. [Issue 6, sub-issue]

Are the Resource Planning Guidelines still relevant and applicable in regulating a public utility’s entry into ‘new’ business or should they be updated to reflect the current energy operational and planning environment?

19 Is FEI the only integrated energy provider (core natural gas distribution and ‘new’ solutions), and will it likely remain the only one in B.C.? [Issue 1]

Is FEI the only integrated energy provider (core natural gas distribution and ‘new’ solutions), and will it likely remain the only one in B.C.?

20 Should internal business cases be subject to regulatory review and reporting; [Issue 4, sub-bullet]

Should internal business cases be subject to regulatory review and reporting?

21 Additional issue proposed by FEU. What are the customer benefits of FEU Providing AES services?

22 Additional issue proposed by FEU. Do AES services achieve British Columbia’s energy objectives?

23 Additional issue proposed by FEU. How does section 60(1)(c) of the UCA apply in the circumstances where the FEU develops a thermal energy class of service?

24 Additional issue proposed by FEU. What precedents are there for a public utility offering multiple classes of service?

25 Additional issue proposed by FEU. How does section 60(1)(c) of the UCA apply to Corix’s providing multiple and different utility services (water, wastewater, gas, heat, electricity etc.) to different customers within the same utility?

26 Additional issue proposed by FEU. How should the public utilities offering AES be guided by the policy previously articulated by the Commission (as expressed in the Gateway Lakeview Estates CPCN decision, Order No. C-22-06) favouring the avoidance of multiple small regulated utilities under the same corporate parent?

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APPENDIX “B” TABLE OF CONCORDANCE

The following table sets out all of the issues from the Staff Working Paper, and indicates

whether FEU submits that they are appropriate or inappropriate for the scope of the Inquiry.

As indicated in Appendix “A”, FEU has proposed reformulations of some of the issues it

considers appropriate. In this table, the issues are as described in the Staff Working Paper. The

far right column indicates where the issue is dealt with in these submissions. For ease of

reference, all of the issues that FEU considers are inappropriate for this Inquiry are shaded in

light grey.

Table B-1

ISSUE # ISSUE FEU RESPONSE

WHERE DISCUSSED IN SUBMISSION

Issue 1 Is FEI the only integrated energy provider (core natural gas distribution and 'new' solutions), and will it likely remain the only one in B.C.?

Appropriate Appendix “A ”, Row 19

Bullet Whether the Inquiry should proceed as a generic proceeding or whether FEI or FortisBC Energy Utilities (FEU) should be the subject of this Inquiry.

Appropriate Appendix “A”, Row 1

Bullet Are members of Energy Services Association of Canada (ESAC) public utilities as defined in the Utilities Commission Act (UCA)?

Inappropriate Section 2C(a)

Issue 2 Do regulatory issues related to Alternative Energy Solutions (AES), biogas, and Natural Gas Vehicles (NGV) overlap?

Inappropriate Section 2D

Bullet Should a hearing process be limited to a single activity, e.g., AES only? Should the hearing include all 'new' energy solutions but have them reviewed by phases within a hearing? Should all 'new' energy solutions be within one hearing?

Inappropriate Section 2D

Issue 3 Appropriateness of FEI providing Alternative Energy Solutions (AES) and other 'new' solutions as a traditional gas distribution utility

n/a n/a

Bullet Where should the new rate structures be examined - revenue requirements, ad hoc applications, portfolios in resource plan/action plan, Certificate of Public

Appropriate Appendix “A”, Row 3

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ISSUE # ISSUE FEU RESPONSE

WHERE DISCUSSED IN SUBMISSION

Convenience & Necessity (CPCN)? Bullet Degree of integration with the core natural

gas services and how severable should the 'new' projects be within an entity.

Appropriate Appendix “A”, Row 11

Bullet The desirability of conducting new solutions under a separate regulated entity or non-regulated business entity.

Appropriate Appendix “A”, Row 10

Bullet Project risks, stranded assets and recovery from natural gas ratepayers; prospect and the extent of cross-subsidization; and if a project fails, who pays?

Appropriate Appendix “A”, Rows 11, 12, 13

Bullet Do tariff provisions, if flowing from a commission order approving an NSA, imply a regulatory policy?

Appropriate Appendix “A”, Row 17

(sub bullet

To what extent do issues resolved in an NSA become policy positions at the Commission?

Appropriate Appendix “A”, Row 17

(sub bullet)

Should the Commission approval be limited to the duration of the test period?

Inappropriate Section 2B

Bullet Should general terms and conditions for New Initiatives be used as a framework for future AES and New Initiatives customers?

Appropriate Appendix “A”, Row 4

Issue 4 Fair Competition n/a n/a Bullet Potential partners and competitors to FEI in

AES and New Initiatives. Impact on FEl's stakeholders and the role/need of public consultation with affected stakeholders.

Appropriate Appendix “A”, Row 8

Bullet Provision of district energy systems and compression and fuelling services by parties other than FEI; the importance to have FEI kick start the market.

Appropriate Appendix “A”, Row 15

Bullet Where approval for Energy Efficiency & Conservation (EEC) funding should be examined – revenue requirements, ad hoc applications, EEC long term plans, CPCN?

Inappropriate Section 2D

Bullet Non-discriminatory availability of HC incentive funding to non-FEI affiliated entities.

Inappropriate Section 2D

Bullet How EEC incentive funding should be determined, applied, and monitored to ensure cost effectiveness.

Inappropriate Section 2D

Bullet Accessibility of EEC incentive funding through a transparent call for tenders.

Inappropriate Section 2D

Bullet Should internal business cases be subject to Appropriate Appendix “A”, Row 20

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ISSUE # ISSUE FEU RESPONSE

WHERE DISCUSSED IN SUBMISSION

regulatory review and reporting; Sub-bullet

Should subsequent filings be streamlined once the first AES and New Initiatives are approved?

Appropriate Appendix “A”, Row 5

Bullet Does the Commission have a role in its public interest decision-making to protect a competitive environment?

Appropriate Appendix “A”, Row 15

Bullet What is the potential of certain AES, Natural Gas Vehicles (NGV) or biogas undertakings being named as a 'prescribed undertaking' for the purpose of reducing greenhouse gas emissions in British Columbia as set out in section 18 of the Clean Energy Act? In setting rates under the UCA for a public utility carrying out a prescribed undertaking, the Commission must set rates that allow the public utility to collect sufficient revenue in each fiscal year to enable it to recover its costs incurred with respect to the prescribed undertaking.

Inappropriate Section 2C(d)

Issue 5 Public Utility Services n/a n/a Bullet Can an AES and fuelling service provider

remain unregulated under the UCA? Inappropriate Section 2C(a), 2D

Bullet Treatment of an integrated energy service provider as a public utility -- what should be the appropriate regulatory format?

Appropriate Appendix “A”, Row 2

Bullet As a gas distribution utility, should FEI be allowed to move up the supply chain and keep this activity within the regulated format as proposed in its biogas business model?

Inappropriate Section 2D

Bullet Should there be a "call for energy (natural gas)" to ensure a competitively priced supply of biogas?

Inappropriate Section 2D

Bullet Should AES applications be heard before or in conjunction with an EEC funding request?

Inappropriate Section 2D

Bullet Do existing regulatory guidelines disallow FEI from trading on its market profile?

Inappropriate Section 2C(c)

Bullet Should there be a Code of Conduct and Transfer Pricing Policy to forbid use of market sensitive information to assist in non-core businesses?

Appropriate Appendix “A”, Row 14

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ISSUE # ISSUE FEU RESPONSE

WHERE DISCUSSED IN SUBMISSION

Bullet What products and services related to AES and New Initiatives are in the proper domain of a public utility?

Inappropriate Section 2C(a)

Bullet Is there appropriate separation of regulated and non-regulated businesses in the current website of the utility fortisbc.com similar to the previous separation of businesses in the websites of terasengas.com (regulated) and terasen.com (non-regulated)?

Inappropriate Section 2C(a), 2C(c)

Issue 6 Retail Markets Downstream of the Utility Meter Guidelines (RMDM) and Resource Planning (RP) Guidelines

n/a n/a

Bullet Are the RMDM … Guidelines still relevant and applicable in regulating FEl's entry into 'new' business or should they be updated to reflect the current energy operational and planning environment. Have there been deviations from the RMDM Guidelines by FEI in some of its activities?

Inappropriate Section 2C(b)

Sub-bullet

Are the RP … Guidelines still relevant and applicable in regulating FEl's entry into 'new' business or should they be updated to reflect the current energy operational and planning environment. Have there been deviations from the RMDM Guidelines by FEI in some of its activities?

Appropriate Appendix “A”, Row 18

Bullet Should the products and services to be offered by a regulated public utility be defined by the Commission? What should be the Commission's jurisdiction to limit FEl's participation in the 'new' solutions?

Appropriate Appendix “A”, Row 9

Bullet Do the RMDM Guidelines adequately address generation and delivery infrastructure for thermal energy as part and parcel of 'core utility assets'?

Inappropriate Section 2C(b)

Bullet How should the Commission deal with programs or activities that in some ways go outside the RMDM Guidelines?

Inappropriate Section 2C(b)

Bullet Should the transfer of assets and services from TES to FEI be subject to review?

Inappropriate Section 2C(a)

Bullet Are there potential conflicts of interest in FEI taking steps to transform itself into an integrated energy provider? If so, what are

Appropriate Appendix “A”, Row 14

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ISSUE # ISSUE FEU RESPONSE

WHERE DISCUSSED IN SUBMISSION

these? Bullet Are the AES, refuelling stations, and district

energy systems' core monopoly products as contemplated in RMDM?

Inappropriate Section 2C(b), 2D

Bullet Is there appropriate separation of regulated and non-regulated business and FEI? Should there be distinct separation of regulated and non-regulated businesses to avoid any potential for cross subsidization and would that ensure a level-playing field?

Inappropriate Section 2D

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FEU EXHIBIT LIST

Legislation

1. Clean Energy Act, S.B.C. 2010, c. 22 (excerpts)

2. Utilities Commission Act, R.S.B.C. 1996, c. 473

BCUC Decisions

3. 2008 TGI, TGVI, TWI Long Term Resource Plan Decision, December 15, 2008

4. 2008 TGI and TGVI Energy Efficiency and Conservation Program Application Decision, April 16, 2009

5. 2010-2011 TGI RRA Negotiated Settlement Agreement (without financial schedules), November 26, 2009

6. 2010-2011 TGI RRA Negotiated Settlement Agreement – Letters of Comment, November 26, 2009

7. 2010 TGI, TGVI, TWI Long Term Resource Plan Decision, February 1, 2011

8. Central Heat Distribution Limited Decision, October 22, 1975 (excerpt)

9. Corix Multi-Utility Services Inc. UniverCity CPCN Decision, May 6, 2011

10. Dockside Green CPCN Decision, April 17, 2008

11. Dockside Green CPCN Reconsideration Decision, June 30, 2008

12. TES Gateway Lakeview Estates CPCN Decision, December 14, 2006

13. TGI Biomethane Application Decision, December 14, 2010

Court Cases

14. ATCO Gas & Pipelines Ltd. v. Alberta (Energy & Utilities Board), 2006 SCC 4

15. BC Hydro v. British Columbia (Utilities Commission) (1996), 20 B.C.L.R. (3d) 106 (C.A.)

BCUC Guidelines and Other Documents

16. Negotiated Settlement Process Guidelines

17. Retail Markets Downstream of the Utility Meter Guidelines

18. FEU General Terms and Conditions – 12A

19. Memorandum of Boughton Peterson Yang Anderson dated March 10, 1997

FortisBC Energy Utilities EXHIBIT BOOK

An Inquiry into FortisBC Energy Inc. regarding the Offering of Products and Services in

Alternative Energy Solutions and Other New Initiatives

Written Submission of the FortisBC Energy Utilities

EXHIBIT BOOK

Legislation

1. Clean Energy Act, S.B.C. 2010, c. 22 (excerpts)

2. Utilities Commission Act, R.S.B.C. 1996, c. 473

BCUC Decisions

3. 2008 TGI, TGVI, TWI Long Term Resource Plan Decision, December 15, 2008

4. 2008 TGI and TGVI Energy Efficiency and Conservation Program Application Decision, April 16, 2009

5. 2010-2011 TGI RRA Negotiated Settlement Agreement (without financial schedules), November 26, 2009

6. 2010-2011 TGI RRA Negotiated Settlement Agreement – Letters of Comment, November 26, 2009

7. 2010 TGI, TGVI, TWI Long Term Resource Plan Decision, February 1, 2011

8. Central Heat Distribution Limited Decision, October 22, 1975 (excerpt)

9. Corix Multi-Utility Services Inc. UniverCity CPCN Decision, May 6, 2011

10. Dockside Green CPCN Decision, April 17, 2008

11. Dockside Green CPCN Reconsideration Decision, June 30, 2008

12. TES Gateway Lakeview Estates CPCN Decision, December 14, 2006

13. TGI Biomethane Application Decision, December 14, 2010

Court Cases

14. ATCO Gas & Pipelines Ltd. v. Alberta (Energy & Utilities Board), 2006 SCC 4

15. BC Hydro v. British Columbia (Utilities Commission) (1996), 20 B.C.L.R. (3d) 106 (C.A.)

BCUC Guidelines and Other Documents

16. Negotiated Settlement Process Guidelines

17. Retail Markets Downstream of the Utility Meter Guidelines

18. FEU General Terms and Conditions – 12A

19. Memorandum of Boughton Peterson Yang Anderson dated March 10, 1997

CLEAN ENERGY ACT

[SBC 2010] CHAPTER 22

…

1 (1) In this Act:

…

"British Columbia's energy objectives" means the objectives

set out in section 2;

…

British Columbia's energy objectives

2 The following comprise British Columbia's energy objectives:

(a) to achieve electricity self-sufficiency;

(b) to take demand-side measures and to conserve energy,

including the objective of the authority reducing its

expected increase in demand for electricity by the year

2020 by at least 66%;

(c) to generate at least 93% of the electricity in British

Columbia from clean or renewable resources and to build

the infrastructure necessary to transmit that electricity;

(d) to use and foster the development in British Columbia of

innovative technologies that support energy conservation

and efficiency and the use of clean or renewable resources;

(e) to ensure the authority's ratepayers receive the benefits

of the heritage assets and to ensure the benefits of the

heritage contract under the BC Hydro Public Power Legacy

and Heritage Contract Act continue to accrue to the

authority's ratepayers;

(f) to ensure the authority's rates remain among the most

competitive of rates charged by public utilities in North

America;

- 2 -

(g) to reduce BC greenhouse gas emissions

(i) by 2012 and for each subsequent calendar year

to at least 6% less than the level of those emissions

in 2007,

(ii) by 2016 and for each subsequent calendar year

to at least 18% less than the level of those emissions

in 2007,

(iii) by 2020 and for each subsequent calendar year

to at least 33% less than the level of those emissions

in 2007,

(iv) by 2050 and for each subsequent calendar year

to at least 80% less than the level of those emissions

in 2007, and

(v) by such other amounts as determined under the

Greenhouse Gas Reduction Targets Act;

(h) to encourage the switching from one kind of energy

source or use to another that decreases greenhouse gas

emissions in British Columbia;

(i) to encourage communities to reduce greenhouse gas

emissions and use energy efficiently;

(j) to reduce waste by encouraging the use of waste heat,

biogas and biomass;

(k) to encourage economic development and the creation

and retention of jobs;

(l) to foster the development of first nation and rural

communities through the use and development of clean or

renewable resources;

(m) to maximize the value, including the incremental value

of the resources being clean or renewable resources, of

British Columbia's generation and transmission assets for

the benefit of British Columbia;

- 3 -

(n) to be a net exporter of electricity from clean or

renewable resources with the intention of benefiting all

British Columbians and reducing greenhouse gas emissions

in regions in which British Columbia trades electricity while

protecting the interests of persons who receive or may

receive service in British Columbia;

(o) to achieve British Columbia's energy objectives without

the use of nuclear power;

(p) to ensure the commission, under the Utilities

Commission Act, continues to regulate the authority with

respect to domestic rates but not with respect to

expenditures for export, except as provided by this Act.

…

Greenhouse gas reduction

18 (1) In this section, "prescribed undertaking" means a project,

program, contract or expenditure that is in a class of projects,

programs, contracts or expenditures prescribed for the purpose of

reducing greenhouse gas emissions in British Columbia.

(2) In setting rates under the Utilities Commission Act for a public

utility carrying out a prescribed undertaking, the commission must set

rates that allow the public utility to collect sufficient revenue in each

fiscal year to enable it to recover its costs incurred with respect to the

prescribed undertaking.

(3) The commission must not exercise a power under the Utilities

Commission Act in a way that would directly or indirectly prevent a

public utility referred to in subsection (2) from carrying out a

prescribed undertaking.

(4) A public utility referred to in subsection (2) must submit to the

minister, on the minister's request, a report respecting the prescribed

undertaking.

- 4 -

(5) A report to be submitted under subsection (4) must include the

information the minister specifies and be submitted in the form and by

the time the minister specifies.

UTILITIES COMMISSION ACT [RSBC 1996] CHAPTER 473

Copyright (c) Queen's Printer, Victoria, British Columbia, Canada IMPORTANT INFORMATION

Contents 1 Definitions

Part 1 — Utilities Commission

2 Commission continued

3 Commission subject to direction

4 Sittings and divisions

5 Commission's duties

6 Repealed

7 Employees

8 Technical consultants

9 Pensions

10 Secretary's duties

11 Conflict of interest

12 Obligation to keep information confidential

13 Annual report

Part 2

14–20 Repealed

Part 3 — Regulation of Public Utilities

21 Application of this Part

22 Exemptions

23 General supervision of public utilities

24 Commission must make examinations and inquiries

25 Commission may order improved service

26 Commission may set standards

27 Joint use of facilities

28 Utility must provide service if supply line near

29 Commission may order utility to provide service if supply line distant

30 Commission may order extension of existing service

31 Regulation of agreements

32 Use of municipal thoroughfares

33 Dispensing with municipal consent

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34 Order to extend service in municipality

35 Other orders to extend service

36 Use of municipal structures

37 Supervisors and inspectors

38 Public utility must provide service

39 No discrimination or delay in service

40 Exemption for part of municipality

41 No discontinuance without permission

42 Duty to obey orders

43 Duty to provide information

44 Duty to keep records

44.1 Long-term resource and conservation planning

44.2 Expenditure schedule

45 Certificate of public convenience and necessity

46 Procedure on application

47 Order to cease work

48 Cancellation or suspension of franchises and permits

49 Accounts and reports

50 Commission approval of issue of securities

51 Restraint on capitalization

52 Restraint on disposition

53 Consolidation, amalgamation and merger

54 Reviewable interests

55 Appraisal of utility property

56 Depreciation accounts and funds

57 Reserve funds

58 Commission may order amendment of schedules

58.1 Rate rebalancing

59 Discrimination in rates

60 Setting of rates

61 Rate schedules to be filed with commission

62 Schedules must be available to public

63 Schedules must be observed

64 Orders respecting contracts

Part 3.1

64.01-64.04 Repealed

Part 4 — Carriers, Purchasers and Processors

64.1 Definition

65 Common carrier

66 Common purchaser

67 Common processor

Part 5 — Electricity Transmission

68 Definitions

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69 Repealed

70 Use of electricity transmission facilities

71 Energy supply contracts

71.1 Gas marketers

Part 6 — Commission Jurisdiction

72 Jurisdiction of commission to deal with applications

73 Mandatory and restraining orders

74 Inspections and depositions

75 Commission not bound by precedent

76 Jurisdiction as to liquidators and receivers

77 Power to extend time

78 Evidence

79 Findings of fact conclusive

80 Commission not bound by judicial acts

81 Pending litigation

82 Power to inquire without application

83 Action on complaints

84 General powers not limited

85 Hearings to be held in certain cases

86 Public hearing

86.1 Repealed

86.2 When oral hearings not required

87 Recitals not required in orders

88 Application of orders

88.1 Withdrawal of application

89 Partial relief

90 Commencement of orders

91 Orders without notice

92 Directions

93-94 Repealed

95 Lien on land

96 Substitute to carry out orders

97 Entry, seizure and management

98 Defaulting utility may be dissolved

Part 7 — Decisions and Appeals

99 Reconsideration by commission

100 Requirement for hearing

101 Appeal to Court of Appeal

102 No automatic stay of proceedings while matter appealed

103 Costs of appeal

104 Case stated by commission

105 Jurisdiction of commission exclusive

Part 8 — Offences and Penalties

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Definitions

1 In this Act:

"appraisal" means appraisal by the commission;

"authority" means the British Columbia Hydro and Power Authority;

"British Columbia's energy objectives" has the same meaning as in

section 1 (1) of the Clean Energy Act;

"commission" means the British Columbia Utilities Commission

continued under this Act;

"compensation" means a rate, remuneration, gain or reward of any

kind paid, payable, promised, demanded, received or expected, directly

or indirectly, and includes a promise or undertaking by a public utility to

provide service as consideration for, or as part of, a proposal or contract

to dispose of land or any interest in it;

"costs" includes fees, counsel fees and expenses;

106 Offences

107 Restraining orders

108 Revocation of certificates

109 Remedies not mutually exclusive

Part 9 — General

110 Powers of commission in relation to other Acts

111 Substantial compliance

112 Vicarious liability

113 Public utilities may apply

114 Municipalities may apply

115 Certified documents as evidence

116 Class representation

117 Costs of commission

118 Participant costs

119 Tariff of fees

120 No waiver of rights

121 Relationship with Local Government Act

122 Repealed

123 Service of notice

124 Reasons to be given

125 Regulations

125.1 Minister's regulations

125.2 Adoption of reliability standards, rules or codes

126 Intent of Legislature

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"demand-side measure" has the same meaning as in section 1 (1) of

the Clean Energy Act;

"distribution equipment" means posts, pipes, wires, transmission

mains, distribution mains and other apparatus of a public utility used to

supply service to the utility customers;

"expenses" includes expenses of the commission;

(a) to encourage public utilities to reduce greenhouse gas

emissions;

(b) to encourage public utilities to take demand-side measures;

(c) to encourage public utilities to produce, generate and acquire

electricity from clean or renewable sources;

(d) to encourage public utilities to develop adequate energy

transmission infrastructure and capacity in the time required to

serve persons who receive or may receive service from the public

utility;

(e) to encourage public utilities to use innovative energy

technologies

(i) that facilitate electricity self-sufficiency or the fulfillment

of their long-term transmission requirements, or

(ii) that support energy conservation or efficiency or the use

of clean or renewable sources of energy;

(f) to encourage public utilities to take prescribed actions in

support of any other goals prescribed by regulation;

"petroleum industry" includes the carrying on within British Columbia

of any of the following industries or businesses:

(a) the distillation, refining or blending of petroleum;

(b) the manufacture, refining, preparation or blending of products

obtained from petroleum;

(c) the storage of petroleum or petroleum products;

(d) the wholesale or retail distribution or sale of petroleum

products;

(e) the retail distribution of liquefied or compressed natural gas;

"petroleum products" includes gasoline, naphtha, benzene, kerosene,

lubricating oils, stove oil, fuel oil, furnace oil, paraffin, aviation fuels,

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butane, propane and other liquefied petroleum gas and all derivatives of

petroleum and all products obtained from petroleum, whether or not

blended with or added to other things;

"public hearing" means a hearing of which public notice is given, which

is open to the public, and at which any person whom the commission

determines to have an interest in the matter may be heard;

"public utility" means a person, or the person's lessee, trustee,

receiver or liquidator, who owns or operates in British Columbia,

equipment or facilities for

(a) the production, generation, storage, transmission, sale,

delivery or provision of electricity, natural gas, steam or any other

agent for the production of light, heat, cold or power to or for the

public or a corporation for compensation, or

(b) the conveyance or transmission of information, messages or

communications by guided or unguided electromagnetic waves,

including systems of cable, microwave, optical fibre or

radiocommunications if that service is offered to the public for

compensation,

but does not include

(c) a municipality or regional district in respect of services provided

by the municipality or regional district within its own boundaries,

(d) a person not otherwise a public utility who provides the service

or commodity only to the person or the person's employees or

tenants, if the service or commodity is not resold to or used by

others,

(e) a person not otherwise a public utility who is engaged in the

petroleum industry or in the wellhead production of oil, natural gas

or other natural petroleum substances,

(f) a person not otherwise a public utility who is engaged in the

production of a geothermal resource, as defined in the Geothermal Resources Act, or

(g) a person, other than the authority, who enters into or is

created by, under or in furtherance of an agreement designated

under section 12 (9) of the Hydro and Power Authority Act, in

respect of anything done, owned or operated under or in relation to

that agreement;

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"rate" includes

(a) a general, individual or joint rate, fare, toll, charge, rental or

other compensation of a public utility,

(b) a rule, practice, measurement, classification or contract of a

public utility or corporation relating to a rate, and

(c) a schedule or tariff respecting a rate;

"service" includes

(a) the use and accommodation provided by a public utility,

(b) a product or commodity provided by a public utility, and

(c) the plant, equipment, apparatus, appliances, property and

facilities employed by or in connection with a public utility in

providing service or a product or commodity for the purposes in

which the public utility is engaged and for the use and

accommodation of the public;

"tenant" does not include a lessee for a term of more than 5 years;

"value" or "appraised value" means the value determined by the

commission.

Part 1 — Utilities Commission

Commission continued

2 (1) The British Columbia Utilities Commission is continued consisting of

individuals appointed as follows by the Lieutenant Governor in Council after a

merit based process:

(a) one commissioner designated as the chair;

(b) other commissioners appointed after consultation with the

chair.

(2) The Lieutenant Governor in Council, after consultation with the chair,

may designate a commissioner appointed under subsection (1) (b) as a

deputy chair.

(3) The chair may appoint a deputy chair or commissioner to act as chair for

any purpose specified in the appointment.

(4) Sections 1 to 13, 15, 18 to 21, 28 to 30, 32, 34 (3) and (4), 35 to 42,

44, 46.3, 48, 49, 54, 56, 60 (a) and (b) and 61 of the Administrative

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Tribunals Act apply to the commission, and for that purpose a reference to a

deputy chair in this Act is a reference to a vice chair under that Act.

(5) The chair is the chief executive officer of the commission and has

supervision over and direction of the work and the staff of the commission.

Commission subject to direction

3 (1) Subject to subsection (3), the Lieutenant Governor in Council, by

regulation, may issue a direction to the commission with respect to the

exercise of the powers and the performance of the duties of the commission,

including, without limitation, a direction requiring the commission to exercise

a power or perform a duty, or to refrain from doing either, as specified in the

regulation.

(2) The commission must comply with a direction issued under subsection

(1), despite

(a) any other provision of

(i) this Act, except subsection (3) of this section, or

(ii) the regulations,

(a.1) any provision of the Clean Energy Act or the regulations

under that Act, or

(b) any previous decision of the commission.

(3) The Lieutenant Governor in Council may not under subsection (1)

specifically and expressly

(a) declare an order or decision of the commission to be of no force

or effect, or

(b) require the commission to rescind an order or a decision.

Sittings and divisions

4 (1) The commission

(a) must sit at the times and conduct its proceedings in a manner it

considers convenient for the proper discharge and speedy dispatch

of its duties under this Act

(b) [Repealed 2004-45-164.]

(2) The chair may organize the commission into divisions.

(3) The commissioners must sit

(a) as the commission, or

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(b) as a division of the commission.

(4) If commissioners sit as a division

(a) 2 or more divisions may sit at the same time,

(b) the division has all the jurisdiction of and may exercise and

perform the powers and duties of the commission, and

(c) a decision or action of the division is a decision or action of the

commission.

(5) At a sitting of the commission or of a division of the commission, one

commissioner is a quorum.

(6) The chair may designate a commissioner to serve as chair at any sitting

of the commission or a division of it.

(7) If a proceeding is being held by the commission or by a division and a

sitting commissioner is absent or unable to attend,

(a) that commissioner is thereafter disqualified from continuing to

sit on the proceeding, and

(b) despite subsection (5), the commissioner or commissioners

remaining present and sitting must exercise and perform all the

jurisdiction, powers and duties of the commission.

(8) and (9) [Repealed 2003-46-2.]

(10) In the case of a tie vote at a sitting of the commission or a division of

the commission, the decision of the chair of the commission or the division

governs.

(11) If a division is comprised of one member and that member is unable for

any reason to complete the member's duties, the chair of the commission,

with the consent of all parties to the application, may organize a new division

to continue to hear and determine the matter on terms agreed to by the

parties, and the vacancy does not invalidate the proceeding.

Commission's duties

5 (0.1) [Repealed by 2010-22-61.]

(1) On the request of the Lieutenant Governor in Council, it is the duty of the

commission to advise the Lieutenant Governor in Council on any matter,

whether or not it is a matter in respect of which the commission otherwise

has jurisdiction.

(2) If, under subsection (1), the Lieutenant Governor in Council refers a

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matter to the commission, the Lieutenant Governor in Council may specify

terms of reference requiring and empowering the commission to inquire into

the matter.

(3) The commission may carry out a function or perform a duty delegated to

it under an enactment of British Columbia or Canada.

(4)-(9) [Repealed 2010-22-61.]

Repealed

6 [Repealed 2004-45-165.]

Employees

7 Despite the Public Service Act, the commission may employ a secretary and

other officers and other employees it considers necessary and may

determine their duties, conditions of employment and remuneration.

Technical consultants

8 The commission may appoint or engage persons having special or technical

knowledge necessary to assist the commission in carrying out its functions.

Pensions

9 The Lieutenant Governor in Council may, by order, direct that the Public

Service Pension Plan, continued under the Public Sector Pension Plans Act, applies to commissioners, officers and other employees of the commission,

but the commission may, alone or in cooperation with other corporations,

departments, commissions or other agencies of the Crown, establish,

support or participate in any one or more of

(a) a pension or superannuation plan, or

(b) a group insurance plan

for the benefit of commissioners, officers and other employees of the

commission and their dependants.

Secretary's duties

10 (1) The secretary must

(a) keep a record of the proceedings before the commission,

(b) ensure that every rule, regulation and order of the commission

is filed in the records of the commission,

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(c) have custody of all rules, regulations and orders made by the

commission and all other records and documents of, or filed with,

the commission, and

(d) carry out the instructions and directions of the commission

under this Act respecting the secretary's duties or office.

(2) On the application of a person who pays a prescribed fee, the secretary

must deliver to the person a certified copy of any rule, regulation or order of

the commission.

(3) In the absence of the secretary, the duties of the secretary under this

Act may be performed by another person appointed by the commission.

(4) A rule, regulation and order of the commission must be signed by the

chair, a deputy chair or an acting chair, and the original or a copy of it must

be delivered to the secretary for filing.

Conflict of interest

11 (1) A commissioner or employee of the commission must not, directly or

indirectly,

(a) hold, acquire or have a beneficial interest in a share, stock,

bond, debenture or other security of a corporation or other person

subject to regulation under Part 3 of this Act,

(b) have a significant beneficial interest in a device, appliance,

machine, article, patent or patented process, or a part of it, that is

required or used by a corporation or other person referred to in

paragraph (a) for the purpose of its equipment or service, or

(c) have a significant beneficial interest in a contract for the

construction of works or the provision of a service for or by a

corporation or other person referred to in paragraph (a).

(2) A commissioner or employee of the commission, in whom a beneficial

interest referred to in subsection (1) is or becomes vested, must divest

himself or herself of the beneficial interest within 3 months after

appointment to the commission or acquisition of the property, as the case

may be.

(3) The use or purchase for personal or domestic purposes, of gas, heat,

light, power, electricity or petroleum products or service from a corporation

or other person subject to regulation under this Act is not a contravention of

this section, and does not disqualify a commissioner or employee from acting

in any matter affecting that corporation or other person.

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Obligation to keep information confidential

12 (1) Every commissioner and every officer and employee of the commission

must keep secret all information coming to the person's knowledge during

the course of the administration of this Act, except insofar as disclosure is

necessary for the administration of this Act or insofar as the commission

authorizes the person to release the information.

(2) A commissioner, officer or employee of the commission must not be

required to testify or produce evidence in any proceeding, other than a

criminal proceeding, about records or information obtained in the discharge

of duties under this Act.

(3) Despite subsection (2), the Supreme Court may require the commission

to produce the record of a proceeding that is the subject of an application for

judicial review under the Judicial Review Procedure Act.

Annual report

13 (1) In each year, the commission must make a report to the Lieutenant

Governor in Council for the preceding fiscal year, setting out briefly

(a) all applications and complaints to the commission under this

Act and summaries of the commission's findings on them,

(b) other matters that the commission considers to be of public

interest in connection with the discharge of its duties under this

Act, and

(c) other information the Lieutenant Governor in Council directs.

(2) The report must be laid before the Legislative Assembly as soon as

possible after it is submitted to the Lieutenant Governor in Council.

Part 2

Repealed

14–20 [Repealed 2003-46-5.]

Part 3 — Regulation of Public Utilities

Application of this Part

21 (1) This Part applies only to a public utility that is subject to the legislative

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authority of the Province.

(2) The provision by a public utility of a class of service in respect of which

the public utility is not subject to the legislative authority of the Province

does not make this Part inapplicable to that public utility in respect of any

other class of service.

Exemptions

22 (1) In this section:

"eligible person" means a person, or a class of persons, that

(a) generates, produces, transmits, distributes or sells electricity,

(b) for the purpose of heating or cooling any building, structure or

equipment or for any industrial purpose, heats, cools or

refrigerates water, air or any heating medium or coolant, using for

that purpose equipment powered by a fuel, a geothermal resource

or solar energy, or

(c) enters into an energy supply contract, within the meaning of

section 68, for the provision of electricity;

"minister" means the minister responsible for the administration of the

Hydro and Power Authority Act.

(2) The minister, by regulation, may

(a) exempt from any or all of section 71 and the provisions of this

Part

(i) an eligible person, or

(ii) an eligible person in respect of any equipment, facility,

plant, project, activity, contract, service or system of the

eligible person, and

(b) in respect of an exemption made under paragraph (a), impose

any terms and conditions the minister considers to be in the public

interest.

(3) The minister, before making a regulation under subsection (2), may refer

the matter to the commission for a review.

General supervision of public utilities

23 (1) The commission has general supervision of all public utilities and may

make orders about

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(a) equipment,

(b) appliances,

(c) safety devices,

(d) extension of works or systems,

(e) filing of rate schedules,

(f) reporting, and

(g) other matters it considers necessary or advisable for

(i) the safety, convenience or service of the public, or

(ii) the proper carrying out of this Act or of a contract,

charter or franchise involving use of public property or rights.

(2) Subject to this Act, the commission may make regulations requiring a

public utility to conduct its operations in a way that does not unnecessarily

interfere with, or cause unnecessary damage or inconvenience to, the public.

Commission must make examinations and inquiries

24 In its supervision of public utilities, the commission must make examinations

and conduct inquiries necessary to keep itself informed about

(a) the conduct of public utility business,

(b) compliance by public utilities with this Act, regulations or any

other law, and

(c) any other matter in the commission's jurisdiction.

Commission may order improved service

25 If the commission, after a hearing held on its own motion or on complaint,

finds that the service of a public utility is unreasonable, unsafe, inadequate

or unreasonably discriminatory, the commission must

(a) determine what is reasonable, safe, adequate and fair service,

and

(b) order the utility to provide it.

Commission may set standards

26 After a hearing held on the commission's own motion or on complaint, the

commission may do one or more of the following:

(a) determine and set just and reasonable standards,

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classifications, rules, practices or service to be used by a public

utility;

(b) determine and set adequate and reasonable standards for

measuring quantity, quality, pressure, initial voltage or other

conditions of supplying service;

(c) prescribe reasonable regulations for examining, testing or

measuring a service;

(d) establish or approve reasonable standards for accuracy of

meters and other measurement appliances;

(e) provide for the examination and testing of appliances used to

measure a service of a utility.

Joint use of facilities

27 (1) If the commission, after a hearing, finds that

(a) public convenience and necessity require the use by a public

utility of conduits, subways, poles, wires or other equipment

belonging to another public utility, and

(b) the use will not prevent the owner or other users from

performing their duties or result in any substantial detriment to

their service,

the commission may, if the utilities fail to agree on the use, conditions or

compensation, make an order it considers reasonable, directing that the use

or joint use of the conduits, subways, poles, wires or other equipment be

allowed and prescribing conditions of and compensation for the use.

(2) If the commission, after a hearing, finds that the provision of adequate

service by one public utility or the safety of the persons operating or using

that service requires that wires or cables carrying electricity and run, placed,

erected, maintained or used by another public utility be placed, constructed

or equipped with safety devices, the commission may make an order it

considers reasonable about the placing, construction or equipment.

(3) By the same or a later order, the commission may

(a) direct that the cost of the placing, construction or equipment be

at the expense of the public utility whose wire, cable or apparatus

was most recently placed, or

(b) in the discretion of the commission, apportion the cost between

the utilities.

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Utility must provide service if supply line near

28 (1) On being requested by the owner or occupier of the premises to do so, a

public utility must supply its service to premises that are located within 200

metres of its supply line or any lesser distance that the commission

prescribes suitable for that purpose.

(2) Before supplying the service under subsection (1) or making a

connection for the purpose, or as a condition of continuing to supply the

service, the public utility may require the owner or occupier to give

reasonable security for repayment of the costs of making the connection as

set out in the filed schedule of rates.

(2.1) If required to do so by regulation, the commission, in accordance with

the prescribed requirements, must set a rate for the authority respecting the

service provided under subsection (1).

(2.2) A requirement prescribed for the purposes of subsection (2.1) applies

despite

(a) any other provision of this Act or any regulation under this Act,

except for a regulation under section 3, or

(b) any previous decision of the commission.

(3) After a hearing and for proper cause, the commission may relieve a

public utility from the obligation to supply service under this Act on terms

the commission considers proper and in the public interest.

Commission may order utility to provide service if supply line distant

29 On the application of a person whose premises are located more than

200 metres from a supply line suitable for that purpose, the commission may

order a public utility that controls or operates the line

(a) to supply, within the time the commission directs, the service

required by that person, and

(b) to make extensions and install necessary equipment and

apparatus on terms the commission directs, which terms may

include payment of all or part of the cost by the applicant.

Commission may order extension of existing service

30 If the commission, after a hearing, determines that

(a) an extension of the existing services of a public utility, in a

general area that the public utility may properly be considered

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responsible for developing, is feasible and required in the public

interest, and

(b) the construction and maintenance of the extension will not

necessitate a substantial increase in rates chargeable, or a

decrease in services provided, by the utility elsewhere,

the commission may order the utility to make the extension on terms the

commission directs, which may include payment of all or part of the cost by

the persons affected.

Regulation of agreements

31 The commission may make rules governing conditions to be contained in

agreements entered into by public utilities for their regulated services or for

a class of regulated service.

Use of municipal thoroughfares

32 (1) This section applies if a public utility

(a) has the right to enter a municipality to place its distribution

equipment on, along, across, over or under a public street, lane,

square, park, public place, bridge, viaduct, subway or watercourse,

and

(b) cannot come to an agreement with the municipality on the use

of the street or other place or on the terms of the use.

(2) On application and after any inquiry it considers advisable, the

commission may, by order, allow the use of the street or other place by the

public utility for that purpose and specify the manner and terms of use.

Dispensing with municipal consent

33 (1) This section applies if a public utility

(a) cannot agree with a municipality respecting placing its

distribution equipment on, along, across, over or under a public

street, lane, square, park, public place, bridge, viaduct, subway or

watercourse in a municipality, and

(b) the public utility is otherwise unable, without expenditures that

the commission considers unreasonable, to extend its system, line

or apparatus from a place where it lawfully does business to

another place where it is authorized to do business.

(2) On application and after a hearing, for the purpose of that extension only

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and without unduly preventing the use of the street or other place by other

persons, the commission may, by order,

(a) allow the use of the street or other place by the public utility,

despite any law or contract granting to another person exclusive

rights, and

(b) specify the manner and terms of the use.

Order to extend service in municipality

34 (1) On the complaint of a municipality that a public utility doing business in

the municipality fails to extend its service to a part of the municipality, and

after any hearing the commission considers advisable, the commission may

order the public utility to extend its service in a way that the commission

considers reasonable and proper.

(2) An order under subsection (1) may

(a) in the commission's discretion, impose terms for the extension,

including the expenditure to be incurred for all necessary works,

and

(b) apportion the cost between the public utility, the municipality

and consumers receiving service from the extension.

Other orders to extend service

35 If the commission, after a hearing, concludes that in its opinion an extension

by a public utility of its existing service would provide sufficient business to

justify the construction and maintenance of the extension, and the financial

condition of the public utility reasonably warrants the capital expenditure

required, the commission may order the utility to extend its service to the

extent the commission considers reasonable and proper.

Use of municipal structures

36 Subject to any agreement between a public utility and a municipality and to

the franchise or rights of the public utility, and after any hearing the

commission considers advisable, the commission may, by order, specify the

terms on which the public utility may use for any purpose of its service

(a) a highway in the municipality, or

(b) a public bridge, viaduct or subway constructed or to be

constructed by the municipality alone or jointly with another

municipality, corporation or government.

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Supervisors and inspectors

37 (1) If the commission considers that a supervisor or inspector should be

appointed to supervise or inspect, continuously or otherwise, the system,

works, plant, equipment or service of a public utility with a view to

establishing and carrying out measures for

(a) the safety of the public and of the users of the utility's service,

or

(b) adequacy of service,

the commission may appoint a supervisor or inspector for that utility and

may specify the person's duties.

(2) The commission may

(a) set the salary and expenses of a supervisor or inspector

appointed under subsection (1), and

(b) order the amount set

(i) to be borne by the municipality in which the operations of

the public utility are carried on or its service is provided, or

(ii) to be borne or apportioned in a way the commission

considers equitable.

Public utility must provide service

38 A public utility must

(a) provide, and

(b) maintain its property and equipment in a condition to enable it

to provide,

a service to the public that the commission considers is in all respects

adequate, safe, efficient, just and reasonable.

No discrimination or delay in service

39 On reasonable notice, a public utility must provide suitable service without

undue discrimination or undue delay to all persons who

(a) apply for service,

(b) are reasonably entitled to it, and

(c) pay or agree to pay the rates established for that service under

this Act.

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Exemption for part of municipality

40 (1) On application, the commission may, by order, exempt a municipality

from section 39 except in a defined area.

(2) On application by any person and after notice to the municipality, the

commission may enlarge or reduce an area defined under subsection (1).

No discontinuance without permission

41 A public utility that has been granted a certificate of public convenience and

necessity or a franchise, or that has been deemed to have been granted a

certificate of public convenience and necessity, and has begun any operation

for which the certificate or franchise is necessary, or in respect of which the

certificate is deemed to have been granted, must not cease the operation or

a part of it without first obtaining the permission of the commission.

Duty to obey orders

42 A public utility must obey the lawful orders of the commission made under

this Act for its business or service, and must do all things necessary to

secure observance of those orders by its officers, agents and employees.

Duty to provide information

43 (1) A public utility must, for the purposes of this Act,

(a) answer specifically all questions of the commission, and

(b) provide to the commission

(i) the information the commission requires, and

(ii) a report, submitted annually and in the manner the

commission requires, regarding the demand-side measures

taken by the public utility during the period addressed by the

report, and the effectiveness of those measures.

(1.1) [Repealed 2010-22-64.]

(2) A public utility that receives from the commission any form of return

must fully and correctly answer each question in the return and deliver it to

the commission.

(3) On request by the commission, a public utility must deliver to the

commission

(a) all profiles, contracts, reports of engineers, accounts and

records in its possession or control relating in any way to its

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property or service or affecting its business, or verified copies of

them, and

(b) complete inventories of the utility's property in the form the

commission directs.

(4) On request by the commission, a public utility must file with the

commission a statement in writing setting out the name, title of office, post

office address and the authority, powers and duties of

(a) every member of the board of directors and the executive

committee,

(b) every trustee, superintendent, chief or head of construction or

operation, or of any department, branch, division or line of

construction or operation, and

(c) other officers of the utility.

(5) The statement required under subsection (4) must be filed in a form that

discloses the source and origin of each administrative act, rule, decision,

order or other action of the utility.

Duty to keep records

44 (1) A public utility must have in British Columbia an office in which it must

keep all accounts and records required by the commission to be kept in

British Columbia.

(2) A public utility must not remove or permit to be removed from British

Columbia an account or record required to be kept under subsection (1),

except on conditions specified by the commission.

Long-term resource and conservation planning

44.1 (1) [Repealed 2010-22-65.]

(2) Subject to subsection (4), a public utility must file with the commission,

in the form and at the times the commission requires, a long-term resource

plan including all of the following:

(a) an estimate of the demand for energy the public utility would

expect to serve if the public utility does not take new demand-side

measures during the period addressed by the plan;

(b) a plan of how the public utility intends to reduce the demand

referred to in paragraph (a) by taking cost-effective demand-side

measures;

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(c) an estimate of the demand for energy that the public utility

expects to serve after it has taken cost-effective demand-side

measures;

(d) a description of the facilities that the public utility intends to

construct or extend in order to serve the estimated demand

referred to in paragraph (c);

(e) information regarding the energy purchases from other persons

that the public utility intends to make in order to serve the

estimated demand referred to in paragraph (c);

(f) an explanation of why the demand for energy to be served by

the facilities referred to in paragraph (d) and the purchases

referred to in paragraph (e) are not planned to be replaced by

demand-side measures;

(g) any other information required by the commission.

(3) The commission may exempt a public utility from the requirement to

include in a long-term resource plan filed under subsection (2) any of the

information referred to in paragraphs (a) to (f) of that subsection if the

commission is satisfied that the information is not applicable with respect to

the nature of the service provided by the public utility

(4) [Repealed 2010-22-65.]

(5) The commission may establish a process to review long-term resource

plans filed under subsection (2).

(6) After reviewing a long-term resource plan filed under subsection (2), the

commission must

(a) accept the plan, if the commission determines that carrying out

the plan would be in the public interest, or

(b) reject the plan.

(7) The commission may accept or reject, under subsection (6), a part of a

public utility's plan, and, if the commission rejects a part of a plan,

(a) the public utility may resubmit the part within a time specified

by the commission, and

(b) the commission may accept or reject, under subsection (6), the

part resubmitted under paragraph (a) of this subsection.

(8) In determining under subsection (6) whether to accept a long-term

resource plan, the commission must consider

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(a) the applicable of British Columbia's energy objectives,

(b) the extent to which the plan is consistent with the applicable

requirements under sections 6 and 19 of the Clean Energy Act,

(c) whether the plan shows that the public utility intends to pursue

adequate, cost-effective demand-side measures, and

(d) the interests of persons in British Columbia who receive or may

receive service from the public utility.

(9) In accepting under subsection (6) a long-term resource plan, or part of a

plan, the commission may do one or both of the following:

(a) order that a proposed utility plant or system, or extension of

either, referred to in the accepted plan or the part is exempt from

the operation of section 45 (1);

(b) order that, despite section 75, a matter the commission

considers to be adequately addressed in the accepted plan or the

part is to be considered as conclusively determined for the

purposes of any hearing or proceeding to be conducted by the

commission under this Act, other than a hearing or proceeding for

the purposes of section 99.

Expenditure schedule

44.2 (1) A public utility may file with the commission an expenditure schedule

containing one or more of the following:

(a) a statement of the expenditures on demand-side measures the

public utility has made or anticipates making during the period

addressed by the schedule;

(b) a statement of capital expenditures the public utility has made

or anticipates making during the period addressed by the schedule;

(c) a statement of expenditures the public utility has made or

anticipates making during the period addressed by the schedule to

acquire energy from other persons.

(2) The commission may not consent under section 61 (2) to an amendment

to or a rescission of a schedule filed under section 61 (1) to the extent that

the amendment or the rescission is for the purpose of recovering

expenditures referred to in subsection (1) (a) of this section, unless

(a) the expenditure is the subject of a schedule filed and accepted

under this section, or

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(b) the amendment or rescission is for the purpose of setting an

interim rate.

(3) After reviewing an expenditure schedule submitted under subsection (1),

the commission, subject to subsections (5), (5.1) and (6), must

(a) accept the schedule, if the commission considers that making

the expenditures referred to in the schedule would be in the public

interest, or

(b) reject the schedule.

(4) The commission may accept or reject, under subsection (3), a part of a

schedule.

(5) In considering whether to accept an expenditure schedule filed by a

public utility other than the authority, the commission must consider

(a) the applicable of British Columbia's energy objectives,

(b) the most recent long-term resource plan filed by the public

utility under section 44.1, if any,

(c) the extent to which the schedule is consistent with the

applicable requirements under sections 6 and 19 of the Clean Energy Act,

(d) if the schedule includes expenditures on demand-side

measures, whether the demand-side measures are cost-effective

within the meaning prescribed by regulation, if any, and

(e) the interests of persons in British Columbia who receive or may

receive service from the public utility.

(5.1) In considering whether to accept an expenditure schedule filed by the

authority, the commission, in addition to considering the interests of persons

in British Columbia who receive or may receive service from the authority,

must consider and be guided by

(a) British Columbia's energy objectives,

(b) an applicable integrated resource plan approved under section

4 of the Clean Energy Act,

(c) the extent to which the schedule is consistent with the

requirements under section 19 of the Clean Energy Act, and

(d) if the schedule includes expenditures on demand-side

measures, the extent to which the demand-side measures are cost-

effective within the meaning prescribed by regulation, if any.

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(6) If the commission considers that an expenditure in an expenditure

schedule was determined to be in the public interest in the course of

determining that a long-term resource plan was in the public interest under

section 44.1 (6),

(a) subsection (5) of this section does not apply with respect to

that expenditure, and

(b) the commission must accept under subsection (3) the

expenditure in the expenditure schedule.

Certificate of public convenience and necessity

45 (1) Except as otherwise provided, after September 11, 1980, a person must

not begin the construction or operation of a public utility plant or system, or

an extension of either, without first obtaining from the commission a

certificate that public convenience and necessity require or will require the

construction or operation.

(2) For the purposes of subsection (1), a public utility that is operating a

public utility plant or system on September 11, 1980 is deemed to have

received a certificate of public convenience and necessity, authorizing it

(a) to operate the plant or system, and

(b) subject to subsection (5), to construct and operate extensions

to the plant or system.

(3) Nothing in subsection (2) authorizes the construction or operation of an

extension that is a reviewable project under the Environmental Assessment Act.

(4) The commission may, by regulation, exclude utility plant or categories of

utility plant from the operation of subsection (1).

(5) If it appears to the commission that a public utility should, before

constructing or operating an extension to a utility plant or system, apply for

a separate certificate of public convenience and necessity, the commission

may, not later than 30 days after construction of the extension is begun,

order that subsection (2) does not apply in respect of the construction or

operation of the extension.

(6) A public utility must file with the commission at least once each year a

statement in a form prescribed by the commission of the extensions to its

facilities that it plans to construct.

(6.1) and (6.2) [Repealed 2008-13-8.]

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(7) Except as otherwise provided, a privilege, concession or franchise

granted to a public utility by a municipality or other public authority after

September 11, 1980 is not valid unless approved by the commission.

(8) The commission must not give its approval unless it determines that the

privilege, concession or franchise proposed is necessary for the public

convenience and properly conserves the public interest.

(9) In giving its approval, the commission

(a) must grant a certificate of public convenience and necessity,

and

(b) may impose conditions about

(i) the duration and termination of the privilege, concession

or franchise, or

(ii) construction, equipment, maintenance, rates or service,

as the public convenience and interest reasonably require.

Procedure on application

46 (1) An applicant for a certificate of public convenience and necessity must file

with the commission information, material, evidence and documents that the

commission prescribes.

(2) The commission has a discretion whether or not to hold any hearing on

the application.

(3) Subject to subsections (3.1) to (3.3), the commission may issue or

refuse to issue the certificate, or may issue a certificate of public

convenience and necessity for the construction or operation of a part only of

the proposed facility, line, plant, system or extension, or for the partial

exercise only of a right or privilege, and may attach to the exercise of the

right or privilege granted by the certificate, terms, including conditions about

the duration of the right or privilege under this Act as, in its judgment, the

public convenience or necessity may require.

(3.1) In deciding whether to issue a certificate under subsection (3) applied

for by a public utility other than the authority, the commission must consider

(a) the applicable of British Columbia's energy objectives,

(b) the most recent long-term resource plan filed by the public

utility under section 44.1, if any, and

(c) the extent to which the application for the certificate is

consistent with the applicable requirements under sections 6 and

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19 of the Clean Energy Act,

(3.2) Section (3.1) does not apply if the commission considers that the

matters addressed in the application for the certificate were determined to

be in the public interest in the course of considering a long-term resource

plan under section 44.1.

(3.3) In deciding whether to issue a certificate under subsection (3) to the

authority, the commission, in addition to considering the interests of persons

in British Columbia who receive or may receive service from the authority,

must consider and be guided by

(a) British Columbia's energy objectives,

(b) an applicable integrated resource plan approved under section

4 of the Clean Energy Act, and

(c) the extent to which the application for the certificate is

consistent with the requirements under section 19 of the Clean Energy Act.

(4) If a public utility desires to exercise a right or privilege under a consent,

franchise, licence, permit, vote or other authority that it proposes to obtain

but that has not, at the date of the application, been granted to it, the public

utility may apply to the commission for an order preliminary to the issue of

the certificate.

(5) On application under subsection (4), the commission may make an order

declaring that it will, on application, under rules it specifies, issue the desired

certificate, on the terms it designates in the order, after the public utility has

obtained the proposed consent, franchise, licence, permit, vote or other

authority.

(6) On evidence satisfactory to the commission that the consent, franchise,

licence, permit, vote or other authority has been secured, the commission

must issue a certificate under section 45.

(7) The commission may amend a certificate previously issued, or issue a

new certificate, for the purpose of renewing, extending or consolidating a

certificate previously issued.

(8) A public utility to which a certificate is, or has been, issued, or to which

an exemption is, or has been, granted under section 45 (4), is authorized,

subject to this Act, to construct, maintain and operate the plant, system or

extension authorized in the certificate or exemption.

Order to cease work

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47 (1) If a public utility

(a) is engaged, or is about to engage, in the construction or

operation of a plant or system, and

(b) has not secured or has not been exempted from the

requirement for, or is not deemed to have received a certificate of

public convenience and necessity required under this Act,

any interested person may file a complaint with the commission.

(2) The commission may, with or without notice, make an order requiring

the public utility complained of to cease the construction or operation until

the commission makes and files its decision on the complaint, or until further

order of the commission.

(3) The commission may, after a hearing, make the order and specify the

terms under this Act that it considers advisable.

(4) If the commission considers it necessary to determine whether a person

is engaged or is about to engage in construction or operation of any plant or

system, the commission may request that person to provide information

required by it and to answer specifically all questions of the commission, and

the person must comply.

Cancellation or suspension of franchises and permits

48 (1) If the commission, after a hearing, determines that a public utility

holding a franchise, licence or permit has failed to exercise or has not

continued to exercise or use the right and privilege granted by the franchise,

licence or permit, the commission may

(a) cancel the franchise, licence or permit, or

(b) suspend for a time the commission considers advisable the

rights, or any of them, under the franchise, licence or permit.

(2) If a franchise, licence or permit is cancelled, the utility must cease to

operate.

(3) If a right under a franchise, licence or permit is suspended, the utility

must cease to exercise the suspended right during the period of suspension.

Accounts and reports

49 The commission may, by order, require every public utility to do one or more

of the following:

(a) keep the records and accounts of the conduct of the utility's

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business that the commission may specify, and for public utilities of

the same class, adopt a uniform system of accounting specified by

the commission;

(b) provide, at the times and in the form and manner the

commission specifies, a detailed report of finances and operations,

verified as specified;

(c) file with the commission, at the times and in the form and

manner the commission specifies, a report of every accident

occurring to or on the plant, equipment or other property of the

utility, if the accident is of such nature as to endanger the safety,

health or property of any person;

(d) obtain from a board, tribunal, municipal or other body or official

having jurisdiction or authority, permission, if necessary, to

undertake or carry on a work or service ordered by the commission

to be undertaken or carried on that is contingent on the

permission.

Commission approval of issue of securities

50 (1) In this section, "security" means any share of any class of shares of a

public utility or any bond, debenture, note or other obligation of a public

utility whether secured or unsecured.

(2) Except in the case of a security evidencing indebtedness payable less

than one year from its date, a public utility must not issue a security without

first obtaining approval of the commission under this section and, if

section 54 applies, under that section.

(3) Without first obtaining the commission's approval, a public utility must

not,

(a) in respect of a security that it has issued,

(i) increase a fixed dividend or fixed interest rate,

(ii) alter a maturity date for the issue,

(ii) restrict the utility's right to redeem the issue,

(iv) increase the premium to be paid on redemption, or

(v) make a material alteration in the characteristics of the

security, or

(b) purchase, redeem or otherwise acquire shares of any class of

the utility except in accordance with any special rights or

restrictions attached to them.

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(4) Subsections (2) and (3) do not apply to the issue of shares under a

genuine employee share purchase plan or genuine employee share option

plan that has been filed with the commission.

(5) Without first obtaining the commission's approval, a public utility must

not guarantee the payment of all or part of a loan or all or part of the

interest on a loan made to another person.

(6) A public utility is not liable under a guarantee given by it after

June 29, 1988, in contravention of subsection (5) or of a condition of

approval imposed under subsection (7).

(7) The commission may give its approval under this section subject to

conditions and requirements considered necessary or desirable in the public

interest.

(8) A municipality is not a utility for the purpose of this section.

Restraint on capitalization

51 A public utility must not do any of the following:

(a) capitalize a franchise or right to be a corporation;

(b) capitalize a franchise, licence, permit or concession in excess of

the amount that, exclusive of tax or annual charge, is paid to the

government, a municipality or other public authority as

consideration for the franchise, licence, permit or concession;

(c) issue a security or evidence of indebtedness against a contract

for consolidation, amalgamation, merger or lease.

Restraint on disposition

52 (1) Except for a disposition of its property in the ordinary course of business,

a public utility must not, without first obtaining the commission's approval,

(a) dispose of or encumber the whole or a part of its property,

franchises, licences, permits, concessions, privileges or rights, or

(b) by any means, direct or indirect, merge, amalgamate or

consolidate in whole or in part its property, franchises, licences,

permits, concessions, privileges or rights with those of another

person.

(2) The commission may give its approval under this section subject to

conditions and requirements considered necessary or desirable in the public

interest.

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Consolidation, amalgamation and merger

53 (1) A public utility must not consolidate, amalgamate or merge with another

person

(a) unless the Lieutenant Governor in Council

(i) has first received from the commission a report under

this section including an opinion that the consolidation,

amalgamation or merger would be beneficial in the public

interest, and

(ii) has, by order, consented to the consolidation,

amalgamation or merger, and

(b) except in accordance with an order made under paragraph (a).

(2) The Lieutenant Governor in Council may, in an order under

subsection (1) (a), include conditions and requirements that the Lieutenant

Governor in Council considers necessary or advisable.

(3) An application for consent of the Lieutenant Governor in Council under

subsection (1) must be made to the commission by the public utility.

(4) The commission must inquire into the application and may for that

purpose hold a hearing.

(5) On conclusion of its inquiry, the commission must,

(a) if it is of the opinion that the consolidation, amalgamation or

merger would be beneficial in the public interest, submit its report

and findings to the Lieutenant Governor in Council, or

(b) dismiss the application.

(6) If a public utility gives notice to its shareholders of a meeting of

shareholders in connection with a consolidation, amalgamation or merger, it

must

(a) set out in the notice the provisions of this section, and

(b) file a copy of the notice with the commission at the time of

mailing to the shareholders.

Reviewable interests

54 (1) In this section:

"child" includes a child in respect of whom a person referred to in the

definition of "spouse" stands in the place of a parent;

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"offeree" means a person to whom a take over bid is made;

"offeror" means a person, other than an agent, who makes a take over

bid and includes 2 or more persons

(a) whose bids are made jointly or in concert, or

(b) who intend to exercise jointly or in concert any voting rights

attaching to the shares for which a take over bid is made;

"spouse" means a person who

(a) is married to another person, or

(b) is living and cohabiting with another person in a marriage-like

relationship, including a marriage-like relationship between persons

of the same gender, and has lived and cohabited in that

relationship for a period of at least 2 years;

"take over bid" has the same meaning as in section 92 of the Securities Act;

"voting share" means a share that has, or may under any special rights

or restrictions attached to the share have, the right to vote for the

election of directors, and for this purpose "share" includes

(a) a security convertible into such a share, and

(b) options and rights to acquire such a share or such a convertible

security.

(2) For the purposes of this section, persons are associates if any of the

following apply:

(a) one of the persons is a corporation

(i) of which more than 10% of the shares outstanding of any

class of the corporation are beneficially owned or controlled,

directly or indirectly, by the other person, or

(ii) of which the other is a director or officer;

(b) each of the persons is a corporation and

(i) more than 10% of the shares outstanding of any class of

shares of one are beneficially owned or controlled, directly or

indirectly, by the other, or

(ii) more than 10% of the shares outstanding of any class of

shares of each are beneficially owned or controlled, directly

or indirectly, by the same person;

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(c) they are partners or one is a partnership of which the other is a

partner;

(d) one is a trust in which the other has a substantial beneficial

interest or for which the other serves as trustee or in a similar

capacity;

(e) they are obligated to act in concert in exercising a voting right

in respect of shares of the utility;

(f) one is the spouse or child of the other;

(g) one is a relative of the other or of the other's spouse and has

the same home as the other.

(3) For the purpose of subsection (2), if a person has more than one

associate, those associates are associates of each other.

(4) For the purpose of this section, a person has a reviewable interest in a

public utility if

(a) the person owns or controls, or

(b) the person and the person's associates own or control,

in the aggregate more than 20% of the voting shares outstanding of any

class of shares of the utility.

(5) A public utility must not, without the approval of the commission,

(a) issue, sell, purchase or register on its books a transfer of

shares in the capital of the utility or create, or

(b) attach to any shares, whether issued or unissued, any special

rights or restrictions,

if the issue, sale, purchase or registration or the creation or attachment of

the special rights or restrictions would

(c) cause any person to have a reviewable interest,

(d) increase the percentage of voting shares owned by a person

who has a reviewable interest,

(e) be a registration of a transfer of shares, the acquisition of

which was contrary to subsection (7) or (8), or

(f) increase the voting rights attached to any shares owned by a

person who has a reviewable interest.

(6) Failure of a public utility to comply with subsection (5) does not give rise

to an offence if the public utility acts in the genuine belief based on an

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enquiry made with reasonable care, that the issue, sale, purchase or

registration, or the creation or attachment of the special rights or

restrictions, would not have the effects referred to in subsection (5) (c)

to (f).

(7) A person must not acquire or acquire control of such numbers of any

class of shares of a public utility as

(a) in themselves, or

(b) together with shares already owned or controlled by the person

and the person's associates,

cause the person to have a reviewable interest in a public utility unless the

person has obtained the commission's approval.

(8) Except if the acquisition or acquisition of control does not increase the

percentage of voting shares held, owned or controlled by the person or by

the person and the person's associates, a person having a reviewable

interest in a public utility and any associate of that person must not acquire

or acquire control of any voting shares in the public utility unless the person

or associate has obtained the commission's approval.

(9) The commission may give its approval under this section subject to

conditions and requirements it considers necessary or desirable in the public

interest, but the commission must not give its approval under this section

unless it considers that the public utility and the users of the service of the

public utility will not be detrimentally affected.

(10) If the commission determines that there has been a contravention of

subsection (5), (7) or (8), the commission may, on notice to the public utility

and after a hearing, make an order imposing on the public utility conditions

and requirements respecting the management and operation of the utility.

(11) A proceeding must not be brought against the commission or the

government by reason of the exercise by the commission of its powers under

subsection (9) or (10).

(12) An offeror who makes a take over bid for shares of a public utility must

(a) file with the commission a copy of the take over bid and all

supporting or supplementary material within 5 days after the date

the material is first sent to offerees, and

(b) include in or attach to the take over bid a notice setting out the

provisions of this section and stating the number, without

duplication, and designation of any shares of the public utility held

by the offeror and the offeror's associates.

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(13) Nothing in subsection (12) relieves a person from any requirement

under the Securities Act.

Appraisal of utility property

55 (1) The commission may

(a) ascertain by appraisal the value of the property of a public

utility, and

(b) inquire into every fact that, in its judgment, has a bearing on

that value, including the amount of money actually and reasonably

expended in the undertaking to provide service reasonably

adequate to the requirements of the community served by the

utility as that community exists at the time of the appraisal.

(2) In making its appraisal, the commission must have access to all records

in the possession of a municipality or any ministry or board of the

government.

(3) In making its appraisal under this section, the commission may order

(a) that all or part of the costs and expenses of the commission in

making the appraisal must be paid by the public utility, and

(b) that the utility pay an amount as the work of appraisal

proceeds.

(4) The certificate of the chair of the commission is conclusive evidence of

the amounts payable under subsection (3).

(5) Expenses approved by the commission in connection with an appraisal,

including expenses incurred by the public utility whose property is appraised,

must be charged by the utility to the cost of operating the property as a

current item of expense, and the commission may, by order, authorize or

require the utility to amortize this charge over a period and in the manner

the commission specifies.

Depreciation accounts and funds

56 (1) If the commission, after inquiry, considers that it is necessary and

reasonable that a depreciation account should be carried by a public utility,

the commission may, by order, require the utility to keep an adequate

depreciation account under rules and forms of account specified by the

commission.

(2) The commission must determine and, by order after a hearing, set

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proper and adequate rates of depreciation.

(3) The rates must be set so as to provide, in addition to the expense of

maintenance, the amounts required to keep the public utility's property in a

state of efficiency in accordance with technical and engineering progress in

that industry of the utility.

(4) A public utility must adjust its depreciation accounts to conform to the

rates fixed by the commission and, if ordered by the commission, must set

aside out of earnings whatever money is required and carry it in a

depreciation fund.

(5) Without the consent of the commission, the depreciation fund must not

be expended other than for replacement, improvement, new construction,

extension or addition to the property of the utility.

Reserve funds

57 (1) The commission may, by order, require a public utility to create and

maintain a reserve fund for any purpose the commission considers proper,

and may fix the amount or rate to be charged each year in the accounts of

the utility for the purpose of creating the reserve fund.

(2) The commission may order that no reserve fund other than that created

and maintained as directed by the commission may be created by a public

utility.

Commission may order amendment of schedules

58 (1) The commission may,

(a) on its own motion, or

(b) on complaint by a public utility or other interested person that

the existing rates in effect and collected or any rates charged or

attempted to be charged for service by a public utility are unjust,

unreasonable, insufficient, unduly discriminatory or in

contravention of this Act, the regulations or any other law,

after a hearing, determine the just, reasonable and sufficient rates to be

observed and in force.

(2) If the commission makes a determination under subsection (1), it must,

by order, set the rates.

(2.1) The commission must set rates for the authority in accordance with

(a) [Repealed RS1996-473-58 (2.3).]

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(b) the prescribed factors and guidelines, if any.

(2.2) [Repealed RS1996-473-58 (2.3).]

(2.3) Subsections (2.1) (a) and (2.2) are repealed on March 31, 2010.

(2.4) Despite subsection (2.3), a requirement prescribed for the purposes of

subsection (2.1) (a) that is in effect immediately before March 31, 2010,

continues to apply after that date as though subsection (2.2) were still in

force, unless the prescribed requirement is amended or repealed after that

date.

(3) The public utility affected by an order under this section must

(a) amend its schedules in conformity with the order, and

(b) file amended schedules with the commission.

Rate rebalancing

58.1 (1) In this section, "revenue-cost ratio" means the amount determined by

dividing the authority's revenues from a class of customers during a period of

time by the authority's costs to serve that class of customers during the

same period of time.

(2) This section applies despite

(a) any other provision of

(i) this Act, or

(ii) the regulations, except a regulation under section 3, or

(b) any previous decision of the commission.

(3) The following decision and orders of the commission are of no force or

effect to the extent that they require the authority to do anything for the

purpose of changing revenue-cost ratios:

(a) 2007 RDA Phase 1 Decision, issued October 26, 2007;

(b) order G-111-07, issued September 7, 2007;

(c) order G-130-07, issued October 26, 2007;

(d) order G-10-08, issued January 21, 2008,

and the rates of the authority that applied immediately before this section

comes into force continue to apply and are deemed to be just, reasonable

and not unduly discriminatory.

(4) [Repealed RS1996-473-58.1 (5).]

(5) Subsection (4) is repealed on March 31, 2010.

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(6) Nothing in subsection (3) prevents the commission from setting rates for

the authority, but the commission, after March 31, 2010, may not set rates

for the authority such that the revenue-cost ratio, expressed as a

percentage, for any class of customers increases by more than 2 percentage

points per year compared to the revenue-cost ratio for that class

immediately before the increase.

Discrimination in rates

59 (1) A public utility must not make, demand or receive

(a) an unjust, unreasonable, unduly discriminatory or unduly

preferential rate for a service provided by it in British Columbia, or

(b) a rate that otherwise contravenes this Act, the regulations,

orders of the commission or any other law.

(2) A public utility must not

(a) as to rate or service, subject any person or locality, or a

particular description of traffic, to an undue prejudice or

disadvantage, or

(b) extend to any person a form of agreement, a rule or a facility

or privilege, unless the agreement, rule, facility or privilege is

regularly and uniformly extended to all persons under substantially

similar circumstances and conditions for service of the same

description.

(3) The commission may, by regulation, declare the circumstances and

conditions that are substantially similar for the purpose of subsection (2) (b).

(4) It is a question of fact, of which the commission is the sole judge,

(a) whether a rate is unjust or unreasonable,

(b) whether, in any case, there is undue discrimination, preference,

prejudice or disadvantage in respect of a rate or service, or

(c) whether a service is offered or provided under substantially

similar circumstances and conditions.

(5) In this section, a rate is "unjust" or "unreasonable" if the rate is

(a) more than a fair and reasonable charge for service of the

nature and quality provided by the utility,

(b) insufficient to yield a fair and reasonable compensation for the

service provided by the utility, or a fair and reasonable return on

the appraised value of its property, or

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(c) unjust and unreasonable for any other reason.

Setting of rates

60 (1) In setting a rate under this Act

(a) the commission must consider all matters that it considers

proper and relevant affecting the rate,

(b) the commission must have due regard to the setting of a rate

that

(i) is not unjust or unreasonable within the meaning of

section 59,

(ii) provides to the public utility for which the rate is set a

fair and reasonable return on any expenditure made by it to

reduce energy demands, and

(iii) encourages public utilities to increase efficiency, reduce

costs and enhance performance,

(b.1) the commission may use any mechanism, formula or other

method of setting the rate that it considers advisable, and may

order that the rate derived from such a mechanism, formula or

other method is to remain in effect for a specified period, and

(c) if the public utility provides more than one class of service, the

commission must

(i) segregate the various kinds of service into distinct classes

of service,

(ii) in setting a rate to be charged for the particular service

provided, consider each distinct class of service as a self

contained unit, and

(iii) set a rate for each unit that it considers to be just and

reasonable for that unit, without regard to the rates fixed for

any other unit.

(2) In setting a rate under this Act, the commission may take into account a

distinct or special area served by a public utility with a view to ensuring, so

far as the commission considers it advisable, that the rate applicable in each

area is adequate to yield a fair and reasonable return on the appraised value

of the plant or system of the public utility used, or prudently and reasonably

acquired, for the purpose of providing the service in that special area.

(3) If the commission takes a special area into account under subsection (2),

it must have regard to the special considerations applicable to an area that is

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sparsely settled or has other distinctive characteristics.

(4) For this section, the commission must exclude from the appraised value

of the property of the public utility any franchise, licence, permit or

concession obtained or held by the utility from a municipal or other public

authority beyond the money, if any, paid to the municipality or public

authority as consideration for that franchise, licence, permit or concession,

together with necessary and reasonable expenses in procuring the franchise,

licence, permit or concession.

Rate schedules to be filed with commission

61 (1) A public utility must file with the commission, under rules the commission

specifies and within the time and in the form required by the commission,

schedules showing all rates established by it and collected, charged or

enforced or to be collected or enforced.

(2) A schedule filed under subsection (1) must not be rescinded or amended

without the commission's consent.

(3) The rates in schedules as filed and as amended in accordance with this

Act and the regulations are the only lawful, enforceable and collectable rates

of the public utility filing them, and no other rate may be collected, charged

or enforced.

(4) A public utility may file with the commission a new schedule of rates that

the utility considers to be made necessary by a rise in the price, over which

the utility has no effective control, required to be paid by the public utility for

its gas supplies, other energy supplied to it, or expenses and taxes, and the

new schedule may be put into effect by the public utility on receiving the

approval of the commission.

(5) Within 60 days after the date it approves a new schedule under

subsection (4), the commission may,

(a) on complaint of a person whose interests are affected, or

(b) on its own motion,

direct an inquiry into the new schedule of rates having regard to the fixing of

a rate that is not unjust or unreasonable.

(6) After an inquiry under subsection (5), the commission may

(a) rescind or vary the increase and order a refund or customer

credit by the utility of all or part of the money received by way of

increase, or

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(b) confirm the increase or part of it.

Schedules must be available to public

62 A public utility must keep a copy of the schedules filed open to and available

for public inspection under commission rules.

Schedules must be observed

63 A public utility must not, without the consent of the commission, directly or

indirectly, in any way charge, demand, collect or receive from any person for

a regulated service provided by it, or to be provided by it, compensation that

is greater than, less than or other than that specified in the subsisting

schedules of the utility applicable to that service and filed under this Act.

Orders respecting contracts

64 (1) If the commission, after a hearing, finds that under a contract entered

into by a public utility a person receives a regulated service at rates that are

unduly preferential or discriminatory, the commission may

(a) declare the contract unenforceable, either wholly or to the

extent the commission considers proper, and the contract is then

unenforceable to the extent specified, or

(b) make any other order it considers advisable in the

circumstances.

(2) If a contract is declared unenforceable either wholly or in part, the

commission may order that rights accrued before the date of the order be

preserved, and those rights may then be enforced as fully as if no

proceedings had been taken under this section.

Part 3.1

Repealed

64.01-64.04 [Repealed 2010-22-69.]

Part 4 — Carriers, Purchasers and Processors

Definition

64.1 In this Part, "sufficient notice" means notice in the manner and form,

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within the period, with the content and by the person required by the commission.

Common carrier

65 (1) In this section, "common carrier" means a person declared to be a

common carrier by the commission under subsection (2) (a).

(2) On application by an interested person and after a hearing, sufficient

notice of which has been given to all persons the commission believes may

be affected, the commission may

(a) issue an order, to be effective on a date determined by it,

declaring a person who owns or operates a pipeline for the

transportation of

(i) one or more of crude oil, natural gas and natural gas

liquids, or

(ii) any other type of energy resource prescribed by the

Lieutenant Governor in Council,

to be a common carrier with respect to the operation of the

pipeline, and

(b) in the order establish the conditions under which the common

carrier must accept and carry energy resources.

(3) On application by a person that uses or seeks to use facilities operated

by a common carrier, the commission, by order and after a hearing,

sufficient notice of which has been given to all persons the commission

believes may be affected, may establish the conditions under which the

common carrier must accept and carry crude oil, natural gas, natural gas

liquids or prescribed energy resources referred to in subsection (2) (a).

(3.1) Without limiting subsection (2) (b) or (3), the commission may

establish conditions with respect to a common carrier in relation to any of

the following matters:

(a) a toll that may be charged by the common carrier;

(b) extensions, improvements or abandonment of service.

(3.2) The commission may order that section 43 applies with respect to a

common carrier as though the common carrier were a public utility referred

to in that section.

(4) A common carrier must not unreasonably discriminate

(a) between itself and persons who apply to the common carrier to

transport, in its pipeline, crude oil, natural gas, natural gas liquids

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or prescribed energy resources referred to in

subsection (2) (a) (ii), or

(b) among the persons who so apply.

(5) A common carrier must comply with the conditions in any order

applicable to the common carrier that is made under this section.

(6) The commission may, by order and after a hearing, sufficient notice of

which has been given to all persons the commission believes may be

affected, vary an order made under this section.

(7) If an agreement between a common carrier and another person

(a) is made before an order is made under this section, and

(b) is inconsistent with the conditions established by the

commission in an order made under this section,

the commission may, in the order or in a subsequent order, after a hearing,

sufficient notice of which has been given to all persons the commission

believes may be affected, vary the agreement between the parties to

eliminate the inconsistency.

(8) Subject to subsection (9), if an agreement is varied under subsection

(7), the common carrier and the commission are not liable for damages

suffered as a result of that variation by the other party to the agreement.

(9) Subsection (8) does not apply to a common carrier referred to in that

subsection in relation to anything done or omitted by that person in bad

faith.

Common purchaser

66 (1) In this section, "common purchaser" means a person declared to be a

common purchaser by the commission under subsection (2).

(2) On application by an interested person and after a hearing, sufficient

notice of which has been given to persons the commission believes may be

affected, the commission may issue an order, to be effective on a date

determined by it, declaring a person who purchases or otherwise acquires,

from a pool designated by the commission, crude oil, natural gas or natural

gas liquids to be a common purchaser of the crude oil, natural gas or natural

gas liquids.

(3) On application by a person whose crude oil, natural gas or natural gas

liquids is or will be purchased by a common purchaser, the commission, by

order and after a hearing, sufficient notice of which has been given to all

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persons the commission believes may be affected, may establish the

conditions under which the common purchaser must purchase crude oil,

natural gas or natural gas liquid.

(4) A common purchaser must not unreasonably discriminate

(a) between itself and persons who apply for the services offered

by the common purchaser, or

(b) among the persons who so apply.

(5) A common purchaser must comply with the conditions in any order

applicable to the common purchaser that is made under this section.

(6) The commission may, by order and after a hearing, sufficient notice of

which has been given to all persons the commission believes may be

affected, vary an order made under this section.

(7) If an agreement between a common purchaser and another person

(a) is made before an order is made under this section, and

(b) is inconsistent with the conditions established by the

commission in an order made under this section,

the commission may, in the order or in a subsequent order, after a hearing,

sufficient notice of which has been given to all persons the commission

believes may be affected, vary the agreement between the parties to

eliminate the inconsistency.

(8) Subject to subsection (9), if an agreement is varied under

subsection (7), the common purchaser and the commission are not liable for

damages suffered as a result of that variation by the other party to the

agreement.

(9) Subsection (8) does not apply to a common purchaser referred to in that

subsection in relation to anything done or omitted by that person in bad

faith.

Common processor

67 (1) In this section, "common processor" means a person declared to be a

common processor by the commission under subsection (2).

(2) On application by an interested person and after a hearing, sufficient

notice of which has been given to all persons the commission believes may

be affected, the commission may issue an order, to be effective on a date

determined by it, declaring the person that owns or operates a plant for

processing natural gas to be a common processor of natural gas.

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(3) On application by a person that uses or seeks to use facilities operated

by a common processor, the commission, by order and after a hearing,

sufficient notice of which has been given to all persons the commission

believes may be affected, may establish the conditions under which the

common processor must accept and process natural gas.

(4) A common processor must not unreasonably discriminate

(a) between itself and persons who apply for the services offered

by the common processor, or

(b) among the persons who so apply.

(5) A common processor must comply with the conditions in any order

applicable to the common processor made under this section.

(6) The commission may, by order and after a hearing, sufficient notice of

which has been given to all persons the commission believes may be

affected, vary an order made under this section.

(7) If an agreement between a common processor and another person

(a) is made before an order is made under this section, and

(b) is inconsistent with the conditions established by the

commission in an order made under this section,

the commission may, in the order or a subsequent order, after a hearing,

sufficient notice of which has been given to all persons the commission

believes may be affected, vary the agreement between the parties to

eliminate the inconsistency.

(8) Subject to subsection (9), if an agreement is varied under subsection

(7), the common processor and the commission are not liable for damages

suffered as a result of that variation by the other party to the agreement.

(9) Subsection (8) does not apply to a common processor referred to in that

subsection in relation to anything done or omitted by that person in bad

faith.

Part 5 — Electricity Transmission

Definitions

68 In this Part:

"electricity transmission facilities" means conductors, circuits,

transmission towers, substations, switching stations, transformers and

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any other equipment or facilities that are necessary for the purpose of

transmitting electricity;

"energy" means electricity or natural gas;

"energy supply contract" means a contract under which energy is sold

by a seller to a public utility or another buyer, and includes an

amendment of that contract, but does not include a contract in respect of

which a schedule is approved under section 61 of this Act;

"gas marketer" means a person who holds a gas marketer licence

issued under section 71.1 (6) (a);

"low-volume consumer" has the meaning ascribed to it under rules

made by the commission under section 71.1 (10);

"natural gas" means any methane, propane or butane that is sold for

consumption as a domestic, commercial or industrial fuel or as an

industrial raw material;

"public utility" means a public utility to which Part 3 applies;

"seller" means a person who sells or trades in energy.

Repealed

69 [Repealed 2003-46-10.]

Use of electricity transmission facilities

70 (1) On application and after a hearing, the commission may make an order

directing a public utility to allow a person, other than a public utility, to use

the electricity transmission facilities of the public utility if the commission

finds that

(a) the person and the public utility have failed to agree on the use

of the facilities or on the conditions or compensation for their use,

(b) the use of the facilities will not prevent the public utility or

other users from performing their duties or result in any substantial

detriment to their service, and

(c) the public interest requires the use of the facilities by the

person.

(2) An order under subsection (1) may contain terms and conditions the

commission considers advisable, including terms and conditions respecting

the rates payable to the public utility for the use of its electricity

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transmission facilities.

(3) After a hearing, the commission may, by order, vary or rescind an order

made under this section.

(4) Any interested person may apply to the commission for an order under

this section, and the application must contain the information the

commission specifies.

Energy supply contracts

71 (1) Subject to subsection (1.1), a person who, after this section comes into

force, enters into an energy supply contract must

(a) file a copy of the contract with the commission under rules and

within the time it specifies, and

(b) provide to the commission any information it considers

necessary to determine whether the contract is in the public

interest.

(1.1) Subsection (1) does not apply to an energy supply contract for the sale

of natural gas unless the sale is to a public utility.

(2) The commission may make an order under subsection (3) if the

commission, after a hearing, determines that an energy supply contract to

which subsection (1) applies is not in the public interest.

(2.1) In determining under subsection (2) whether an energy supply contract

filed by a public utility other than the authority is in the public interest, the

commission must consider

(a) the applicable of British Columbia's energy objectives,

(b) the most recent long-term resource plan filed by the public

utility under section 44.1, if any,

(c) the extent to which the energy supply contract is consistent

with the applicable requirements under sections 6 and 19 of the

Clean Energy Act,

(d) the interests of persons in British Columbia who receive or may

receive service from the public utility,

(e) the quantity of the energy to be supplied under the contract,

(f) the availability of supplies of the energy referred to in

paragraph (e),

(g) the price and availability of any other form of energy that could

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be used instead of the energy referred to in paragraph (e), and

(h) in the case only of an energy supply contract that is entered

into by a public utility, the price of the energy referred to in

paragraph (e).

(2.2) Subsection (2.1) (a) to (c) does not apply if the commission considers

that the matters addressed in the energy supply contract filed under

subsection (1) were determined to be in the public interest in the course of

considering a long-term resource plan under section 44.1.

(2.21) In determining under subsection (2) whether an energy supply

contract filed by the authority is in the public interest, the commission, in

addition to considering the interests of persons in British Columbia who

receive or may receive service from the authority, must consider and be

guided by

(a) British Columbia's energy objectives,

(b) an applicable integrated resource plan approved under section

4 of the Clean Energy Act,

(c) the extent to which the energy supply contract is consistent

with the requirements under section 19 of the Clean Energy Act,

(d) the quantity of the energy to be supplied under the contract,

(e) the availability of supplies of the energy referred to in

paragraph (d),

(f) the price and availability of any other form of energy that could

be used instead of the energy referred to in paragraph (d), and

(g) in the case only of an energy supply contract that is entered

into by a public utility, the price of the energy referred to in

paragraph (d).

(2.3) A public utility may submit to the commission a proposed energy

supply contract setting out the terms and conditions of the contract and a

process the public utility intends to use to acquire power from other persons

in accordance with those terms and conditions.

(2.4) If satisfied that it is in the public interest to do so, the commission, by

order, may approve a proposed contract submitted under subsection (2.3)

and a process referred to in that subsection.

(2.5) In considering the public interest under subsection (2.4) with respect

to a submission by a public utility other than the authority, the commission

must consider

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(a) the applicable of British Columbia's energy objectives,

(b) the most recent long-term resource plan filed by the public

utility under section 44.1,

(c) the extent to which the application for the proposed contract is

consistent with the applicable requirements under sections 6 and

19 of the Clean Energy Act, and

(d) the interests of persons in British Columbia who receive or may

receive service from the public utility.

(2.51) In considering the public interest under subsection (2.4) with respect

to a submission by the authority, the commission, in addition to considering

the interests of persons in British Columbia who receive or may receive

service from the authority, must consider and be guided by

(a) British Columbia's energy objectives,

(b) an applicable integrated resource plan approved under section

4 of the Clean Energy Act, and

(c) the extent to which the application for the proposed contract is

consistent with the requirements under section 19 of the Clean Energy Act.

(2.6) If the commission issues an order under subsection (2.4), the

commission may not issue an order under subsection (3) with respect to a

contract

(a) entered into exclusively on the terms and conditions, and

(b) as a result of the process

referred to in subsection (2.3).

(3) If subsection (2) applies, the commission may

(a) by order, declare the contract unenforceable, either wholly or

to the extent the commission considers proper, and the contract is

then unenforceable to the extent specified, or

(b) make any other order it considers advisable in the

circumstances.

(4) If an energy supply contract is, under subsection (3) (a), declared

unenforceable either wholly or in part, the commission may order that rights

accrued before the date of the order under that subsection be preserved,

and those rights may then be enforced as fully as if no proceedings had been

taken under this section.

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(5) An energy supply contract or other information filed with the commission

under this section must be made available to the public unless the

commission considers that disclosure is not in the public interest.

Gas marketers

71.1 (1) A person must not perform a gas marketing activity within the meaning

of subsection (2) unless

(a) the person is a public utility and the public utility performs the

gas marketing activity within any area in which it is authorized to

provide service, or

(b) the person holds a gas marketer licence issued to the person

under subsection (6) (a).

(2) For the purposes of subsection (1), a person performs a gas marketing

activity if the person

(a) sells or offers to sell natural gas to a low-volume consumer,

(b) acts as the agent or broker for a seller in a sale of natural gas

to a low-volume consumer, or

(c) acts or offers to act as the agent or broker of a low-volume

consumer in a purchase of natural gas.

(3) A gas marketer must comply with the commission rules issued under

subsection (10) and the terms and conditions, if any, attached to the gas

marketer licence held by the gas marketer.

(4) A gas marketer must not carry on or offer to carry on business as a gas

marketer in a name other than the name in which it is licensed unless

authorized to do so in the licence.

(5) If a person is not in compliance with subsection (1), (3) or (4), the

commission may do one or more of

(a) declare an energy supply contract between the person and a

low-volume consumer unenforceable, either wholly or to the extent

the commission considers proper, in which event the contract is

enforceable to the extent specified, and

(b) if the person is a gas marketer,

(i) amend the terms and conditions of, or impose new terms

and conditions on, the gas marketer licence, and

(ii) suspend or cancel the gas marketer licence.

(6) The commission may

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(a) on application, issue a gas marketer licence to any person who

is not a public utility,

(b) impose, in respect of any gas marketer licence issued by the

commission, terms and conditions that the commission considers

appropriate,

(c) amend any of the terms and conditions imposed in respect of a

gas marketer licence, and

(d) suspend or cancel a gas marketer licence.

(7) The commission may require, as a condition of granting a gas marketer

licence, that the gas marketer post security in a form, and in accordance

with such terms and conditions, as the commission considers appropriate.

(8) The commission may order that some or all of the security posted by a

gas marketer in accordance with a requirement imposed under

subsection (7) be paid out to those persons who the commission considers

have been or may be affected by an act or omission of the gas marketer.

(9) Section 43 applies to each gas marketer as if that gas marketer were a

public utility.

(10) The commission may make the following rules:

(a) defining "low-volume consumer";

(b) respecting the process by which application may be made for a

gas marketer licence and specifying the form and content of

applications for that licence;

(c) respecting the imposition of terms and conditions on gas

marketer licences;

(d) requiring an applicant for a gas marketer licence to obtain a

bond, letter of credit or other specified security and requiring the

filing with the commission of proof, satisfactory to the commission,

of that security;

(e) respecting the form and content of security that may be

required under paragraph (d) and the person by whom and the

terms on which it is to be held;

(f) respecting the circumstances in which and the persons to whom

disbursement of some or all of the security required under

paragraph (d) is to be made.

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Part 6 — Commission Jurisdiction

Jurisdiction of commission to deal with applications

72 (1) The commission has jurisdiction to inquire into, hear and determine an

application by or on behalf of any party interested, complaining that a person

constructing, maintaining, operating or controlling a public utility service or

charged with a duty or power relating to that service, has done, is doing or

has failed to do anything required by this Act or another general or special

Act, or by a regulation, order, bylaw or direction made under any of them.

(2) The commission has jurisdiction to inquire into, hear and determine an

application by or on behalf of any party interested, requesting the

commission to

(a) give a direction or approval which by law it may give, or

(b) approve, prohibit or require anything to which by any general

or special Act, the commission's jurisdiction extends.

Mandatory and restraining orders

73 (1) The commission may order and require a person to do immediately or by

a specified time and in the way ordered, so far as is not inconsistent with this

Act, the regulations or another Act, anything that the person is or may be

required or authorized to do under this Act or any other general or special

Act and to which the commission's jurisdiction extends.

(2) The commission may forbid and restrain the doing or continuing of

anything contrary to or which may be forbidden or restrained under any Act,

general or special, to which the commission's jurisdiction extends.

Inspections and depositions

74 For the purposes of this Act, the commission may

(a) enter on and inspect property, and

(b) require the taking of depositions inside or outside of British

Columbia.

Commission not bound by precedent

75 The commission must make its decision on the merits and justice of the

case, and is not bound to follow its own decisions.

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Jurisdiction as to liquidators and receivers

76 (1) The fact that a liquidator, receiver, manager or other official of a public

utility, or other person engaged in the petroleum industry, or a person

seizing a public utility's property has been appointed by a court in British

Columbia, or is acting under the authority of a court, does not prevent the

exercise by the commission of any jurisdiction conferred by this Act.

(2) A liquidator, receiver, manager, official or person seizing must act in

accordance with this Act and the orders and directions of the commission,

whether the orders are general or particular.

(3) The liquidator or other person referred to in subsection (1), and any

person acting under that person, must obey the orders of the commission,

within its jurisdiction, and the commission may enforce its orders against the

person even though the person is appointed by or acts under the authority of

a court.

Power to extend time

77 If a work, act, matter or thing is, by order or decision of the commission,

required to be performed or completed within a specified time, the

commission may, if the circumstances of the case in its opinion so require,

extend the time so specified

(a) on notice and hearing, or

(b) in its discretion, on application, without notice to any person.

Evidence

78 (1) [Repealed 2004-45-169.]

(2) An inquiry that the commission considers necessary may be made by a

member or officer or by a person appointed by the commission to make the

inquiry, and the commission may act on that person's report.

(3) Each member, officer and person appointed has, for the purpose of the

inquiry, the powers conferred on the commission by section 74 of this Act

and section 34 (3) and (4) of the Administrative Tribunals Act.

(4) If a person is appointed to inquire and report on a matter, the

commission may order by whom, and in what proportion, the costs incurred

must be paid, and may set the amount of the costs.

Findings of fact conclusive

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79 The determination of the commission on a question of fact in its jurisdiction,

or whether a person is or is not a party interested within the meaning of this

Act, is binding and conclusive on all persons and all courts.

Commission not bound by judicial acts

80 In determining a question of fact, the commission is not bound by the finding

or order of a court in a proceeding involving the determination of that fact,

and the finding or order is, before the commission, evidence only.

Pending litigation

81 The fact that a suit, prosecution or other proceeding in a court involving

questions of fact is pending does not deprive the commission of jurisdiction

to hear and determine the same questions of fact.

Power to inquire without application

82 (1) The commission

(a) may, on its own motion, and

(b) must, on the request of the Lieutenant Governor in Council,

inquire into, hear and determine a matter that under this Act it may inquire

into, hear or determine on application or complaint.

(2) For the purpose of subsection (1), the commission has the same powers

as are vested in it by this Act in respect of an application or complaint.

Action on complaints

83 If a complaint is made to the commission, the commission has powers to

determine whether a hearing or inquiry is to be had, and generally whether

any action on its part is or is not to be taken.

General powers not limited

84 The enumeration in this Act of a specific commission power or authority does

not exclude or limit other powers or authorities given to the commission.

Hearings to be held in certain cases

85 (1) Except in case of urgency, of which the commission is sole judge, the

commission must not, without a hearing, make an order involving an outlay,

loss or deprivation to a public utility.

(2) If an order is made in case of urgency without a hearing, on the

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application of a person interested, the commission must as soon as

practicable hear and reconsider the matter and make any further order it

considers advisable.

Public hearing

86 If this Act requires that a hearing be held, it must be a public hearing

whenever, in the opinion of the commission or the Lieutenant Governor in

Council, a public hearing is in the public interest.

Repealed

86.1 [Repealed 2004-45-170.]

When oral hearings not required

86.2 (1) Despite any other provision of this Act, in any circumstance in which,

under this Act, a hearing may or must be held, the commission may conduct

a written hearing.

(2) The commission may make rules respecting the circumstances in which

and the process by which written hearings may be conducted and specifying

the form and content of materials to be provided for written hearings.

Recitals not required in orders

87 In making an order, the commission is not required to recite or show on the

face of the order the taking of any proceeding, the giving of any notice or the

existence of any circumstance necessary to give the commission jurisdiction.

Application of orders

88 (1) In making an order, rule or regulation, the commission may make it

apply to all cases, or to a particular case or class of cases, or to a particular

person.

(2) The commission may exempt a person from the operation of an order,

rule or regulation made under this Act for a time the commission considers

advisable.

(3) The commission may, on conditions it considers advisable, with the

advance approval of the Lieutenant Governor in Council, exempt a person,

equipment or facilities from the application of all or any of the provisions of

this Act or may limit or vary the application of this Act.

(4) The commission has no power under this section to make an order

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respecting a person, or a person in respect of a matter, who has been

exempted under section 22.

Withdrawal of application

88.1 If an applicant withdraws all or part of an application or the parties advise

the commission that they have reached a settlement of all or part of an

application, the commission may order that the application or part of it is

dismissed.

Partial relief

89 On an application under this Act, the commission may make an order

granting the whole or part of the relief applied for or may grant further or

other relief, as the commission considers advisable.

Commencement of orders

90 (1) In an order or regulation, the commission may direct that the order or

regulation or part of it comes into operation

(a) at a future time,

(b) on the happening of an event specified in the order or

regulation, or

(c) on the performance, to the satisfaction of the commission, by a

person named by it of a term imposed by the order.

(2) The commission may, in the first instance, make an interim order, and

reserve further direction for an adjourned hearing or further application.

Orders without notice

91 (1) If the special circumstance of a case so requires, the commission may,

without notice, make an interim order authorizing, requiring or forbidding

anything to be done that the commission is empowered to authorize, require

or forbid on application, notice or hearing.

(2) The commission must not make an interim order under subsection (1) for

a longer time than it considers necessary for a hearing and decision.

(3) A person interested may, before final decision, apply to modify or set

aside an interim order made without notice.

Directions

92 If, in the exercise of a commission power under an Act, the commission

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directs that a structure, appliance, equipment or works be provided, constructed,

reconstructed, removed, altered, installed, operated, used or maintained, the

commission may, except as otherwise provided in the Act conferring the

power, order

(a) by what person interested at or within what time,

(b) at whose cost and expense,

(c) on what terms including payment of compensation, and

(d) under what supervision,

the structure, appliance, equipment or works must be carried out.

Repealed

93-94 [Repealed 2004-45-170.]

Lien on land

95 (1) If the commission makes an order for payment of money, costs or a

penalty, the commission may register a copy of the order certified by the

commission's secretary in a land title office.

(2) On registration in a land title office, an order is a lien and charge on all

the land of the person ordered to make the payment that is in the land title

district in which the order is registered, to the same extent and with the

same effect and realizable in the same way as a judgment of the Supreme

Court under the Court Order Enforcement Act.

Substitute to carry out orders

96 (1) If a person defaults in doing anything directed by an order of the

commission under this Act,

(a) the commission may authorize a person it considers suitable to

do the thing, and

(b) the person authorized may do the thing authorized and may

recover from the person in default the expense incurred in doing

the thing, as money paid for and at the request of that person.

(2) The certificate of the commission of the amount expended is conclusive

evidence of the amount of the expense.

Entry, seizure and management

97 (1) The commission may take the steps and employ the persons it considers

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necessary to enforce an order made by it, and, for that purpose, may forcibly or

otherwise enter on, seize and take possession of the whole or part of the

business and the property of a public utility affected by the order, together

with the records, offices and facilities of the utility.

(2) The commission may, until the order has been enforced or until the

Lieutenant Governor in Council otherwise orders, assume, take over and

continue the management of the business and property of the utility in the

interest of its shareholders, creditors and the public.

(3) While the commission continues to manage or direct the management of

the utility, the commission may exercise, for the business and property, the

powers, duties, rights and functions of the directors, officers or managers of

the utility in all respects, including the employment and dismissal of officers

or employees and the employment of others.

(4) On the commission taking possession of the business and property of the

utility, each officer and employee of the utility must obey the lawful orders

and instructions of the commission for that business and property, and of

any person placed by the commission in authority in the management of the

utility or a department of its undertaking or service.

(5) On taking possession of the business and property of a public utility, the

commission may determine, receive or pay out all money due to or owing by

the utility, and give cheques and receipts for money to the same extent and

to the same effect as the utility or its officers or employees could do.

(6) The costs incurred by the commission under this section are in the

discretion of the commission, and the commission may order by whom and

in what amount or proportion costs are to be paid.

Defaulting utility may be dissolved

98 (1) If a public utility incorporated under an Act of the Legislature fails to

comply with a commission order, and the commission believes that no

effective means exist to compel the utility to comply, the commission, in its

discretion, may transmit to the Attorney General a certificate, signed by its

chair and secretary, setting out the nature of the order and the default of the

public utility.

(2) Ten days after publication in the Gazette of a notice of receipt of the

certificate by the Attorney General, the Lieutenant Governor in Council may,

by order, dissolve the public utility.

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Part 7 — Decisions and Appeals

Reconsideration by commission

99 The commission may reconsider, vary or rescind a decision, order, rule or

regulation made by it, and may rehear an application before deciding it.

Requirement for hearing

100 If a hearing is held or required under this Act before a rule or regulation is

made, the rule or regulation must not be altered, suspended or revoked

without a hearing.

Appeal to Court of Appeal

101 (1) An appeal lies from a decision or order of the commission to the Court of

Appeal with leave of a justice of that court.

(2) The party appealing must give notice of the application for leave to

appeal, stating the grounds of appeal, to the commission, to the Attorney

General and to any party adverse in interest, at least 2 clear days before the

hearing of the application.

(3) If leave is granted, within 15 days from the granting, the appellant must

give notice of appeal to the commission, to the Attorney General, and to any

party adverse in interest.

(4) The commission and the Attorney General may be heard by counsel on

the appeal.

(5) On the determination of the questions involved in the appeal, the Court

of Appeal must certify its opinion to the commission, and an order of the

commission must conform to that opinion.

No automatic stay of proceedings while matter appealed

102 (1) An appeal to the Court of Appeal does not of itself stay or suspend the

operation of the decision, order, rule or regulation appealed from, but the

Court of Appeal may grant a suspension, in whole or in part, until the appeal

is decided, on the terms the court considers advisable.

(2) The commission may, in its discretion, suspend the operation of its

decision, order, rule or regulation from which an appeal is taken until the

decision of the Court of Appeal is given.

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Costs of appeal

103 (1) Payment of the costs incurred for an application or appeal to the Court of

Appeal may be enforced in the same way as payment of costs ordered by the

commission.

(2) Neither the commission nor an officer, employee or agent of the

commission is liable for costs in respect of an application or appeal referred

to in subsection (1).

Case stated by commission

104 (1) The commission may, on its own motion or on the application of a party

who gives the security the commission directs, and must, on the request of

the Attorney General, state a case in writing for the opinion of the Court of

Appeal on a question that, in the opinion of the commission or of the

Attorney General, is a question of law.

(2) The Court of Appeal must hear and determine all questions of law arising

on the stated case and must remit the matter to the commission with the

court's opinion.

(3) The court's opinion is binding on the commission and on all parties.

Jurisdiction of commission exclusive

105 (1) The commission has exclusive jurisdiction in all cases and for all matters

in which jurisdiction is conferred on it by this or any other Act.

(2) Unless otherwise provided in this Act, an order, decision or proceeding of

the commission must not be questioned, reviewed or restrained by or on an

application for judicial review or other process or proceeding in any court.

Part 8 — Offences and Penalties

Offences

106 (1) The following persons commit an offence:

(a) a person who fails or refuses to obey an order of the

commission made under this Act;

(b) a person who does, causes or permits to be done an act,

matter or thing contrary to this Act or omits to do an act, matter or

thing required to be done by this Act;

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(c) a public utility

(i) that fails or refuses to prepare and provide to the

commission in the time, manner and form, and with the

particulars and verification required under this Act, an

information return, the answer to a question submitted by

the commission or information required by the commission

under this Act,

(ii) that willfully or negligently makes a return or provides

information to the commission that is false in any particular,

(iii) that gives, or an officer of which gives, to an officer,

agent, manager or employee of the utility a direction,

instruction or request to do or refrain from doing an act

referred to in paragraph (d) (i) to (vii) and in respect of

which the officer, agent, manager or employee is convicted

under paragraph (d) (i) to (vii), or

(iv) an officer, agent, manager or employee of which is

convicted of an offence under paragraph (d) (viii);

(d) an officer, agent, manager or employee of a public utility

(i) who fails or refuses to complete and provide to the

commission a report or form of return required under this

Act,

(ii) who fails or refuses to answer a question contained in a

report or form of return required under this Act,

(iii) who willfully gives a false answer to a question

contained in a report or form of return required under this

Act,

(iv) who evades a question or gives an evasive answer to a

question contained in a report or form of return required

under this Act, if the person has the means to ascertain the

facts,

(v) who, after proper demand under this Act, fails or refuses

to exhibit to the commission or a person authorized by it an

account, record or memorandum of the public utility that is in

the person's possession or under the person's control,

(vi) who fails to properly use and keep the system of

accounting of the public utility specified by the commission

under this Act,

(vii) who refuses to do any act or thing in that system of

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accounting when directed by the commission or its

representative,

(viii) on whom the commission serves notice directing the

person to provide to the commission information or a return

that the utility may be required to provide under this Act and

who willfully refuses or fails to provide the information or

return to the best of the person's knowledge, or means of

knowledge, in the manner and time directed by the

commission, or

(ix) who knowingly registers or causes to be registered on

the books of the public utility any issue or transfer of shares

that has been made contrary to section 54 (5), (7) or (8);

(e) the president, and each vice president, director, managing

director, superintendent and manager of a public utility that fails or

refuses to obey an order of the commission made under this Act;

(f) the mayor and each councillor or member of the ruling body of

a municipality that fails or refuses to obey an order of the

commission made under this Act;

(g) [Repealed 2003-46-15.]

(h) a person who obstructs or interferes with a commissioner,

officer or person in the exercise of rights conferred or duties

imposed under this Act;

(i) a person who knowingly solicits, accepts or receives, directly or

indirectly, a rebate, concession or discrimination for service of a

public utility, if the service is provided or received in violation of

this Act;

(j) except so far as the person's public duty requires the person to

report on or take official action, an officer or employee of the

commission, or person having access to or knowledge of a return

made to the commission or of information procured or evidence

taken under this Act, other than a public inquiry or public hearing,

who, without first obtaining the authority of the commission,

publishes or makes known information, having obtained or knowing

it to have been derived from the return, information or evidence;

(k) a person who applies to a public utility to register on its books

any issue or transfer of shares that has been made contrary to

section 54 (5), (7) or (8).

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(2) Subsection (1) (e) and (f) does not apply if the person proves

(a) that, according to the person's position and authority, the

person took all necessary and proper means in the person's power

to obey and carry out, and to procure obedience to and the

carrying out of the order, and

(b) that the person was not at fault for the failure or refusal.

(3) Subsection (1) (h) does not apply if the commissioner, officer or person

does not, on request at the time, produce a certificate of his or her

appointment or authority.

(4) A person convicted of an offence under this section is liable to a penalty

not greater than $10 000.

(5) If this Act makes anything an offence, each day the offence continues

constitutes a separate offence.

(6) Nothing in or done under this section affects the liability of a public utility

otherwise existing or prejudices enforcement of an order of the commission

in any way otherwise available.

Restraining orders

107 (1) If a person, to or in respect of whom

(a) [Repealed 2003-46-16.]

(b) a certificate of public convenience and necessity,

(c) an order under section 22, 53 or 54 (10), or

(d) an approval given under section 50 or 54 (5), (7) or (8),

is issued, contravenes a condition or requirement of the certificate, order or

approval, the contravention may be restrained in a proceeding brought by

the minister in the Supreme Court.

(2) [Repealed 2003-46-16.]

Revocation of certificates

108 If a person contravenes a condition or requirement of an order made under

section 22,

(a) the Lieutenant Governor in Council may revoke

(i) the energy project certificate or energy operation

certificate in respect of which the contravention occurred,

and

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(ii) any approval, licence or permit given or issued, in

association with the certificate, or

(b) the minister responsible for the administration of the Hydro and Power Authority Act may revoke the order.

Remedies not mutually exclusive

109 If a person contravenes

(a) [Repealed 2003-46-18.]

(b) a condition or requirement of an order made under section 22,

53 or 54 (10),

(c) the conditions of an approval given under section 50 or 54 (5),

(7) or (8), or

(d) a condition or requirement of a certificate of public convenience

and necessity,

the penalties for the contravention provided for in section 106, the remedies

for the contravention provided for in section 107 and, if applicable, the

remedies provided for in section 108 are not mutually exclusive, and any or

all of them may be applied in the one case.

Part 9 — General

Powers of commission in relation to other Acts

110 The powers given to the commission by this Act apply

(a) even though the subject matter about which the powers are

exercisable is the subject matter of an agreement or another Act,

(b) in respect of service and rates, whether fixed by or the subject

of an agreement or other Act, or otherwise, and

(c) if the service or rates are governed by an agreement, whether

the agreement is incorporated in, or ratified, or made binding by a

general or special Act, or otherwise.

Substantial compliance

111 Substantial compliance with this Act is sufficient to give effect to the orders,

rules, regulations and acts of the commission, and they must not be declared

inoperative, illegal or void for want of form or an error or omission of a

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technical or clerical nature.

Vicarious liability

112 In construing and enforcing this Act, or a rule, regulation, order or direction

of the commission, an act, omission or failure of an officer, agent or other

person acting for or employed by a public utility, if within the scope of the

person's employment, is deemed in every case to be the act, omission or

failure of the utility.

Public utilities may apply

113 A person who is subject to regulation under this Act may make application or

complaint to the commission about a matter affecting a public utility, as if

made by another party interested.

Municipalities may apply

114 (1) In this section, "municipality" includes a regional district.

(2) If a municipality believes that the interests of the public in the

municipality or a part of it are sufficiently concerned, the municipality may,

by resolution, become an applicant, complainant or intervenant in a matter

within the commission's jurisdiction.

(3) The municipality may, for subsection (2), take a proceeding or incur

expense necessary

(a) to submit the matter to the commission,

(b) to oppose an application or complaint before the commission,

or

(c) if necessary, to become a party to a proceeding or appeal under

this Act.

Certified documents as evidence

115 (1) A copy of a rule, regulation, order or other document in the commission

secretary's custody, purporting to be certified by the secretary to be a true

copy, is evidence of the document without proof of the signature.

(2) A certificate purporting to be signed by the commission secretary stating

that no rule, regulation or order on a specified matter has been made by the

commission, is evidence of the fact stated without proof of the signature.

Class representation

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116 (1) With the approval of the Attorney General, the commission may appoint

counsel to represent a class of persons interested in a matter for the purpose

of instituting or attending on an application or hearing before the commission

or another tribunal or authority.

(2) The commission may fix the costs of the counsel and may order by

whom and in what amount or proportion they be paid.

Costs of commission

117 (1) In this section, "costs of the commission" includes costs incurred by

the commission for the services of consultants and experts engaged in

connection with the proceeding.

(2) The commission may order that the costs of the commission incidental to

a proceeding before it are to be paid by one or more participants in the

proceeding in such amounts and proportions as the commission may

determine.

Participant costs

118 (1) The commission may order a participant in a proceeding before the

commission to pay all or part of the costs of another participant in the

proceeding.

(2) If the commission considers it to be in the public interest, the

commission may pay all or part of the costs of participants in proceedings

before the commission that were commenced on or after April 1, 1993 or

that are commenced after June 18, 1993.

(3) Amounts paid for costs under subsection (2) must not exceed the limits

prescribed for the purposes of this section.

Tariff of fees

119 With the advance approval of the Lieutenant Governor in Council, the

commission may prescribe a tariff of fees for a matter within the

commission's jurisdiction.

No waiver of rights

120 (1) Nothing in this Act releases or waives a right of action by the commission

or a person for a right, penalty or forfeiture that arises under a law of British

Columbia.

(2) No penalty enforceable under this Act is a bar to or affects recovery for a

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right, or affects or bars a proceeding against or prosecution of a public

utility, its directors, officers, agents or employees.

Relationship with Local Government Act

121 (1) Nothing in or done under the Community Charter or the Local Government Act

(a) supersedes or impairs a power conferred on the commission or

an authorization granted to a public utility, or

(b) relieves a person of an obligation imposed under this Act or the

Gas Utility Act.

(2) In this section, "authorization" means

(a) a certificate of public convenience and necessity issued under

section 46,

(b) an exemption from the application of section 45 granted, with

the advance approval of the Lieutenant Governor in Council, by the

commission under section 88, and

(c) an exemption from section 45 granted under section 22, only if

the public utility meets the conditions prescribed by the Lieutenant

Governor in Council.

(3) For the purposes of subsection (2) (c), the Lieutenant Governor in

Council may prescribe different conditions for different public utilities or

categories of public utilities.

Repealed

122 [Repealed 2004-45-172.]

Service of notice

123 (1) A notice that the commission is empowered or required to give to a

person under this Act must be in writing and may be served either personally

or by mailing it to the person's address.

(2) If a notice is mailed, service of the notice is deemed to be effected at the

time at which the letter containing the notice, properly addressed, postage

prepaid and mailed, would be delivered in the ordinary course of post.

Reasons to be given

124 (1) If an application to the commission is opposed, the commission must

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prepare written reasons for its decision.

(2) If an application is unopposed, the commission may, and at the request

of the applicant must, prepare written reasons for its decision.

(3) Written reasons must be made available by the secretary to any person

on payment of the fee set by the commission.

(4) [Repealed 2003-46-20.]

Regulations

125 (1) The Lieutenant Governor in Council may make regulations as referred to

in section 41 of the Interpretation Act.

(2) Without limiting subsection (1), the Lieutenant Governor in Council may,

for the purpose of recovering the expenses arising out of the administration

of this Act in a fiscal year, make regulations as follows:

(a) setting, or authorizing the commission to set, by order of the

commission, and to collect fees, levies or other charges from

(i) public utilities, a class of public utility or a particular

public utility, and

(ii) other persons to whom a provision of this Act applies or

a class of those persons;

(b) setting, or authorizing the commission to set, the fees, levies or

other charges payable by the members of the different classes

referred to in paragraph (a) in different amounts;

(c) exempting, or authorizing the commission to exempt, a public

utility or other person, or a class of either of them, from the

payment of a fee, levy or other charge;

(d) authorizing the commission to retain all or part of any fees,

levies or other charges collected by the commission under a

regulation;

(e) requiring the commission to set a rate for the purposes of

section 28 (2.1) and prescribing requirements for the purposes of

that section.

(3) The commission may make regulations on a matter for which it is

empowered by this Act to make regulations.

Minister's regulations

125.1 (1) In this section, "minister" means the minister responsible for the

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administration of the Hydro and Power Authority Act.

(2)-(3) [Repealed 2010-22-72.]

(4) The minister may make regulations as follows:

(a) [Repealed 2010-22-72.]

(b) respecting exemptions under section 22;

(c) [Repealed 2010-22-72.]

(d) [Repealed 2010-22-72.]

(e) for the purposes of sections 44.1 and 44.2,

(i) prescribing rules for determining whether a demand-side

measure, or a class of demand-side measures, is adequate,

cost-effective or both,

(ii) declaring a demand-side measure, or a class of demand-

side measures, to be cost effective and necessary for

adequacy, and

(iii) prescribing rules or factors a public utility must use in

making the estimate referred to in section 44.1 (2) (a);

(iv) [Repealed 2010-22-72.]

(f) [Repealed 2010-22-72.]

(g) prescribing factors and guidelines for the purposes of section

58 (2.1) (b), including, without limitation, factors and guidelines to

encourage

(i) energy conservation or efficiency,

(ii) the use of energy during periods of lower demand,

(iii) the development and use of energy from clean or

renewable resources, or

(iv) the reduction of the energy demand a public utility must

serve;

(h) defining a term or phrase used in section 58.1 and not defined

in this Act;

(i) identifying facts that must be used in interpreting the definition

in section 58.1;

(j)-(n) [Repealed 2010-22-72.]

(o) prescribing standard-making bodies for the purposes of section

125.2 (1) and matters for the purposes of section 125.2 (3) (d);

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(p) prescribing owners, operators, direct users, generators and

distributors, or classes of any of them, for the purposes of section

125.2 (8).

(5) In making a regulation under this section, the minister may

(a) make regulations of specific or general application, and

(b) make different regulations for different persons, places, things,

measures, transactions or activities.

Adoption of reliability standards, rules or codes

125.2 (1) In this section:

"reliability standard" means a reliability standard, rule or code

established by a standard-making body for the purpose of being a

mandatory reliability standard for planning and operating the North

American bulk power system, and includes any substantial change to any

of those standards, rules or codes;

"standard-making body" means

(a) the North American Electric Reliability Corporation,

(b) the Western Electricity Coordinating Council, and

(c) a prescribed standard-making body.

(2) For greater certainty, the commission has exclusive jurisdiction to

determine whether a reliability standard is in the public interest and should

be adopted in British Columbia.

(3) The authority must review each reliability standard and provide to the

commission, in accordance with the regulations, a report assessing

(a) any adverse impact of the reliability standard on the reliability

of electricity transmission in British Columbia if the reliability

standard were adopted under subsection (6),

(b) the suitability of the reliability standard for British Columbia,

(c) the potential cost of the reliability standard if it were adopted

under subsection (6), and

(d) any other matter prescribed by regulation or identified by order

of the commission for the purposes of this section.

(4) The commission may make an order for the purposes of subsection (3)

(d).

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(5) If the commission receives a report under subsection (3), the

commission must

(a) make the report available to the public in a reasonable manner,

which may include by electronic means, and for a reasonable

period of time, and

(b) consider any comments the commission receives in reply to the

publication referred to in paragraph (a).

(6) After complying with subsection (5), the commission, subject to

subsection (7), must adopt the reliability standards addressed in the report if

the commission considers that the reliability standards are required to

maintain or achieve consistency in British Columbia with other jurisdictions

that have adopted the reliability standards.

(7) The commission is not required to adopt a reliability standard under

subsection (6) if the commission determines, after a hearing, that the

reliability standard is not in the public interest.

(8) A reliability standard adopted under subsection (6) applies to every

(a) prescribed owner, operator and direct user of the bulk power

system, and

(b) prescribed generator and distributor of electricity.

(9) Subsection (8) applies to a person prescribed for the purposes of that

subsection despite any exemption issued to the person under section 22 or

88 (3).

(10) The commission may make orders providing for the administration of

adopted reliability standards.

(11) The commission, on its own motion or on complaint, may

(a) rescind an adoption made under subsection (6), or

(b) adopt a reliability standard previously rejected under

subsection (7)

if the commission determines, after a hearing, that the rescission or adoption

is in the public interest.

(12) The commission, without the approval of the minister responsible for

the administration of the Hydro and Power Authority Act, may not set a

standard or rule under section 26 of this Act with respect to a matter

addressed by a reliability standard assessed in a report submitted to the

commission under subsection (3) of this section.

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Intent of Legislature

126 If a provision of this Act is held to be beyond the powers of British Columbia,

that provision must be severed from the remainder of the Act, and the

remaining provisions of the Act have the same effect as if they had been

originally enacted as a separate enactment and as the only provisions of this

Act.

Copyright (c) Queen's Printer, Victoria, British Columbia, Canada

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SIXTH FLOOR, 900 HOWE STREET, BOX 250 VANCOUVER, B.C.  V6Z 2N3   CANADA 

web site: http://www.bcuc.com

TELEPHONE:  (604)  660‐4700 BC TOLL FREE:  1‐800‐663‐1385 FACSIMILE:  (604)  660‐1102

…/2 

 BRIT ISH  COLUMBIA  

UTIL IT IES  COMMISSION      ORDER    NUMBER   G‐194‐08  

 IN THE MATTER OF 

the Utilities Commission Act, R.S.B.C. 1996, Chapter 473  

and  

Terasen Gas Inc. and Terasen Gas (Vancouver Island) Inc. and Terasen Gas (Whistler) Inc. 

2008 Resource Plan  

BEFORE:  A.W.K. Anderson, Commissioner     A.A. Rhodes, Commissioner   December 15, 2008   

O  R  D  E  R  

WHEREAS:  A. On June 27, 2008, Terasen Gas Inc., Terasen Gas (Vancouver Island) Inc. and Terasen Gas (Whistler) Inc. 

(collectively “Terasen” or “the Companies”) jointly filed a consolidated 2008 Resource Plan (“Resource Plan”) for acceptance by the British Columbia Utilities Commission (“Commission”) in accordance with Section 44.1 of the Utilities Commission Act; and 

 B. On May 28, 2008, Terasen Gas Inc. and Terasen Gas (Vancouver Island) Inc. (collectively “TGI and TGVI”) filed 

an Energy Efficiency and Conservation Programs Application (“EEC Application”); and 

 C. The Resource Plan includes five‐year capital plans and statements of facilities expansion, although the 

Companies note that they are not requesting approval of these capital plans; and 

 D. By Order G‐120‐08 the Commission established  a written proceeding  to review the Resource Plan; and 

 

E. The Rental Owners and Managers Society of BC, British Columbia Hydro and Power Authority (“BC Hydro”), the Ministry of Energy Mines and Petroleum Resources (“MEMPR”), and the British Columbia Old Age Pensioners’ Organization et. al. (“BCOAPO”) registered as Intervenors in the proceeding; and  

 

 

2 

…/3 

 BRIT ISH  COLUMBIA  

UTIL IT IES  COMMISSION      ORDER    NUMBER   G‐194‐08  

F. In a letter dated September 9, 2008, BC Hydro submitted that the fuel switching expenditures proposed by TGI and TGVI in the EEC Application are not in the public interest and requested Commission determinations that issues related to the EEC Application would be dealt with exclusively in the EEC Application and that a decision on the Resource Plan would be withheld until the Commission had properly considered the EEC Application; and  

 G. In a letter dated September 11, 2008, BCOAPO stated that it shared the concerns of BC Hydro and requested 

that the regulatory process for the Resource Plan be delayed until after the Commission’s decision with respect to the EEC Application was released; and 

 H. In a letter dated September 12, 2008, Terasen submitted that the Companies supported a Commission 

direction confirming that EEC‐related issues, including the issue of fuel switching, would be dealt with exclusively in the EEC proceeding.  The Companies further submitted that such a direction would be adequate to ensure the EEC Application and the Resource Plan would be reviewed efficiently and fairly and that there was no basis to delay the regulatory timetable established for the Resource Plan; and  

 I. By letter L‐45‐08 dated September 26, 2008, the Commission directed that all issues related to the EEC 

Application, including fuel switching, would be dealt with exclusively in the EEC proceeding and declined to make any adjustment to the regulatory timetable for the 2008 Resource Plan; and 

 J. On September 30, 2008, Terasen responded to Information Requests from the Commission, BC Hydro and 

BCOAPO; and 

 K. On October 7, 2008, Terasen filed its final submissions regarding the Resource Plan; and 

 L. BC Hydro and BCOAPO filed their final submissions on October 14, 2008 and October 16, 2008 respectively; 

and  

 M. On October 24, 2008 Terasen filed its reply submissions; and 

 N. The Commission Panel determines that acceptance of the 2008 Resource Plan for filing is in the public 

interest, subject to the comments in the Reasons for Decision attached as Appendix A to this Order. 

    

3 

Orders/G‐194‐08_TGVI‐TGW‐2008 Resource Plan‐Reasons for Decisions 

 BRIT ISH  COLUMBIA  

UTIL IT IES  COMMISSION      ORDER    NUMBER   G‐194‐08  

NOW THEREFORE the Commission Panel orders that the Resource Plan is accepted for filing by the Commission subject to the comments in the Reasons for Decision attached as Appendix A to this Order.   DATED at the City of Vancouver, in the Province of British Columbia, this          15th           day of December 2008.    BY ORDER    Original signed by:    A.A. Rhodes   Commissioner Attachment      

 APPENDIX A 

to Order G‐194‐08 Page 1 of 3  

  

Terasen Gas Inc. and Terasen Gas (Vancouver Island) Inc. and Terasen Gas (Whistler) Inc. 

2008 Resource Plan   

REASONS FOR DECISION  

On June 27, 2008, Terasen Gas Inc., Terasen Gas (Vancouver Island) Inc., and Terasen Gas (Whistler) Inc. (collectively “Terasen”) filed their consolidated 2008 Resource Plan (“Resource Plan”) with the British Columbia Utilities Commission (the “Commission”).  Terasen’s Resource Plan includes five‐year capital plans and statements of facilities expansion, but does not include a request for approval of these capital plans.  Rather, Terasen will file separate applications for Certificates of Public Convenience and Necessity, if required, for any of those projects consistent with the Commission’s guidelines.  The Action Plan identifies seven action items (Exhibit B‐1, section 9).  Only one of those action items, “Implement the new EEC program and continue research and planning for future EEC programming”, requires significant new funding, and that funding is the subject of a separate application as discussed below.  Terasen Gas Inc. and Terasen Gas (Vancouver Island) Inc. had previously filed, on May 28, 2008, their Energy Efficiency and Conservation Programs Application (the “EEC Application”).  On June 20, 2008 by Order G‐102‐08 the Commission established a preliminary regulatory timetable to review the EEC Application.  Subsequently, on September 18, 2008, by Order G‐130‐08, the Commission established a written hearing process (“EEC Proceeding”) and regulatory timetable to review the EEC Application.  Order G‐120‐08 established a written hearing and regulatory timetable to review the Resource Plan.  The Rental Owners and Managers Society of BC, British Columbia Hydro and Power Authority (“BC Hydro”), the Ministry of Energy Mines and Petroleum Resources, and the British Columbia Old Age Pensioners’ Organization et. al. (“BCOAPO”) registered as Intervenors in the proceeding.  On September 26, 2008, the Commission issued letter L‐45‐08 which stated that “…because the issues in the Resource Plan and the EEC Application are sufficiently distinct, it could approve the Resource Plan, except for EEC issues, subject to and in advance of a decision with respect to the EEC Application.” (Exhibit A‐3, p. 2)  The Commission Panel therefore directed that all issues related to the EEC Application, including fuel switching, are to be dealt with exclusively in the EEC proceeding, and declined any adjustment to the regulatory timetable for the 2008 Resource Plan.    Consistent with the timetable established by Order G‐120‐08, Terasen filed responses to information requests from the Commission, BC Hydro and BCOAPO on September 30, 2008.  Terasen filed its final submission on October 7, 2008.  Intervenors, specifically BCOAPO and BC Hydro, filed their final submissions on October 16, 2008 and October 14, 2008, respectively.  Terasen filed its reply submission on October 24, 2008.  BC Hydro’s submission notes that it had filed intervenor evidence in the EEC proceeding supporting its view that the portion of the EEC expenditure targeting fuel switching from electricity to natural gas is not in the public interest at this time.  BC Hydro also noted Commission letter L‐45‐08, which determined that Terasen’s asserted regional approach to Greenhouse Gas (“GHG”) emissions would be dealt with exclusively in the EEC proceeding.  BC Hydro took no position on the remainder of the Resource Plan.  

 APPENDIX A 

to Order G‐194‐08 Page 2 of 3  

BCOAPO noted that Terasen’s Resource Plan does not seek approval of any of the specific actions described in the Application.  By way of comment BCOAPO suggested that it is “…inadvisable for a fossil fuel provider to file a long‐term planning tool that ignores we now live in a country where aggressive conservation programs are or soon will be the norm and where non‐GHG emitting fuel sources are preferred going forward.”  BCOAPO stated that it shares BC Hydro’s concerns over Terasen’s reliance on a solely regional analysis when evaluating GHG emissions.  BCOAPO further submitted that since Terasen filed its Resource Plan in June 2008, global economic circumstances have changed to an extent sufficient to require that the growth scenarios presented in the Resource Plan be reconsidered.  BCOAPO submitted that, as opposed to the Reference Case presented in the Terasen Resource Plan, its “Low Growth” scenario is now a more appropriate reference case.   In addition, BCOAPO submitted that Terasen’s reference case forecast projects an average annual growth rate of 0.7 percent due largely to increased population and economic growth, but that in response to information requests, Terasen indicated it has assumed population growth of 1.03 percent and customer growth that is 25 percent of population growth, which implies that population growth is responsible for an average annual increase of 0.258 percent.   BCOAPO submitted that “…this discrepancy, combined with a likely low economic growth scenario and increased conservation efforts are cause to revisit the forecast projections and methodology.” (BCOAPO Final Submission, p. 5)   BCOAPO also expressed concerns about the ability of the regional gas transmission systems in the Pacific Northwest to meet peak day demand, and commented that the Regional Infrastructure Conclusions and Recommendations do not appear to address the issue, should it arise before “the longer term”.  Finally, BCOAPO expressed concerns about Terasen’s Design Day Demand Methodology and, in particular, about the R‐squared statistics reported for each of the separate regression equations and Terasen’s multicollinear equation.  BCOAPO submits that Terasen appears to have submitted “unadjusted R‐squares” and requested that Terasen submit the adjusted R‐squared statistics.  BCOAPO also submitted that Terasen should be required to provide the variances of the parameter estimates and review the statistical methodology prior to filing its next resource plans.  In its Reply Submission, Terasen stated that the issues raised by BC Hydro are matters that must be addressed in the context of Terasen’s EEC Application, and will be addressed there.  Regarding the BCOAPO comments, Terasen submitted in its Reply Submissions that it has examined GHG emissions from a provincial policy perspective as well as a regional perspective and that both of these perspectives are consistent and necessary.  Terasen further argued that it is not a foregone conclusion that the low growth scenario for forecast gas demand is the most appropriate over the long term, and stated that it will continue to review and update its long‐range forecast as new information becomes available “…primarily within the timeframes of its annual planning cycles.”  Terasen further submitted that Action Plan items within the Resource Plan address the issue of regional infrastructure capacity and identify specific solutions to alleviate the problem.  Finally, Terasen submitted that it did use adjusted R‐squared values, and that its current methodology is a reasonable way to estimate future design day demand.    

 APPENDIX A 

to Order G‐194‐08 Page 2 of 3  

   Commission Panel Conclusions  Since Terasen is not requesting approval of any specific actions in its resource plan, it needs only to be accepted under section 44. 1 of the amended Utilities Commission Act RSBC 1996 c.473 (“UCA”).  Section 44.1(2)(b) establishes that a long‐term resource plan must include “(b) a plan of how the public utility intends to reduce the demand referred to in paragraph (a) by taking cost‐effective demand‐side measures.”  The Resource Plan addresses that requirement of the UCA in section 4, in large measure by reference to the EEC Application, which has been ordered to be heard separately.   With regard to the issues related to fuel switching and GHG emissions, both these issues have been made part of the EEC Application and will be considered then.  The forecasting issue raised by BCOAPO is not significant now because there are no actions required by the reference case forecast presented by Terasen, and a forecast lower than the reference case implies more time before system reinforcements are required.  Finally Terasen’s design day forecast methodology has not been demonstrated to be incorrect in this proceeding nor has a superior method been proposed and, consequently, the Commission Panel is not prepared to direct any changes to it.  However, if BCOAPO continues to have concerns about its accuracy, the Commission Panel is of the view that intervenors should be allowed the opportunity to raise the issue in the next Resource Plan filing or any other application where it is a factor, and would encourage them to submit evidence advocating an alternative approach they feel would be more appropriate. 

 Section 44.1(7) of the UCA states that the Commission may accept or reject a part of the public utility’s plan.  Because the EEC issues are to be dealt with in the proceeding to review Terasen’s EEC Application, the Commission Panel accepts the Resource Plan for filing, except for Section 4 and those other parts of the Resource Plan that relate to the issue of Energy Efficiency and Conservation, including fuel switching and GHG emissions.   A determination on those remaining issues will be made following the EEC Proceeding. 

IN THE MATTER OF

TERASEN GAS INC. TERASEN GAS (VANCOUVER ISLAND) INC.

AND

ENERGY EFFICIENCY AND CONSERVATION APPLICATION

DECISION

April 16, 2009

Before:

A.W.K. Anderson, Commissioner A.A. Rhodes, Commissioner

TABLE OF CONTENTS 

 

  Page No. 

1.0 BACKGROUND AND REGULATORY PROCESS  1

1.1 The Application  1

1.2 Legal and Regulatory  3

1.2.1 The Utilities Commission Act  3

1.2.2 The Long Term Resource Plan  4

1.2.3 ‘Cost effectiveness’ and the Demand Side Measures (DSM) Regulation  4

1.2.4 BC Government’s Energy Objectives  5

2.0 TERASEN’S PROPOSED EEC EXPENDITURES  6

2.1 Residential and Commercial Energy Efficiency  7

2.1.1 Residential Energy Efficiency  8

2.1.1.1 New Construction  9

2.1.1.2 Retrofit  9

2.1.1.3 Commercial Energy Efficiency  10

2.1.1.4 New Construction  11

2.1.2.5 Retrofit  12

2.2 Residential Fuel Switching  14

2.3 Conservation Education and Outreach  18

2.4 Joint Initiatives, Trade Relations, 2009 CPR, and Innovative Technologies, NGV and Measurement  21

2.4.1 Joint Initiatives  21

2.4.1.1 Audits  22

2.4.1.2 Affordable Housing  22

2.4.1.3 Labeling  22

2.4.1.4 Community Action  22

2.4.2 Trade Relations  24

2.4.3 Innovative Technologies, NGV and Measurement  25

TABLE OF CONTENTS 

 

  Page No. 

 2.5 Conservation Potential Review Update  27

2.6 The Industrial Sector  28

3.0 ASSESSMENT CRITERIA AND ACCOUNTABILITY  31

3.1 Portfolio Approach  31

3.2 Free Riders  35

3.3 Attribution to Regulatory Changes  37

3.4 Carbon Pricing  40

3.5 Accountability Mechanisms  41

4.0 CAPITALISATION OF INCREMENTAL EEC EXPENDITURES  43

5.0 AMORTISATION OF EEC EXPENDITURES  45

 

ORDER NO. G‐36‐09 

APPENDIX 1 – LIST OF EXHIBITS 

 

 

  

1.0  BACKGROUND AND REGULATORY PROCESS 

 

1.1  The Application 

 

On May 28, 2008 Terasen Gas Inc. (“TGI”) and Terasen Gas (Vancouver Island) Inc. (“TGVI”) 

(collectively “Terasen”) filed its Energy Efficiency and Conservation (“EEC”) Programs Application 

(“Application”) with the British Columbia Utilities Commission (“the Commission”). 

 

In the Application, Terasen requested an order or orders approving the following:  

 

• Increases of EEC expenditures in the period 2008‐2010 to $46.944 million for TGI and $9.667 million for TGVI, a combined total of $56.6 million; 

• Capitalisation of incremental EEC expenditures as a regulatory asset deferral account on an after tax basis and amortisation of the account over 20 years; 

• An increase in the amortisation period to 20 years for incentive amounts that are added to deferral accounts for 2008 and 2009 as part of the 2008‐2009 extension of the 2004‐2007 TGI PBR Settlement Agreement (“TGI PBR Extended Settlement”) approved by Order G‐33‐07 and the 2008‐2009 extension of the 2006‐2007 TGVI Revenue Requirements Settlement Agreement (“TGVI RR Extended Settlement”) approved by Order G‐34‐07; 

• Changes to the benefit‐cost analysis undertaken to evaluate EEC measures as outlined below: 

o Implementation of a portfolio approach to benefit‐cost analysis such that the Total Resource Cost (“TRC”) test for all programs combined must return an overall combined result of one or more;  

o Elimination of the requirement to include free‐riders in benefit‐cost tests;  

o Inclusion of the benefits of savings associated with implementation of a regulation as a result of EEC programs aimed at preparing the marketplace for the introduction of regulation of minimum efficiency levels in equipment, buildings or energy systems 

o Inclusion of the impact of carbon‐pricing as one of the inputs to the benefit‐cost tests; 

2   

• A requirement that Terasen submit annually to the Commission, by the end of the first quarter following year‐end, for each year of the funding period, a report on all EEC initiatives and activities, expenditures and results for TGI and TGVI. 

 

The Commission directed that the Application would follow a written hearing process after hearing 

submissions from intervenors and interested parties. 

 

Intervenors registered for the hearing were: 

 

• British Columbia Hydro and Power Authority (“BC Hydro”),  

• British Columbia Old Age Pensioners’ Organization et. al. (“BCOAPO”),  

• B.C. Sustainable Energy Association and the Sierra Club of Canada (British Columbia Chapter) (collectively, “BCSEA‐SCBC”),  

• The Ministry of Energy, Mines and Petroleum Resources (“MEMPR”),  

• The Rental Owners and Managers Society of B.C. (“ROMS”),  

• FortisBC Inc.,  

• Pacific Northern Gas Ltd. (“PNG”),  

• The Commercial Energy Consumers Association of BC (“CEC”) and  

• Direct Energy Marketing Limited  

 

In addition to parties registering as intervenors, numerous letters of comment were received. 

 

Two rounds of Information Requests were conducted. 

 

Intervenors BC Hydro and BCSEA‐SCBC also filed evidence. 

 

The process was complete on December 5, 2008 with the filing of Terasen’s reply submission. 

 

3   

1.2  Legal and Regulatory 

 

1.2.1  The Utilities Commission Act 

 

The Application is made pursuant to Section 44.2 of the Act, which states, in part: 

 

“(1) A public utility may file with the commission an expenditure schedule containing one or more of the following: 

(a) a statement of the expenditures on demand‐side measures the public utility has made or anticipates making during the period addressed by the schedule;…” 

 and:  

“(3) After reviewing an expenditure schedule submitted under subsection (1), the commission, subject to subsections (5) and (6), must 

(a) accept the schedule, if the commission considers that making the expenditures referred to in the schedule would be in the public interest, or 

(b) reject the schedule. 

(4) The commission may accept or reject, under subsection (3), a part of a schedule. 

(5) In considering whether to accept an expenditure schedule, the commission must consider 

(a) the government's energy objectives, 

(b) the most recent long‐term resource plan filed by the public utility under section 44.1, if any, 

(c) whether the schedule is consistent with the requirements under section 64.01 or 64.02, if applicable, 

(d) if the schedule includes expenditures on demand‐side measures, whether the demand‐side measures are cost‐effective within the meaning prescribed by regulation, if any, and 

(e) the interests of persons in British Columbia who receive or may receive service from the public utility. 

(6)  If the commission considers that an expenditure in an expenditure schedule was determined to be in the public interest in the course of determining that a long‐term resource plan was in the public interest under section 44.1 (6), 

4   

(a) subsection (5) of this section does not apply with respect to that expenditure, and 

(b) the commission must accept under subsection (3) the expenditure in the expenditure schedule.” 

 

1.2.2  The Long Term Resource Plan  

 

The Commission Panel notes that, with respect to subsection 44.2 (5) (b) and subsection 44.2(6), 

Terasen filed its consolidated 2008 Resource Plan (on behalf of TGI, TGVI and Terasen Gas 

(Whistler) Inc.) on June 27, 2008, which was accepted as described in Order G‐194‐08 and its 

accompanying Reasons.    As noted in the Reasons, the Commission Panel specifically excluded any 

consideration or determination with respect to whether the EEC expenditures included in the 

instant Application were in the public interest.  Accordingly, the Commission Panel considers that 

subsection 5 of s. 44.2 is applicable to the Application, whereas subsection 44.2(6) is not.  

 

1.2.3  ‘Cost effectiveness’ and the Demand Side Measures (DSM) Regulation 

 

Subsection 44.2 (5)(d) requires the Commission to consider whether the EEC expenditures are “. . . 

cost‐effective within the meaning prescribed by regulation, if any, . . .”. 

 

On November 7, 2008, the Government issued Ministerial Order M271/2008 which attached B.C. 

Reg. 326/2008 ‐ Demand‐Side Measures Regulation.  Section 3 of the DSM Regulation deals with 

the “adequacy” of a demand‐side measures “plan portfolio” and section 4 of the DSM Regulation 

sets forth certain requirements with respect to the determination of whether such expenditures 

are “cost effective”.  Section 2 of the DSM Regulation provides that the regulation applies only to 

‘the authority’ (BC Hydro) until June 1, 2009, at which time the regulation will become more 

generally applicable.   Accordingly the requirements of sections 3 and 4 are not applicable to 

Terasen’s current EEC Application. 

 

5   

1.2.4  BC Government’s Energy Objectives 

 

 

Subsection 44.2 (5)(a) of the Act requires the Commission to consider the “government’s energy 

objectives” in considering whether to accept an expenditure schedule.  The “government’s energy 

objectives” are defined in section 1 of the Act as follows: 

 

“(a) to encourage public utilities to reduce greenhouse gas emissions; 

(b) to encourage public utilities to take demand‐side measures; 

(c) to encourage public utilities to produce, generate and acquire electricity from clean or renewable sources; 

(d) to encourage public utilities to develop adequate energy transmission infrastructure and capacity in the time required to serve persons who receive or may receive service from the public utility; 

(e) to encourage public utilities to use innovative energy technologies 

(i)  that facilitate electricity self‐sufficiency or the fulfillment of their long‐term transmission requirements, or 

(ii)  that support energy conservation or efficiency or the use of clean or renewable sources of energy; 

(f) to encourage public utilities to take prescribed actions in support of any other goals prescribed by regulation…” 

 

 

 

6   

2.0  TERASEN’S PROPOSED EEC EXPENDITURES 

 

Terasen is applying for approval of an increase in allowed expenditures for EEC activity for TGI and 

TGVI to a total of approximately $56.6 million over the three year Program Period 2008 to 2010, an 

increment of $48.062 million over currently approved DSM spending for the two utilities. 

(Exhibit B‐1, p. 8)   

 

The proposed EEC Expenditures, by Program Area, by Utility, are set out in the table below. 

 Table 1 

 ($000) 

Spend by Program Area 2008 ‐2010  TGI  TGVI  Total  

Residential Energy Efficiency  8,552 734  9,286

Commercial Energy Efficiency  19,592 2,199  21,791

Residential Fuel Switching  1,332 2,367  3,699

Conservation Education and Outreach  11,068 2,767  13,835

Joint Initiatives  2,400 600  3,000

Trade Relations  1,200 300  1,500

Conservation Potential Review  400 100  500

Innovative Technologies, NGV and 

Measurement 

2,400 600  3,000

Total  46,944 9,667  56,611

  (Source:  Exhibit B‐1, p. 9)  

 

 Terasen states that it is most efficient for the Commission to approve the overall expenditure level, 

by utility, for the funding period rather than by approving the funding by program area or by 

individual program initiative.   Terasen submits that this approach will allow it to respond quickly to 

changes within initiatives and to new opportunities that might arise, and will reduce the 

administrative burden related to EEC activity. (Exhibit B‐1, pp. 50‐51)  

7   

 

Terasen also submits that the energy savings from the EEC expenditures will result in savings with a 

present value of almost 10 million gigajoules (“GJs”) over the lives of the various measures 

proposed, while fuel switching activity is estimated to result in approximately 2.3 million GJs of 

additional load.  The anticipated present value of net energy savings is approximately 7.7 million 

GJs, not including potential savings arising from Conservation Education and Outreach, Joint 

Initiatives or Innovative Technologies, NGV and Measurement program areas. (Exhibit B‐1, p. 10)  

Terasen further states that DSM expenditures at current levels would result in cumulative annual 

savings of 1.3 million (nominal, rather than present value) GJs by 2016, whereas the proposed 

expenditures would result in cumulative annual savings of approximately 6.4 million nominal GJs in 

the same time period. (Exhibit B‐1, p. 11) 

 

2.1  Residential and Commercial Energy Efficiency  

 

Terasen developed its budget estimates for Residential Energy Efficiency, Commercial Energy 

Efficiency and Residential Fuel Switching based on work done in 2006 in its Conservation Potential 

Review (“CPR”).  Those estimates were refined by Habart and Associates Consulting Inc. (“Habart”) 

as described in Habart’s September 2007 Report (“Habart Report”) provided in Appendix 9 of the 

Application. (Exhibit B‐1, p. 52)  The Habart Report concluded that total DSM funding of 

approximately $35 million over the three‐year period would be required. (Exhibit B‐1, Appendix 9, 

p. 23) 

 

Terasen states that “[t]he key finding of the CPR was the Achievable Potential” which is a measure 

of savings which could realistically be achieved within the study period. (Exhibit B‐1, p. 45)  The 

Achievable Potential from the CPR is outlined in the table below: 

 

8   

Table 2  

CPR Findings 

  (Exhibit B‐1, Table 4.1, p. 45)   

Terasen states that “[t]he strategies outlined in this Application, and the expenditures for which 

approval is being sought, are based to a significant degree on the findings of the CPR and the 

subsequent work undertaken with Habart.”  (Exhibit B‐1, p. E‐3) 

 

In discussing estimation of new dwelling heating loads, the 2006 CPR states that: “[d]iscussions 

with provincial government staff indicated that a number of changes to residential buildings are 

under consideration that could affect the thermal performance of British Columbia’s new housing 

over the study period.”  The changes being considered include targets for new construction, 

including residential buildings and all commercial buildings (including apartments) and strategies to 

achieve improved thermal performance in related residential equipment and products, including 

furnaces, fireplaces, and windows.  (Exhibit B‐1, Appendix 1, p. 33) 

 

2.1.1  Residential Energy Efficiency  

 

Terasen proposes spending $9.286 million on Residential Energy Efficiency for both TGI and TGVI 

over the Program Period (Exhibit B‐1, p. 55, Table 6.2b).  The Residential Energy Efficiency program 

area includes both new construction and retrofit initiatives.  

 

9   

2.1.1.1  New Construction 

 

For new construction, Terasen is proposing EnerChoice Fireplace and Energy Star Appliance 

initiatives.  The EnerChoice Fireplace program will provide an incentive to customers who purchase 

and install an EnerChoice rated fireplace, insert or free‐standing stove. The Energy Star Appliance 

program provides incentives for customers who use natural gas for domestic hot water (“DHW”) 

heating to install Energy Star clothes washers and/or dishwashers.  (Exhibit B‐1, p. 59) 

 

Terasen states “[t]he key decision makers in this market for the [new construction] programs . . . 

are builders and developers who build single family homes and row‐houses” and  “. . .  new 

construction EEC portfolio in the residential market will include programs that encourage 

customers, whether they be individuals building a new home, or builders and developers, to install 

energy efficient appliances.”  (Exhibit B‐1, p. 58) (emphasis in original) 

 

2.1.1.2  Retrofit 

 

For the residential retrofit market Terasen is proposing an Energy Star Heating System Upgrade 

program that will reprise earlier versions of this program, and will provide customers who install an 

Energy Star heating system a credit on their Terasen bill for gas service.  Terasen’s Application is 

based on funding for incentives for gas furnace upgrades in single family dwellings (“SFDs”) and 

duplexes in the Terasen service territory.  Terasen estimates upgrades to 5.3 percent of the stock of 

pre‐1976 SFDs and duplexes or 8,180 furnace upgrades to the end of 2009.  Terasen notes that due 

to expected new Federal government regulations requiring all furnaces sold in Canada to meet a 

minimum standard of 90 percent efficiency after December 31, 2009, this program will conclude 

prior to that date. (Exhibit B‐1, pp. 59‐60)   

 

Terasen is also proposing EnerChoice Fireplace and Energy Star Appliance programs for the retrofit 

market as for the new construction market.  The Hearth, Patio & Barbeque Association of Canada 

will provide assistance in promotional and educational aspects of the EnerChoice Fireplace 

program. (Exhibit B‐1, p. 60) 

10   

 

The residential sector expenditures proposed by Terasen, by utility and program area are as 

follows: 

Table 3 

TGI and TGVI Energy Efficiency  ($000)  2008 2009 2010  Total

TGI  New Construction  411 566 1,056  2,033

  Retrofit  2,495 2,658 1,367  6,520

  Sub total, TGI  2,906 3,224 2,423  8,553

TGVI  New Construction  130 156 232  518

  Retrofit  53 66 97  216

  Sub total, TGVI  183 222  329  734

  Total  3,089 3,446 2,752  9,287

Source: BCUC IR No. 1 Attach 56.2A 

 

 

2.1.1.3  Commercial Energy Efficiency  

 

Terasen is proposing to spend $21.7 million on commercial sector new construction and retrofit 

programs (Exhibit B‐1, p. 60).  The expenditure proposals were based on refinements of the 

following initial recommendations from the Habart report:  

 

11   

Table 4 

TGI and TGVI Commercial Programs  

Spending 2008‐2010 ($000) 

  TGI  TGVI 

New Construction     

  Efficient New Construction  5,297  727 

  Boilers   1,928  224 

  Water Heating  1,118  103 

  Subtotal ‐ New Construction 8,343  1,055 

Retrofit       

  Boilers   7,395  1,074 

  Building Recommissioning  3,095  354 

  Next Generation Building Automation Systems  968  95 

  Demand Control Ventilation  1,795  ‐ 

  High Efficiency Rooftop Units  239  17 

  Water Heat  2,032  254 

  Subtotal ‐ Retrofit 15,524  1,794 

Total Commercial Energy Efficiency  23,867  2,849 

  Source: Exhibit B‐2, Attachment 56 2A TGVI and 56 2A TGI 

 

2.1.1.4  New Construction 

 

The commercial new construction program is aimed at all new construction “…which might use 

natural gas space and water heating.”  Terasen states that “…the immediate opportunities are 

likely to be Multifamily Dwellings (“MFDs”) and Commercial office space” and may also include 

some institutional buildings. (Exhibit B‐1, p. 61)   Terasen lists some potential areas for activity in 

the commercial new construction sector, and notes that program design in this sector is complex, 

so the program activities listed in the Application are merely summaries.   

 

12   

Terasen states “[t]he key decision makers in this market are owners including: governments; 

builders/developers; architects; engineers; interior designers; mechanical consultants; and 

contractors.”  (Exhibit B‐1, p. 61) 

 

The new construction energy efficiency program areas include initiatives aimed at: 

 

• Efficient New Construction Design and High Insulation Technology for windows; 

• Condensing and near condensing boilers; and  

• Instantaneous and condensing DHW heaters and drain water heat recovery. 

  (Exhibit B‐1, Table 6.3.2, p. 61) 

 

2.1.2.5  Retrofit 

 

Terasen’s commercial retrofit program is aimed at all commercial and industrial buildings with 

existing natural gas space and water heating equipment.  Terasen again notes that, due to the 

complexity of programs in this sector, it has merely summarized areas of program activity and 

states “[m]ore detailed program development work must be completed by [Terasen] in conjunction 

with industry groups before these programs are rolled out.” (Exhibit B‐1, p. 62) 

Commercial retrofit energy efficiency program area activity includes initiatives for: 

 

• Condensing and near condensing boilers 

• Building Recommissioning 

• Next Generation Building Automation Systems (“BAS”) 

• High Efficiency (“HE”) Rooftop Units 

• Instantaneous and condensing DHW boilers and heaters 

• For TGI only, Terasen is proposing to add: demand control ventilation  for large and medium commercial buildings and drainwater heat recovery. 

(Exhibit B‐1, p. 62, Table 6.3.2a) 

13   

 

Terasen states that commercial sector programs are intended to offer qualified customers a menu 

of programs from which to choose and that Terasen staff will work with participants in selecting 

the most appropriate program and/or component.  (Exhibit B‐1, p. 63) 

 

Intervenor Positions 

 

BCOAPO takes issue with the relative allocation of spending as between proposed residential and 

commercial customer groups.  BCOAPO notes that residential customers make up 90 percent of 

Terasen’s total customers and 38 percent of its total volume, whereas commercial customers 

represent only 9.7 percent of its customer base and 26 percent of its total volume. (BCOAPO 

Argument, p. 12) 

 

Commission Determination 

 

The Commission Panel notes BCOAPO’s comments as well as the CPR evidence indicating that some 

70 percent of the Achievable Potential savings are associated with the residential sector. Terasen 

has included residential market MFDs in its Commercial EE program, which, in the view of the 

Commission Panel, may also have significant potential for low income housing initiatives. Terasen 

indicates that it will re‐direct funding amongst programs based on customer response, thus 

enabling funding balancing between Residential and Commercial programs as appropriate.   

   

The Commission Panel finds the design of Terasen’s Residential and Commercial EE programs to be 

reasonable, flexible and in the public interest, and accepts the expenditure proposals for these 

program areas.  

 

14   

2.2  Residential Fuel Switching 

 

Reduction in Greenhouse Gas (“GHG”) emissions is advanced by Terasen as a benefit in support of 

residential fuel switching for TGI.  The stated premise is that the substitution of natural gas for 

electricity will reduce overall GHG emissions in the short term, by increasing the amount of 

electricity available to BC Hydro to meet domestic load, thereby reducing its dependence on 

imported power or, alternatively, allowing it to increase exports of clean power, thus enabling a 

reduction in the regional use of gas or coal‐fired power.  Terasen submits, over the longer term, to 

the extent BC Hydro is able to meet its load requirements, excess clean generation could be 

exported, displacing the use of gas and/or coal‐fired generation in the region (Western 

Interconnection).  (Exhibit B‐1, p. 63; Terasen Reply, p. 5) 

 

Terasen states that “[t]he primary objective of the fuel‐switching offers is to promote the most 

optimal balance in energy share between electricity and natural gas, preserving BC Hydro’s 

generation and transmission systems for its [sic] highest value – in running lights, computers and 

other technology.” (Exhibit B‐1, p. 64)  

 

Terasen proposes to spend $3.7 million in the residential fuel switching program area.   It is 

proposing that only new construction fuel switching programs be offered in the TGI service area 

but that both new construction and retrofit fuel switching programs be offered in the TGVI service 

area. 

 

Terasen proposes to spend the following amounts on fuel switching programs annually, over the 

Funding Period. 

 

15   

Table 5 

 

Residential Fuel Switching Programs 

Program  Initiatives  TGI  TGVI 

New Construction     

Natural Gas Water Heating  NG DHW  319  693

NG Range  1,013  50

Sub Total 1,332  743

   

 

Natural Gas Appliances 

 

     

Retrofits  NG Dryer    38

  Natural Gas Appliances  FS Range  ‐  247

    FS Dryer  ‐  247

  Furnace Fuel Substitution  Furnace  ‐  766

  Fireplace Fuel Substitution  EnerChoice Fireplace  ‐  326

  Sub‐total   1624

  Totals 1332  2367

  Source:  Exhibit B‐2, Attachments 56.2A 2 (TGI) and 56.2A 4 TGVI 

 

New Construction 

 

All new construction expenditures involve fuel switching from electricity.  Only the Retrofit 

programs, which are limited to Vancouver Island, involve potential fuel switching from propane, oil 

or wood in addition to electricity.  Terasen states:  “[i]t is very challenging to separate out proposed 

expenditures for fuel switching from electricity to natural gas from vs. [sic] proposed expenditures 

for fuel switching from non‐electric sources to natural gas, as there are a number of potential 

energy sources for the proposed TGVI residential retrofit program, and …[it] cannot predict the 

proportion of participants switching from each energy source.” (Exhibit B‐5, BC Hydro 1.1.1) 

16   

Terasen proposes fuel substitution incentive programs to encourage the use of natural gas in new 

construction projects for installation of natural gas domestic hot water heaters in the TGVI service 

area and to install a natural gas range and/or dryer in both the TGI and TGVI service areas. 

(Exhibit B‐1, p. 64)  

 

Retrofit 

 

Incentive funding for fuel substitution retrofits is only contemplated for TGVI, as many households 

in its service territory still use wood, propane or fuel oil for space heating and fireplaces.   

 

The proposed programs include incentive payments for: 

 

• Switching to natural gas for space heating and for installing Energy Star equipment.  Terasen states that “the current regulatory regime for TGVI does not allow Terasen to offer customers who switch to natural gas an incentive to install Energy Star equipment.”  (Terasen proposes that it be able to offer both, but also advises that it would restrict the incentive to furnaces and boilers rated Energy Star.); 

• Installation of an EnerChoice‐rated fireplace, insert or free‐standing stove; and 

• Replacement of existing electric or propane ranges and dryers with gas appliances. 

  (Exhibit B‐1, p. 65) 

 

Intervenor Positions 

 

BCOAPO strongly opposes the inclusion of any expenditures associated with fuel switching away 

from electricity to natural gas in Terasen’s EEC portfolio.  BCOAPO argues that there is no evidence 

as to an “optimal balance” as between electricity and natural gas and suggests that a movement 

away from (clean) electricity to a fossil fuel would not be part of such optimal balance. (BCOAPO 

Argument, p. 10) 

 

17   

BC Hydro filed the evidence of Randy Reimann, P. Eng., its manager of Resource Planning, wherein 

he contradicted Terasen’s assertion that fuel switching away from electricity to natural gas would 

reduce the need for BC Hydro to import electricity from other jurisdictions which rely on coal or 

natural gas for generation.  Mr. Reimann stated:  “[t]here is no medium to long term linkage 

between fuel switching from electricity to natural gas and a change in BC Hydro’s need for 

importing electric energy or ability to export such energy.”  (Exhibit C2‐6, Direct Testimony of 

Randy Reimann, p. 2, Q.7) 

 

BC Hydro also filed the evidence of Patrice Rother, its manager of Environmental Strategy in the 

Safety, Health and Environmental group.  Ms. Rother reviewed recent GHG‐related legislative and 

policy developments including the B.C. Greenhouse Gas Reduction Targets Act (“GGRTA”), the B.C. 

Climate Action Plan and the joinder of British Columbia into the Western Climate Initiative and 

highlighted a number of areas of uncertainty surrounding how the WCI GHG trading scheme will 

align with the GGRTA legislated targets and other Chinook Action Plan action items on a regional 

basis. (Exhibit C2‐6, Direct Testimony of Patrice Rother pp. 2‐3, Q. 8, 11) 

 

Commission Determination 

 

While the Commission Panel notes the comments of Terasen regarding potential GHG benefits of 

fuel switching, particularly away from fossil fuels with a higher carbon content than natural gas, the 

Commission Panel is not convinced that expenditures on fuel switching and load building away 

from electricity can be properly considered in a portfolio of EEC programs at this time.  The 

Commission Panel agrees with the comments of the BCOAPO that the “optimal balance” as 

between natural gas and electricity has not been established.  The Commission Panel also finds that 

the efficiency of other energy sources over and above that of electricity has not been adequately 

established.   

 

The Commission Panel also notes that natural gas does have a GHG impact which is not present in 

clean domestic electricity and that one of the government’s energy objectives is “to encourage 

public utilities to reduce GHG emissions.” The Commission Panel accepts the evidence of 

18   

Ms. Rother that there is considerable uncertainty, at this time, surrounding how various 

government initiatives will align on a regional basis. The Commission Panel finds that Terasen has 

not provided sufficient evidence to persuade the Panel, on a balance of probabilities, that a 

regional approach should be adopted as a justification for EEC expenditures aimed at substituting 

natural gas as a fuel to replace electricity.   

 

The Commission Panel accepts EEC expenditures directed at fuel switching from fossil fuels with a 

higher carbon content than that of natural gas.  Expenditure programs specifically directed at 

encouraging fuel switching away from electricity are rejected, as are Incentive payments for 

appliances for which an Energy Star rating is not available.  However, expenditures are accepted for 

incentives to install Energy Star and EnerChoice equipment and appliances for customers who, at 

their own initiative, wish to switch to natural gas as the fuel of choice.  

 

2.3  Conservation Education and Outreach 

 

This proposal is in addition to program‐specific education and outreach funding, and relates to non‐

program‐specific activities, as set out below. 

 

• Terasen’s proposed budget for Conservation Education and Outreach (CEO) was developed in consultation with Wasserman + Partners Advertising (“Wasserman”).  Terasen proposes a total CEO expenditure of $13.835 million in the 2008 to 2010 period which is 24 percent of the total EEC proposed expenditures of $56.611 million. The Wasserman proposal states that the planned messaging will educate the public about Terasen’s EEC program and related activities.   

(Exhibit B‐1, Appendix 8) 

Terasen was requested to describe the specifics of the CEO programs and responded that these 

initiatives “. . . have not yet been fully developed, however, as outlined on page 65 of the 

Application, they are projected to include: 

 

19   

• Stakeholder industry group activities, such as first time homebuyers seminars 

• Public outreach by “Team Terasen” 

• Support for conservation education within the school system 

• Energy Forum 

• Conservation communications, as outlined in Appendix 8 in the Application.” 

  (Exhibit B‐2, BCUC 1.28.1) 

 

The entire proposed $13.835 expenditure for the CEO Program Area is taken by the Conservation 

communications initiative of the CEO Program.   $11.550 million or 83 percent of the $13.835 

million is allocated to Mass Media Advertising and Production over the three year expenditure 

period.  (Exhibit B‐1, Appendix 8) 

 

Terasen did not submit any details or expenditure estimates for the first four program initiatives 

described above.  

 

Terasen proposes to attribute the CEO expenditures in each year equally between the Residential 

and Commercial Energy Efficiency programs, with none of the CEO expenditures being attributed to 

other Program Areas such as Fuel Switching or Trade Relations.  (Exhibit B‐1, p. 54)  

   

Terasen states: “EEC expenditures will be efficient, with non‐incentive costs not exceeding 50% of 

the expenditure in a given year.”  (Exhibit B‐1, p. 47, #3)  Terasen does not provide any further 

evidence supporting the implication that, merely by not exceeding 50 percent of the total, non‐

incentive, expenditures, the balance represents efficiency in expenditures.   

 

Intervenor Positions 

 

BCOAPO submitted that “The Application’s education and outreach component is 

disproportionately large, and inappropriately treated as an asset to be amorti[s]ed over 20 years.”   

(BCOAPO Argument, p. 14) 

20   

 

BCSEA‐SCBC submitted the evidence of John J. Plunkett of Green Energy Economics Group, Inc.  The 

Commission Panel reviewed Mr. Plunkett’s qualifications and experience and accepts him as an 

expert with respect to the matters his testimony addresses in this Application. 

 

Mr. Plunkett proposes that the CEO should be reduced by 50 percent, and the amount by which the 

funding is reduced be redirected to the residential and commercial efficiency programs. 

Mr. Plunkett notes that while building a conservation ‘ethic’ in British Columbia is laudable, the 

primary purpose of the CEO expenditures should be to support the efficiency programs.  

(Exhibit C5‐5, pp. 18, 19)    

 

Commission Determination 

 

The Commission Panel finds that Terasen has not provided sufficient evidence to support either the 

$13.835 million total proposed EEC expenditures, or the allocation of some 84 percent of that 

amount to mass media advertising and production.  The Commission Panel notes that the 

Commercial component comprises some 70 percent of the total expenditures in the combined 

Residential and Commercial Energy Efficiency program areas, to which the CEO costs have been 

attributed equally. The Commission Panel also notes Terasen’s comments, quoted above, with 

respect to the key decision makers in both the new and retrofit commercial markets. The 

Commission Panel considers both these markets to be significantly more narrow and focused than 

markets which may warrant the use of mass media approaches to communication.   

 

The Commission Panel also notes that Terasen’s evidence did not include any discussion of bill 

stuffers or other communication methods. 

  

The Commission Panel agrees in part with Mr. Plunkett’s proposal, and considers that, while public 

education is an appropriate activity in support of the EEC objectives, the evidence is not sufficient 

to support either the full amount proposed or the allocation of the proposed CEO expenditures.  

The Commission panel does not agree with Mr. Plunkett’s suggestion that the funding reduction of 

21   

the CEO expenditures be redirected to the energy efficiency programs.  The Commission Panel 

finds the evidence sufficient to establish that there is a benefit to some CEO expenditures and 

accepts 50 percent, $6.918 million, as reasonable.  

 

Terasen is directed to review the CEO program with a view to: 

 

• altering the program to allocate funds away from the mass media campaign and to include other initiatives, with particular attention paid to conservation education within the school system and affordable housing initiatives; 

• addressing the apparent imbalance of the residential to commercial expenditure ratio, approximately 30:70, in comparison to the ratio of residential to commercial Achievable Potential GJ impact of approximately 77:23 (Exhibit B‐1, p. 45); 

• reconsidering the apparent lack of communication expenditures directed in a focused manner to the Commercial Energy Efficiency program,  

• reconsidering appropriate attribution of CEO costs to Program Areas and initiatives, and any related impact on Total Resource Cost calculations and rate impacts.  

 

2.4  Joint Initiatives, Trade Relations, 2009 CPR, and Innovative Technologies, NGV and 

Measurement 

 

2.4.1  Joint Initiatives 

 

Terasen is requesting that $1.0 million per year be approved for the development of Joint 

Initiatives as they arise.  Initiatives that Terasen states it will, or may pursue if the funding is 

approved, include: support for audits for a Provincial Home Retrofit Program, DSM for affordable 

housing, building labeling, and community action on energy efficiency. (Exhibit B‐1, pp. 66‐68) 

 

22   

2.4.1.1  Audits 

 

The “audit” joint initiative involves providing financial assistance to customers by paying for the 

cost of a pre or post upgrade audit, both of which are necessary for participation in the federal 

government’s “Eco‐Energy” program.  This initiative would support the provincial government’s 

expressed intention to implement a province‐wide home retrofit program, “LiveSmartBC”, to 

complement the federal government initiative.  The provincial program does not contemplate 

paying the cost of post‐retrofit audits, and Terasen sees an opportunity to provide full or partial 

funding to enable more of its customers to participate in the programs. (Exhibit B‐1, pp. 43, 67)   

 

2.4.1.2  Affordable Housing 

 

Terasen states that “[t]he Ministry of Energy Mines and Petroleum Resources has asked that the 

Terasen Utilities lead a working group on DSM for Affordable Housing, the goal of which is to find 

ways and means to deliver Energy Efficiency to the Affordable Housing sector in B.C. and that such 

group has been convened.  Terasen proposes to fund its participation in any resulting DSM 

incentive program from the Joint Initiatives Program allocation. (Exhibit B‐1, p. 67) 

 

2.4.1.3  Labeling 

 

A further joint initiative which Terasen proposes is to co‐fund a pilot project to label homes and 

buildings with an energy consumption/efficiency rating.  Terasen states that this will assist in 

informing the public and promoting energy conservation and will enable comparisons as between 

different gas‐heated homes. 

 

2.4.1.4  Community Action 

 

Terasen also proposes to make a financial contribution to the pool of funds to which municipalities 

can apply under the “Community Action on Energy Efficiency” initiative for financial and research 

support to advance energy conservation and efficiency in their areas, through policy action and 

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public outreach.  (Exhibit B‐1, p. 68; The BC Energy Plan 2007‐ Policy Action #9) 

 

Intervenor Positions 

 

BC Hydro supports the Joint Initiatives funding requested.  (BC Hydro Argument, p. 5)   

 

BCOAPO argues that this area of the EEC is “drastically under‐funded if any meaningful [low‐

income energy efficiency program (“LIEEP”)…is to be developed.” (BCOAPO Argument, p. 7)   

 

BCSEA‐SCBC argues: “. . . while the four initiatives under the Join Initiatives program area may be 

worthwhile” they do not satisfactorily address the need for better integration of Terasen’s 

programs with electrical DSM programs as identified by the BCSEA‐SCBC expert, Mr. Plunkett. 

(BCSEA‐SCBC Argument, pp. 12‐13)  Mr. Plunkett recommends that Terasen should be directed to 

redesign programs by streamlining them and better integrating them with electric efficiency 

programs. (Exhibit C5‐5, p. 5)   

 

Commission Determination 

 

The Commission Panel accepts the expenditures requested for the Joint Initiatives Program area. 

The Commission Panel notes the comments of the BCOAPO and agrees that the Affordable Housing 

Initiative appears to be under‐funded, particularly given that no portion of the requested global 

amount for Joint Initiatives is specifically dedicated to Affordable Housing.  The Commission Panel 

also notes that the DSM Regulation which does not yet, but will, apply to Terasen requires that a 

public utility’s plan portfolio include “a demand‐side measure intended specifically to assist 

residents of low‐income households to reduce their energy consumption”.  The Commission Panel 

therefore directs Terasen to proceed with its Joint Initiative relating to Affordable Housing and 

encourages Terasen to consider re‐allocating funding from other approved areas of its overall 

spending as may be suitable.   

 

24   

The Commission Panel concurs with Mr. Plunkett’s recommendation, and considers the Joint 

Initiatives Program to be an appropriate area from which funds should be used to aggressively 

pursue integrating Terasen’s EEC programs with those of the electric utilities in British Columbia. 

The Commission Panel’s view is that integrating the efforts of gas and electric utilities will better 

encourage customers to take advantage of the programs by eliminating unnecessary duplication in 

communication, applications, audits and similar time consuming activities.     

 

2.4.2  Trade Relations 

 

The Trade Relations program area is aimed at the support and education of skilled trades, 

equipment manufacturers, distributors, suppliers and retailers, appliance and equipment 

salespeople and Realtors.  The $1.5 million in funding being requested for Trade Relations with this 

Application is to support the activities of a Terasen Utilities staff member focused on Trade 

Relations as it relates to energy efficiency. 

 

Commission Determination  

 

The Commission Panel takes note of Terasen’s descriptions of the key decision makers in each of 

the Residential and Commercial EE programs, referred to previously, as well as the references to 

the complexity of the commercial new construction and retrofit sector programs and resulting 

paucity of detail for those program areas. (Exhibit B‐1, p. 61)   

 

The Commission Panel considers that the Trade Relations program area expenditures represent a 

significant duplication of the Residential and Commercial Energy Efficiency programs’ non‐incentive 

costs.  As noted in the Application, the Energy Efficiency programs will significantly increase the 

interactions as between Terasen and its customers, and therefore increase “the opportunities for 

[Terasen] to communicate general conservation information in addition to program‐specific 

information...” (Exhibit B‐1, p. 46)  The Commission Panel finds the evidence with respect to the 

details of the Trade Relations program area to be insufficient, and accordingly, this area of 

expenditure is rejected. 

25   

 

2.4.3  Innovative Technologies, NGV and Measurement 

 

Terasen states that it is in a unique position to foster and further the deployment of forward‐

looking low carbon technologies, including measurement technologies, and is therefore seeking 

funding with this Application, specific to this arena. (Exhibit B‐1, p. 69) 

 

Terasen states that “[t]he amount for Innovative Technologies, NGV and measurement will need to 

be refined – if an effective program in Innovative Technologies, NGV and Measurement can be 

developed over the funding timeframe, the Companies wish to have the ability to fund such a 

program over the funding timeframe.” (Exhibit B‐1, pp. 53, 69)  Terasen states that the activity in 

this area would be in the nature of pilot programs, with limited time frames, geographic areas and 

numbers of installations.  The Companies indicate that they would pursue technologies with the 

same underlying characteristics: 

 

• Each promotes the efficient use of natural gas through sustainable design; 

• None are currently a mainstream technology; 

• Each offers the potential for at least a 10 percent GHG benefit. 

 

Energy efficiency technologies the Companies would intend to pursue include: 

 

• Residential 

o hydronic based heating systems; 

o Integrated energy systems providing both space heat and DHW; 

o Solar thermal assisted space or DHW systems; 

26   

• Commercial 

o hydronic based heating systems; 

o Solar thermal assisted space or DHW systems. 

(Exhibit B‐1, p. 73) 

 

Terasen states that it would aim fuel‐substitution initiatives at both new construction and retrofit 

markets in both the TGI and TGVI service areas, and notes that fuel‐substitution in this category 

refers to the displacement of natural gas using cleaner renewable technologies.   The Companies 

state that more detailed program development work must be completed by Terasen in conjunction 

with industry groups before programs are rolled out or funding is allocated.  (Exhibit B‐1, p. 74) 

 

Commission Determination 

 

The Commission Panel considers that Innovative Technologies, NGV and Measurement programs 

can be appropriate vehicles for encouraging commercial development of technologies to reduce or 

replace natural gas consumption and related GHG emissions. 

 

However, as noted above, Terasen acknowledges that further refinement of this program is 

required and indicates uncertainty as to whether an effective program can be developed over the 

funding timeframe. The Commission Panel finds that there is insufficient evidence with respect to 

the nature and scope of the proposed program, and accordingly rejects the Innovative 

Technologies, NGV and Measurement program expenditures at this time.  Terasen may wish to 

bring forward projects in this program area for consideration as they become more fully developed. 

 

27   

2.5  Conservation Potential Review Update 

 

The Terasen Gas April 2006 Conservation Potential Review (CPR) was a comprehensive planning 

document prepared for TGI to use for: 

 

• Developing a long range energy efficiency and fuel choice strategy; 

• Designing and implementing energy efficiency and fuel choice programs; 

• Assessing the impact of energy efficiency and fuel choice programs on both peak and annual loads; and 

• Setting annual efficiency and fuel choice targets and budgets.  

  (Exhibit B‐1, Appendix 1, page E‐1) 

 

The 2009 CPR estimate of $0.5 million is based on the cost to perform the previous CPR, 

approximately $300,000, plus an allowance for the kind of work done by Habart to refine the CPR 

results into a DSM program. (Exhibit B‐1, p. 53)  The updated CPR would be received in 2010 and 

would form the basis for an application to the Commission for EEC funding for the period 2011 to 

2014. (Exhibit B‐1, p. 69)  It also includes an allowance of $100,000 for cost inflation from the last 

CPR.  (Exhibit B‐2, BCUC 1.21.1) 

 

The CPR Program is discussed at Section 4 of the Application, including an illustration of the CPR 

Process Flow, and a table summarising the potential annual impact identified by the 2006 CPR. The 

2006 CPR identifies a gross impact [consumption reduction] by 2015/2016 of 11.615 million GJs, 

and a Potential Annual Impact of 10.163 million GJs after adding back 1.453 million GJs of 

additional load attributed to the residential fuel switching program.  The gross impact number 

includes 1.890 million GJs for Industrial Energy Efficiency (EE).  Separate programs for Industrial EE 

are not specifically included as part of the Application. (Exhibit B‐2, pp. 44‐46) 

 

The detailed 2006 CPR report is included in the Application. (Exhibit B‐2, Appendix 1) 

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Intervenor Positions 

 

BCSEA‐SCBC supports Terasen’s proposal for approval of expenditures for an update of the CPR to 

form the basis for Terasen’s “next tranche of EEC funding for the period 2011 to 2014.” (BCSEA‐

SCBC Argument, p. 15) 

 

BC Hydro supports Terasen’s evidence with respect to the CPR and also the program element in the 

Application for additional funding for a 2009 update of the CPR. (BC Hydro Argument, p. 5) 

 

Commission Determination 

 

The Commission Panel considers the CPR to be an important tool for use in developing, supporting 

and assessing this and future EEC/DSM expenditure Applications.  The Commission Panel accepts 

the Application’s CPR update expenditure proposal. 

 

The Commission Panel anticipates that Terasen will be able to develop a stronger and more 

transparent linkage between the CPR, the development of programs arising from the CPR and their 

proposed costs in any future EEC/DSM Applications. 

 

2.6  The Industrial Sector 

 

Terasen has not included energy efficiency (EE) initiatives for industrial customers in the 

Application.  Terasen discusses its rationale for not planning for EE programs specifically for the 

industrial sector at Section 6.10 of its Application, Exhibit B‐1, p. 78. 

 

The CPR study conducted by Marbek Resource Consultants Ltd. and Willis Energy Services Ltd. 

(Marbek) concluded that: 

 

29   

“The study findings confirm the existence of significant potential cost‐effective natural gas efficiency improvements in B.C.’s manufacturing sector. In the “most likely” and “upper” achievable scenarios those energy efficiency improvements would provide between about 1,900 and 2,600 thousand GJ/yr. of savings in FY 2015/16. The same energy efficiency improvements would also provide reduced GHG emissions of approximately 80,000 to 112,000 tonnes per year as well as peak day load reductions of approximately 20 to 20.5 thousand GJ.  Two particularly significant opportunities are identified in the study results:  

• Energy efficient boilers for the greenhouse and food processing facilities in the Lower Mainland. 

• Energy efficient kilns for sawmills and planer mills in the Interior.”   

(Exhibit B‐1, Appendix 1, p. 75) 

 

Intervenor Positions 

 

MEMPR provided a Letter of Comment stating: “. . .the Ministry has an interest in seeing Terasen 

Gas Inc. and Terasen Gas (Vancouver Island) Inc. (“the Companies”) expand their demand‐side 

management activities.  The Ministry notes the absence of specific demand‐side measures for the 

industrial sector in the Application. The Companies may be missing significant conservation and 

efficiency gains.”  (MEMPR Letter of Comment, Exhibit C1‐4, p. 1) 

 

The Ministry also submitted that the Commission should include a number of determinations in its 

Decision with respect to the processes and timing of development of DSM measures for the 

manufacturing sector.   

 

BCSEA‐SCBC concurs with MEMPR’s recommendation. (BCSEA‐SCBC Argument, p. 16) 

 

Terasen submits that “a cautious approach is warranted in considering delivering incentives to 

industrial customers at a high enough dollar level to spur participation adequate to ensure a 

positive TRC.  Both of these options expose customers to risk. The Terasen Utilities will continue to  

30   

explore opportunities for industrial DSM and will bring forward a proposal if they regard 

expenditures as being warranted and in the interests of customers.”  (Terasen Reply, p. 17) 

 

Commission Determination  

 

The Commission Panel considers that the omission of an industrial sector program in Terasen’s EEC 

Application is a significant and unfortunate shortcoming in Terasen’s stated efforts to support the 

BC Energy Plan (“Energy Plan”) Policy Actions (Exhibit B‐1, Appendix 6) with respect to Energy 

Efficiency in the industrial sector.  The Commission Panel takes particular note of Terasen’s specific 

exclusion of EEC Policy Action 8, which addresses the development of an “Industrial Energy 

Efficiency Program”. (Exhibit B‐1, p. 40; Energy Plan, p. 39) 

 

The Commission Panel takes note of the MEMPR Letter of Comment, and directs Terasen to 

commence the planning process for the development of an industrial EE program and to file a 

report outlining the process contemplated and scheduling of the development plan with the 

Commission for review within 90 days of this Decision.  The matters addressed in the report should 

include those raised by MEMPR in Exhibit C4‐1.   

 

31   

3.0  ASSESSMENT CRITERIA AND ACCOUNTABILITY 

 

Terasen believes that the benefit‐cost “. . . results for the proposed EEC expenditure in this 

Application are under‐stated, because the benefits used in the calculations include free‐riders, 

effectively reducing the net energy savings, and exclude attribution effects, as well as excluding 

savings from the proposed expenditure on Joint Initiatives, Trade Relations, Conservation 

Education and Outreach and Innovative Technologies, Measurement and NGV.  However, even 

with this approach, which could be considered conservative, the Total Resource Cost test result for 

the EEC portfolio as a whole is positive, with a ratio of 2.9., and a net financial benefit of $139.4 

million. If free rider effects are excluded, as the Companies are proposing, the EEC portfolio has a 

TRC ratio of 3.1 and a net financial benefit of $165.1 million.” (Exhibit B‐1, pp. 87, 88) 

 

3.1  Portfolio Approach 

 

Terasen proposes a “portfolio approach” to the benefit‐cost analysis which involves assessing the 

cost effectiveness of the EEC portfolio as a whole, “on an overall combined basis, rather than on 

individual initiatives or program areas.” (Exhibit B‐1, p. 82)  Terasen proposes that the portfolio as a 

whole maintain a TRC ratio of 1.0 or better to allow it to include programs which, on an individual 

basis, may not have such a ratio in the short term, but have longer term potential to achieve the 

ratio.  This approach would also allow Terasen to offer programs to customers in service areas 

which would otherwise not have sufficient customer usage to support the necessary TRC ratio.  

(Exhibit B‐1, pp. 11‐12) 

 

Intervenor Positions 

 

Mr. Plunkett indicates that judging economic performance at the portfolio level only is 

“problematic”.  (Exhibit C5‐5, p. 14)  He recommends that Terasen establish the cost‐effectiveness 

of each measure and project.  (Exhibit C5‐5, p. 15) 

 

32   

Terasen states in reply that it is not proposing that economic performance be judged only at the 

portfolio level and that Mr. Plunkett has mischaracterized its proposal. 

 

Terasen states that “[t]he energy efficiency and fuel switching programs would be planned and 

evaluated on the TRC, the RIM test, the Utility Cost (“UC”) test and the Participant test, and the 

overall portfolio TRC test results would have to be greater than 1.0 to proceed.”  (Exhibit B‐1, p. 83) 

 

However, Terasen also states that it is “not proposing any thresholds with respect to the RIM test, 

the UC test and the Participant test.  In the absence of such thresholds, [it is] not comfortable 

stating that an activity would proceed or not based on RIM, UC and Participant test results.”  

Rather, Terasen proposes that “the overall portfolio level TRC must be maintained at 1.0 or 

greater.”  (Exhibit B‐4, BCUC 2.19.1) 

 

Commission Determination 

 

The Commission Panel accepts the portfolio level approach based on achieving a portfolio TRC 

level, discussed below, of 1.0 or greater provided that program areas, initiatives or measures with 

an individual TRC of less than 1.0 are proactively designed and sufficiently support social or 

environmental objectives. Consequently, it is important for the components of any portfolio to be 

capable of analysis on an individual basis.  The Commission Panel directs that Terasen include in its 

annual EEC Report to the Commission the results of the RIM, UC, TRC and Participant tests for each 

proposed DSM in its portfolio, and provide justification for continuing with any measures or groups 

of measures which have a TRC of less than 1.0.  

  

33   

Total Resource Cost Test  

 

Terasen proposes that the benefit‐cost tests be used to evaluate its programs as outlined in the 

“California Standard Practice Manual:  Economic Analysis of Demand‐Side Programs and Projects”, 

which is included in Exhibit B‐1 as Appendix 12 (“the California Standard Practice Manual”).  

(Exhibit B‐1, p. 82) 

 

The California Standard Practice Manual describes the Total Resource Cost Test as a cost‐

effectiveness test which “measures the net cost of a demand‐side management program as a 

resource option based on the total costs of the program, including both the participants’ and the 

utility’s costs.”  (Exhibit B‐1, Appendix 12, p. 18)  

 

The “benefits” portion of the TRC test is made up of the avoided supply costs, valued at their 

marginal cost, for periods when a load reduction results.  These costs are “calculated using net 

program savings, savings net of changes in energy use that would have happened in the absence of 

the program.  For fuel substitution programs, benefits include the avoided device costs and avoided 

supply costs for the energy, using equipment not chosen by the program participant.”  (Exhibit B‐1, 

Appendix 12, p. 18) 

 

The “costs” portion of the TRC test is made up of the program costs paid by the utility and the 

participants plus any increase in supply costs for periods when load is increased.  This is a broad 

category, and includes all equipment costs, installation, operation and maintenance costs, cost of 

removal (less any salvage value), and administration costs, regardless of who pays, less any tax 

credits.  For fuel substitution programs, costs also include any increase in the supply costs of the 

utility providing the chosen fuel. (Exhibit B‐1, Appendix 12, p. 18) 

 

The benefit‐cost ratio is the ratio of discounted total program benefits to discounted total program 

costs over a specified period of time.  A benefit‐cost ratio greater than one indicates the program is 

beneficial, on the basis of the TRC test. (Exhibit B‐1, Appendix 12, p. 19) 

 

34   

Intervenor Positions 

 

BCOAPO prefers the “Societal test” over other cost‐benefit tests which it argues “do not capture 

the non‐economic benefits of DSM programs”. (BCOAPO Argument, p. 4)  

 

According to the California Standard Practice Manual, the “Societal test” is a variant of the TRC 

test.  It differs in that it looks at society as a whole as opposed to the utility’s service territory and 

includes the effects of externalities, such as environmental implications.  It also excludes tax credit 

benefits and uses a “societal” discount rate.   

 

Mr. Plunkett notes in his evidence that:  “[i]ncluding external social and environmental benefits in 

calculating DSM cost‐effectiveness would be to apply the societal test, not the total resource cost 

(TRC) test.  Other jurisdictions such as Vermont and New York apply the societal test as the 

threshold determinant of DSM cost‐effectiveness.  Explicitly valuing social and environmental 

externalities in DSM cost‐effectiveness will lead to more efficient resource allocation – and greater 

societal net benefits – than the economically inferior policy of pursuing a portfolio benefit/cost 

ratio under the TRC test of 1.0.”  (Exhibit C5‐7, BCUC 1.5.2)  

 

Commission Determination 

 

The Commission Panel acknowledges the Societal test as one which addresses a broader spectrum 

of factors not included in the TRC test.  While recognising that societal factors have significance, 

the Commission Panel views many of these factors as being rather subjective and difficult to 

measure.  The Commission Panel also takes note of the DSM Regulation which will apply to Terasen 

as of June 01, 2009 requiring the Commission to use, in addition to any other test it considers 

appropriate, the TRC test in determining whether a demand‐side measure is cost‐effective.  While 

the DSM Regulation is not in effect for the purposes of this Decision, the Commission Panel does 

consider the TRC test to be appropriate and adequate for the purposes of this Application and 

accepts it as such.      

 

35   

3.2  Free Riders 

 

Terasen seeks certain changes to the cost‐benefit analysis undertaken in respect of EEC 

expenditures, including a proposal to “. . . eliminate the requirement to include free riders in cost‐

benefit tests, as the energy and emissions reduction goals of the government are absolute goals 

and do not consider free ridership effects.” (Exhibit B‐1, p. 16) 

 

The Application defines free riders as “. . . customers who participate in a program, but would have 

undertaken the same conservation actions even if the program were not offered”.   Terasen’s 

proposal with respect to free riders includes two tables illustrating an estimated TRC benefit for the 

EEC Portfolio of $165.149 million, excluding the effects of free riders, and of $139.448 million, 

including the effects of free riders, a difference of $27.701 million.  Terasen’s discussion concludes 

with the view that “. . . the inclusion of the effects of free riders in the cost‐benefit test for EEC 

programs distorts the value of EEC programs and is counter to the objectives of the energy plan.”     

(Exhibit B‐1, pp. 85‐86) 

 

Terasen responded in some detail to Information Requests concerning Free Riders, including the 

statements that “[f]ree riders are one of the most‐debated aspects of DSM cost‐benefit tests as 

they are challenging to establish” and “[e]stimating free rider rates . . .  is more of an art than a 

science.”  (Exhibit B‐2, BCUC 1.3.1) 

 

It is Terasen’s view that “it should be the outcome [energy consumption reduction] that matters, 

not the way in which it was achieved.” (Exhibit B‐1, p. 86)  Terasen states: “. . . . [Government] GHG 

reduction goals make no mention of net‐to‐gross ratios – in fact they could be considered “gross” 

GHG reduction goals, and presumably it is gross energy savings that will be counted towards 

achieving those goals. It makes sense to align gross estimations of energy savings from utility DSM 

programs with government’s gross GHG reduction goals.” (Exhibit B‐2, BCUC 1.3.1) 

 

36   

Terasen notes that “[w]hile it is possible that estimated free rider rates may be higher than 

forecast, it is also possible that free rider rates may be lower than forecast.”  (Exhibit B‐2, 

BCUC 1.46.1) 

 

Intervenor Positions 

 

With respect to the free rider issue, BCSEA‐SCBC’s expert Mr. Plunkett states:  

 

“[Terasen’s] proposal would depart from well‐established Commission practice of accounting for savings from program free riders. This not only distorts economic assessment but is also inconsistent with resource planning, since it will overstate how much Terasen should expect to reduce energy supply requirements. It will also distort program design, especially in appliance and equipment replacement markets where the high‐efficiency market penetration can change rapidly. Ignoring free ridership would tend to prevent adjustments in minimum qualifying efficiency levels due to a higher‐efficiency market baseline.”  (Exhibit C5‐5, pp.15, 16) 

 

Mr. Plunkett’s concluding recommendation included directing Terasen to modify its plan to 

“[d]evelop market net‐to‐gross ratios for programs based on estimates of free‐ridership and 

spillover effects incorporated into program planning and design.” (Exhibit C5‐5, p. 23) 

 

BCSEA‐SCBC does, however, agree with Terasen that “the inclusion or exclusion of free riders from 

the analysis makes no practical difference in evaluating the acceptability of this specific EEC plan on 

an overall basis” although it notes that “failing to incorporate the free‐rider factor can distort 

program design.”  (BCSEA‐SCBC Argument, p. 19) 

 

BCOAPO expresses the view that “. . . free ridership has the effect of over‐crediting EEC programs.  

BCOAPO agrees that measuring free ridership is difficult, but this difficulty does not mean that it is 

appropriate to set it to zero.” BCOAPO concurs with Mr. Plunkett’s views with respect to the free 

rider issue. (BCOAPO Argument, p. 13) 

 

37   

Commission Determination 

The Commission Panel notes the position of Terasen, and the acknowledgements of BCOAPO and 

BCSEA‐SCBC that, in the case of the Application, the free rider issue has no immediate practical 

impact, as the portfolio level TCR results calculated either with or without inclusion of the free rider 

effect is well above the ‘break‐even’ threshold of 1.0. However, the Commission Panel does 

consider that this issue is likely to become a factor as the DSM initiatives of Terasen become more 

fully developed and refined, and therefore should be addressed in this Decision. 

 

The Commission Panel does not agree with Terasen’s position that “. . . the inclusion of the effects 

of free riders in the cost‐benefit test for EEC programs distorts the value of EEC programs and is 

counter to the objectives of the energy plan.” (Exhibit B‐1, pp. 85‐86)  The Commission Panel 

considers that it would be an unacceptable distortion to measure the effectiveness DSM programs 

by giving credit to the programs for consumption reductions which, based Terasen’s own definition 

(quoted above), would have taken place absent the incentive program.   

 

The Commission Panel rejects Terasen’s proposal to exclude the free rider factor from program 

effectiveness (TRC) calculations.  

 

3.3  Attribution to Regulatory Changes 

 

Terasen submits that once a proposed regulation and implementation date for minimum efficiency 

standards for an appliance, building or energy system is announced by a regulating body, it be 

permitted to attribute savings to market transformation programs for that particular appliance, 

building or energy system in its cost benefit tests at that time.  The proposal involves attributing 

the savings to the program over a five year span, with adjustment for the level of Terasen’s support 

for the market transformation and the level of financial contribution by others. 

 

38   

Terasen submits that it is reasonable to include attribution savings in a cost‐benefit test, 

particularly in light of the newly issued DSM Regulation. The Regulation permits the Commission to 

include in the benefit of measures proposed a proportion of the savings resulting from the 

increased market share of a regulated item because of the commencement and application of a 

specified standard with respect to the regulated item. (Terasen Argument, p. 39; Exhibit B‐1, p. 12; 

Exhibit B‐1, p. 16) 

 

The attribution rates proposed by the Company, for which it is seeks approval with this Application, 

for any such future regulation are outlined below. 

 

Table 6 Attribution Rates 

Regulation Year  

Percentage of Savings Attributed to Program 

1  50 

2  40 

3  30 

4  20 

5  10 

  Source:  Exhibit B‐1, p. 87 

 

Intervenor Positions 

 

BCSEA‐SCBC’s concern with respect to the attribution concept is based on Mr. Plunkett’s evidence 

that it can distort program design. As with the free‐rider factor, BCSEA‐SCBC favours the use of net‐

to‐gross ratios. (BCSEA‐SCBC Argument, p. 20) 

 

BC Hydro submits that “Terasen Utilities' position on attribution of savings from codes and 

standards to utility DSM programs is arbitrary and will result in an unrepresentative view of the 

benefits (higher or lower) associated with some programs.”  BC Hydro further submits that  

39   

“[a]ttribution of savings from codes and standards should be evaluated on a case‐by‐case basis” 

and that “the attribution rate should reflect the level of support for market transformation”, 

arguing that Terasen’s “position on attribution goes against this approach.” (BC Hydro Argument, p. 

17)  

 

BCOAPO states “. . . the DSM regulation 4(7) allows for the Commission to include a proportion of 

the benefit that, in the Commission’s opinion (not the Applicant’s) will increase market share only 

between the time that a specified standard has been announced, and the time that it commences. 

Any attribution beyond that will, predictably, distort program design.”  (BCOAPO Argument, p. 13) 

(emphasis in original) 

 

In its Reply, Terasen notes that “BCOAPO and BCSEA‐SCBC have made submissions on attribution of 

benefits. This issue is not relevant to the assessment of the proposed portfolio, as the assessment 

does not include any attribution of benefits. With respect to the assessment of future portfolios, 

the Terasen Utilities repeat and rely on the submissions made in paragraphs 109 to 111 of the 

Initial Submissions” (which argue for the inclusion of attribution savings.) 

(Terasen Reply, p. 20) 

 

Commission Determination 

 

The Commission Panel notes Terasen’s comment that the attribution issue is not relevant to this 

Application as the assessment does not include any attribution of benefits. However, as in the case 

of free riders, the Commission Panel does consider that this issue is likely to become a factor as the 

DSM initiatives of Terasen become more fully developed and refined, and therefore should be 

addressed in this Decision. 

 

The Commission Panel accepts the position of BC Hydro that attribution of savings from codes and 

standards should be evaluated on a case‐by‐case basis and that the attribution rate should reflect 

the level of support for market transformation.  The Commission Panel shares the BCSEA‐SCBC’s  

40   

concern, as detailed in Mr. Plunkett’s evidence, that the attribution concept can distort program 

design.   

 

The Commission Panel rejects the Attribution to Regulatory Change proposal made in the 

Application and refers this issue back to Terasen to redesign and resubmit with its next annual EEC 

report to the Commission, giving consideration to a modified version of the Application’s 

attribution proposal reflecting the provisions of the DSM Regulation which come into effect for 

Terasen on June 1, 2009.  The Commission Panel directs Terasen to address, in the modified 

version, the matters raised by BC Hydro and BCSEA‐SCBC, and also to give consideration to factors 

such as the length of time a particular program element has been operative at the time any 

applicable regulation is introduced and how compatible the program initiative is with the new 

regulation (e.g. if a regulation is introduced with a higher or lower threshold or standard than the 

program design). 

3.4  Carbon Pricing 

 

As part of the Application, Terasen seeks an order approving certain changes to the benefit‐cost 

analysis undertaken in respect of EEC expenditures, including recognizing the impact of carbon 

pricing as one of the inputs to the benefit‐cost tests.  (Exhibit B‐1, pp. 15‐16) 

 

Terasen proposes that additional customer bill savings from the implementation of the tax should 

be included in the benefit‐cost analysis for EEC programs. Terasen proposes that the activities 

supported by the EEC Application will contribute to consumer education and provide consumers 

with tools to help them reduce the impact of the proposed carbon tax on their energy 

expenditures. (Exhibit B‐1, p. 41) 

Terasen summarises its position with respect to the carbon tax matter in Argument as follows: “The 

customers will also enjoy a benefit associated with reduced Carbon Tax costs. Customers that 

install an efficient appliance or design a more efficient building as a result of Terasen's EEC 

initiatives will use less gas, and will therefore pay less Carbon Tax. Therefore, the avoided Carbon  

41   

Tax was included in the participant benefits, as noted in Appendices 11A and 11B of the 

Application”  [Terasen Argument, p. 21) 

 

Commission Determination 

 

The Commission Panel accepts Terasen’s proposal for the carbon tax reduction as an appropriate 

factor to be included in computing the EEC cost‐benefit analysis.  

 

3.5  Accountability Mechanisms 

 

Terasen summarises its proposal for accountability mechanisms as follows: 

“In this Application the Companies have recognized the need for accountability for the funds approved for EEC programs. First, any funds not spent will not be charged to the regulatory asset deferral account. Second, the Companies intend to monitor the portfolio TRC on a monthly basis, and have proposed to file an Annual EEC Report with the Commission by the end of the first quarter every year. The Report will detail program activity, expenditures, and cost‐benefit results for the previous year, as well as describe program activity and provide forecasts for the upcoming year. Third, in the event that the relief sought is granted, the Companies would form and engage an EEC stakeholder group with membership representing a broad cross section of stakeholders identified in the Application. Fourth, the Companies have indicated their intention to hold annual EEC workshops with stakeholders, at which the Companies would present updates on program progress and obtain stakeholder input on new programs and refinements to existing programs. Fifth, the Companies are proposing to develop many of the programs for the commercial sector and the DSM for Affordable Housing sector in conjunction with stakeholder advisory groups.” (Terasen Argument, p. 39) 

Intervenor Positions 

BCSEA‐BCSC states that they: “. . . support this [funding] approach, noting that the proposed 

accountability mechanisms are designed to be more effective and efficient than having on‐going 

Commission involvement in decision‐making within the portfolio during the Funding Period” and 

“BCSEA‐SCBC acknowledge and support the additional accountability mechanisms proposed by 

Terasen in [Terasen Argument] paragraph 112.”  (BCSEA‐SCBC Argument, pp. 5, 20) 

42   

 

BCOAPO argues that, should the Application be approved, an independent audit process should be 

required with respect particularly to free ridership, attribution and redirection of funds. (BCOAPO 

Argument, p. 14) 

 

Commission Determination 

 

The Commission Panel accepts Terasen’s accountability undertakings, and considers that, while the 

proposal to evaluate the EEC project using the TRC test at the Portfolio level has been accepted, 

TRC calculations for each program area, initiative and measure should also be included in the 

accountability reporting as a means of assessing the components of the Project and their ongoing 

effectiveness. 

 Commission Panel directs that the annual EEC Report include the following: 

 

• TRC, RIM, UC, and Participant test calculations of DSM at the Program Area initiative and individual measure levels in addition to the total Portfolio level reporting.  Reporting of the Residential & Commercial EE program areas should also be made at the New Construction and Retrofit levels.   

• any inter and intra Program Area initiative funding transfers, with supporting rationale, and the impact of such transfers on the transferor and transferee Program areas, initiatives, and measures as the case may be.  

• data for fuel switching programs should be tracked in a manner which allows for reporting types of fuels replaced by natural gas, including estimated GHG impacts. 

 

The Commission Panel also directs Terasen to include in its annual EEC Report to the Commission a 

discussion of its internal data gathering, monitoring and reporting control processes. The discussion 

should include a description of how these processes ensure that funds expended and the statistical 

results of the programs implemented are completely and accurately recorded and monitored, 

including any related internal check and audit processes. The report should also discuss how 

Terasen has measured or estimated the results of the EEC expenditure initiatives. 

43   

4.0  CAPITALISATION OF INCREMENTAL EEC EXPENDITURES 

 

Terasen’s proposed EEC expenditures are summarised and discussed in Section 2.0.  Terasen 

proposes to capitalise the approved incremental expenditures as a regulatory deferral account in 

the year in which the expenditures are incurred, with amortisation over 20 years commencing the 

year after the expenditures are made.  The proposed amortisation period is addressed in Section 

5.0 of this Decision.  

 

Terasen’s total EEC expenditures for 2008 to 2010 include operating and maintenance (O&M) 

expenditures for its previously approved DSM programs for 2008 and 2009.  Terasen proposes to 

charge those O&M costs to operations in those years, with the balance of the total EEC 

expenditures being added to a new EEC deferral account. This method accounts for the impact of 

the legacy DSM Operating & Maintenance expenditures having been considered in the PBR and RR 

Extended Settlements for TGI and TGVI respectively. The reconciliation of the Total EEC 

expenditures and the amounts expensed and deferred is illustrated in the following table. 

 

Table 7  

Deferral Reconciliation TGI TGVI

2008 2009 2010 2008 2009 2010

Total EEC

Expenditures

13,996

15,752 17,196

2,830

3,043

3,793

Expensed per Extended

Settlements

1,624

1,624 -

500

500 -

Proposed Deferral Addition

12,372

14,128

17,196

2,330

2,543

3,793

  Source: Exhibit B‐1, pp. 49, 95, 97   

Terasen points out that its proposed accounting treatment to capitalize the EEC expenditures is 

permitted under current Canadian Institute of Chartered Accountants (CICA) accounting standards.  

Terasen also notes that, effective 2011, all publicly accountable entities, including it will be 

required to comply with International Financial Reporting Standards (IFRS).  Terasen is of the view 

44   

that: “. . . the proposed financial treatment of EEC funding also meets the requirements of IFRS” 

and goes on to state that “[i]f, however, after further discussion and closer examination in 

conjunction with auditors and other utilities, the EEC funding failed to pass these [IFRS] tests, then 

[Terasen] will revisit the program to ensure that it continues in a fashion which maintains an 

alignment on interests between customers, investors and government policy.” (Exhibit B‐1, pp. 81‐

82) 

 

Intervenor Positions 

 

BCSEA‐SCBC comments on Terasen’s “. . . proposal to capitalize incremental EEC expenditures 

amortised over 20 years.  BCSEA‐SCBC supports this concept, including the 20 year amortisation 

period due to the life‐expectancy of gas DSM measures.”  (BCSEA‐SCBC Argument, p. 17) 

 

Commission Determination 

 

The Commission Panel accepts Terasen’s proposal to capitalize the approved EEC expenditure to a 

regulatory deferral account, and to amortitse the deferral account balances over an appropriate 

time period.  The related issues of the quantum of the expenditures approved and the appropriate 

amortisation period(s) for the program areas are addressed in other sections of this Decision. 

 

45   

5.0  AMORTISATION OF EEC EXPENDITURES 

 

Terasen proposes to amortise its EEC expenditures, including both program, and incentive and 

rebate costs, over a 20 year period, based on a calculation of the 22.5 years as the weighted 

average measurable life of the proposed appliance and energy system installations.  Terasen’s 

weighted average calculation is based on achieving estimated volumes, mix and lives of 

installations for the various measures being proposed. (Exhibit B‐1, p. 80, and Appendix 40.2)  

FortisBC and BC Hydro each use 10 year amortisation periods. (Exhibit B‐2, p. 95)  Terasen states: 

“…research failed to uncover any examples where utilities are using or proposing amortisation 

periods as long as 20 years” for DSM programs. (Exhibit B‐2, p. 97) 

 

Commission Determination 

 

The Commission Panel rejects the 20 year amortisation period proposed by Terasen.   The 

Commission panel considers the underlying forecast assumptions on which the Terasen 

methodology is based to be inherently uncertain, and deserving little weight. The Commission 

Panel does consider that a ten year amortisation period provides a reasonable balance, considering 

both the DSM objectives and customer impact.  Terasen is directed to base its amortisation of 

approved EEC expenditures over periods not to exceed 10 years. 

 

46   

DATED at the City of Vancouver, in the Province of British Columbia, this    16th   day of April 2009. 

   

  Original signed by:   A.W. KEITH ANDERSON   COMMISSIONER    

  Original signed by:   ALISON A. RHODES   COMMISSIONER  

                  

SIXTH FLOOR, 900 HOWE STREET, BOX 250 VANCOUVER, B.C.  V6Z 2N3   CANADA 

web site: http://www.bcuc.com 

    

 

                

TELEPHONE:  (604)  660‐4700 BC TOLL FREE:  1‐800‐663‐1385 FACSIMILE:  (604)  660‐1102 

 

 BRIT ISH  COLUMBIA  

UTIL IT IES  COMMISSION      ORDER    NUMBER   G‐36‐09  

IN THE MATTER OF the Utilities Commission Act, R.S.B.C. 1996, Chapter 473 

 and  

Terasen Gas Inc. and Terasen Gas (Vancouver Island) Inc. Energy Efficiency and Conservation Programs Application 

  

BEFORE:  A.W.K. Anderson, Commissioner   April 16, 2009   A.A. Rhodes, Commissioner   

  

O  R  D  E  R  

WHEREAS:  A.  On May 28, 2008 Terasen Gas Inc. and Terasen Gas (Vancouver Island) Inc. (collectively “Terasen”) filed an 

application for approval of various concepts and expenditures in support of an expanded energy efficiency and conservation (“EEC”) strategy, and to capitalize incremental EEC expenditures by charging the expenditures to a regulatory asset deferral account and amortising the balance over 20 years (the “Application”); and 

 B.  On June 3, 2008 the British Columbia Utilities Commission (“Commission”) issued a letter requesting that 

interested parties register and file comments on Terasen’s proposed timetable before June 11, 2008; and  C. By Order G‐102‐08 dated June 19, 2008, the Commission issued a Preliminary Regulatory Timetable which 

included two rounds of Commission Information Requests and one round of Intervenor Information Requests, and requested comments from all parties on further process for reviewing the Application; and 

 D. In response to Order G‐102‐08, the Commission received replies from Terasen and the following Intervenors:  

B.C. Ministry of Energy Mines and Petroleum Resources (“MEMPR”), British Columbia Hydro and Power Authority (“BC Hydro”), B.C. Sustainable Energy Association and the Sierra Club of British Columbia (“BCSEA‐SCBC”), the Commercial Energy Consumers Association of British Columbia (“CEC”), B.C. Old Age Pensioners’ Organization et al. (“BCOAPO”); and 

 E. Following its review of comments from Terasen and Intervenors, the Commission issued Letter L‐39‐08 

dated September 8, 2008 ordering a second round of Intervenor Information Requests; and  

          

2    

 BRITISH  COLUMBIA  

UTILITIES  COMMISSION      ORDER    NUMBER   G‐36‐09  

F. By Order G‐130‐08 dated September 18, 2008 the Commission established a Written Hearing Process and Regulatory Timetable for its review of the Application; and 

 G. The Written Hearing Process concluded on December 5, 2008 with the filing of Terasen’s reply submission; 

and  H. The Commission has reviewed and considered the evidence and submissions of Terasen and Registered 

Intervenors.   NOW THEREFORE pursuant to section 44.2 of the Utilities Commission Act, and subject to the specific determinations, qualifications and directions set out in the Decision issued concurrently with this Order, the Commission orders as follows:   1.  The following proposed expenditures are accepted:  

(a) $31.077 million for the combined Residential Energy Efficiency and Commercial Energy Efficiency programs; 

 (b) Expenditures for programs or initiatives directed at fuel switching away from fossil fuels with a higher 

carbon content than that of natural gas to natural gas;  

(c) $6.918 million for the Conservation Education and Outreach program;  

(d) $3 million for Joint Initiatives; and   

(e) $0.5 million for Conservation Potential Review.  2.  Expenditures in the sum of $3 million for Innovative Technologies, Natural Gas Vehicles and Measurement 

and $1.5 million for Trade Relations are rejected.  3.  The proposed portfolio approach is accepted.  4.  The Total Resource Cost test is accepted as the appropriate test for cost effectiveness.  

          

3    

 BRITISH  COLUMBIA  

UTILITIES  COMMISSION      ORDER    NUMBER   G‐36‐09  

5. The proposal to exclude the free rider factor from benefit‐cost analyses is rejected.  6. The proposal for Attribution of Regulatory Changes is rejected.  7. The proposal to include carbon tax reductions in computing benefit‐cost analyses is accepted.  8. Terasen is to commence the planning process for development of an Industrial EEC program and file a report 

with the Commission within 90 days of the date of the Decision.  9. The proposal for accountability mechanisms is accepted and Terasen is to file an annual report on its EEC 

activities as described in the Commission’s Decision.  10. Subject to paragraph 11 below, the proposal to capitalise the approved EEC expenditure to a regulatory 

deferral account and to amortise the deferral account balances is accepted.  11. The proposal to amortise EEC expenditures over a 20 year period is rejected.  Terasen is directed to base its 

amortisation of approved EEC expenditures over periods not to exceed 10 years.    DATED at the City of Vancouver, in the Province of British Columbia, this           16th           day of April 2009.    BY ORDER    Original signed by:    A.W.K. Anderson   Commissioner  

Orders/G‐36‐09_TGI‐TGVI Energy Efficiency Conservation Decision 

APPENDIX 1 Page 1 of 6 

 IN THE MATTER OF 

the Utilities Commission Act, R.S.B.C. 1996, Chapter 473  

and  

Terasen Gas Inc. and Terasen Gas (Vancouver Island) Inc. Energy Efficiency and Conservation Programs Application 

  

EXHIBIT LIST 

 Exhibit No.  Description  COMMISSION DOCUMENTS  A‐1  Letter dated June 3, 2008 issuing request for comments on process and proposed 

timetable 

A‐2  Letter dated June 19, 2008 issuing Order No. G‐102‐08 establishing the Regulatory Timetable 

A‐3  Letter dated June 20, 2008 issuing Commission Information Request No. 1 

A‐4  Letter dated July 25, 2008 issuing Commission Information Request No. 2 

A‐5  Letter dated September 8, 2008 establishing a Second Round of Information Requests 

A‐6  Letter dated September 12, 2008 issuing Commission Information Request No. 3 

A‐7  Letter dated September 18, 2008 and Order No. G‐130‐08 establishing a Written Hearing and Regulatory Timetable 

A‐8  Letter dated October 22, 2008 issuing Information Request #1 to BC Hydro 

A‐9  Letter dated October 24, 2008 filing Information Request No. 1 to BCSEA 

 APPLICANT DOCUMENTS  B‐1  Letter dated May 28, 2008 filing Energy Efficiency and Conservation Programs 

Application 

B‐2  Letter dated July 11, 2008 filing response to the Commission’s Information Request No. 1 

Updated: April 15, 2009

APPENDIX 1 Page 2 of 6 

 Exhibit No.  Description  B‐2‐1  CONFIDENTIAL ‐ Letter dated July 11, 2008 filing response to the Commission’s 

Information Request No. 1, Questions 9.2 and 22.1 

B‐3  Letter dated August 15, 2008 filing response to the Commission’s Information Request No. 2 

B‐4  CONFIDENTIAL ‐ Letter dated August 15, 2008 filing response to the Commission’s Information Request No. 2 

B‐5  Letter dated August 15, 2008 filing response to BC Hydro’s Information Request No. 1 

B‐6  Letter dated August 15, 2008 filing response to BCOAPO’s Information Request No. 1 

B‐7  Letter dated August 15, 2008 filing response to BC Sustainable Energy Assoc & Sierra Club of Canada Information Request No. 1 

B‐8  Letter dated August 15, 2008 filing response to the Commercial Energy Consumers Association of BC’s Information Request No. 1 

B‐9  Letter dated August 15, 2008 filing response to the Ministry of Energy, Mines & Petroleum Resources’ Information Request No. 1 

B‐10  Letter dated August 15, 2008 filing response to the Rental Owners & Managers Society of BC’s Information Request No. 1 

B‐11  Letter dated August 27, 2008 filing comments on submissions from Intervenor and on the further procedural process 

B‐12  WITHDRAWAL ORIGINAL B‐11, AMENDED AND REPOSTED ‐ Letter dated October 6, 2008 filing response to the Commission’s Information Request No. 3 

B‐13  WITHDRAWAL ORIGINAL B‐12, AMENDED AND REPOSTED ‐ Letter dated October 6, 2008 filing response to the BCOAPO’s Information Request No. 2 

B‐14  WITHDRAWAL ORIGINAL B‐13, AMENDED AND REPOSTED ‐ Letter dated October 6, 2008 filing response to the BCSEA’s Information Request No. 2 

B‐15  Letter dated October 24, 2008 issuing Information Request No. 1 to BC Hydro and Power Authority 

B‐16  Letter dated October 24, 2008 issuing Information Request No. 1 to BCSEA and SCBC 

 

APPENDIX 1 Page 3 of 6 

 Exhibit No.  Description  INTERVENOR DOCUMENTS  C1‐1  MINISTRY OF ENERGY, MINES AND PETROLEUM RESOURCES (MEMPR) – Letter dated June 10, 

2008 from Duane Chapman, Senior Regulatory Advisor, requesting participation in the proceedings 

C1‐2  Letter dated July 24, 2008 filing MEMPR’s Information Request No. 1 

C1‐3  Letter dated August 27, 2008 filing comments on further procedural process 

C1‐4  Letter dated October 24, 2008 filing comment for consideration 

 C2‐1  BRITISH COLUMBIA HYDRO & POWER AUTHORITY (BC HYDRO) – Online web registration 

received June 10, 2008 filing request for Intervenor status 

C2‐2  Letter dated June 11, 2008 filing comments on the regulatory review process and timetable 

C2‐3  Letter dated July 25, 2008 filing Information Request No. 1 to Terasen 

C2‐4  Letter dated August 27, 2008 filing comments on further procedural process 

C2‐5  Letter dated September, 2008 filing request for an extension for filing Intervenor Evidence 

C2‐6  Letter dated October 14, 2008 filing BC Hydro’s Evidence 

C2‐7  Letter dated November 7, 2008 filing responses to the Commission’s and Terasen Utilities’ Information Request No. 1 

 C3‐1  RENTAL OWNERS AND MANAGERS SOCIETY OF BC (ROMS) – Letter dated June 10, 2008 

from Al Kemp, CEO, requesting Intervenor status 

C3‐2  Letter dated July 21, 2008 filing Information Request No. 1 to Terasen 

 C4‐1  BRITISH COLUMBIA OLD AGE PENSIONERS ORGANIZATION (BCOAPO) ‐ Letter dated June 11, 

2008 request for Registered Intervenor status for Leigha Worth, Eugene Kung, and James Wightman of Econalysis Consulting 

C4‐2  Letter dated June 11, 2008 filing comments on procedural matters 

APPENDIX 1 Page 4 of 6 

 Exhibit No.  Description  C4‐3  Letter dated July 25, 2008 filing Information Request No. 1 to Terasen 

C4‐4  Letter dated August 27, 2008 filing comments on further procedural process 

C4‐5  Letter dated September 15, 2008 filing Information Request No. 2 to Terasen 

 C5‐1  BC SUSTAINABLE ENERGY ASSOCIATION (BCSEA) AND THE SIERRA CLUB OF CANADA (BRITISH 

COLUMBIA CHAPTER) (SCCBC) ‐ Letter dated June 11, 2008 request for Registered Intervenor status 

C5‐2  Letter dated July 25, 2008 filing Information Request No. 1 to Terasen 

C5‐3  Letter dated August 27, 2008 from William J. Andrews, legal counsel, filing comments on further procedural process 

C5‐4  Letter dated September 15, 2008 filing Information Request No. 2 to Terasen 

C5‐5  Letter dated October 14, 2008 filing BCSEA et al Evidence 

C5‐6  Letter dated October 16, 2008 filing Errata to Evidence (Exhibit C5‐5) 

C5‐7  Letter dated November 7, 2008 filing response to the Commission’s Information Request 

C5‐8  Letter dated November 7, 2008 filing response to Terasen’s Information Request with worksheet  

 C6‐1  FORTISBC INC. ‐  Letter dated June 12, 2008 from Joyce Martin, filing request for 

Registered Intervenor status 

C7‐1  PACIFIC NORTHERN GAS LTD. (PNG) – Online web registration received June 18, 2008 from Craig Donohue filing request for Intervenor status 

 C8‐1  COMMERCIAL ENERGY CONSUMERS ASSOCIATION OF BC  (CECBC) ‐  Letter dated June 18, 

2008 from Christopher Weafer, Owen Bird, legal counsel, filing request for Registered Intervenor status and comments 

C8‐2  Letter dated July 25, 2008 filing Information Request No. 1 to Terasen 

C8‐3  Letter dated August 27, 2008 from Christopher Weafer, Owen Bird, legal counsel, filing comments on further procedural process 

APPENDIX 1 Page 5 of 6 

 Exhibit No.  Description   C9‐1  DIRECT ENERGY MARKETING  LIMITED (DEML) ‐  Online web registration dated June 25, 

2008 from Chad Painchaud, filing request for Registered Intervenor status  

 LETTERS OF COMMENT  E‐1  CANADIAN MORTGAGE AND HOUSING CORPORATION (CMHC – SCHL) ‐ Letter of Comment 

dated June 16, 2008, faxed from Lance Jakubec, Senior Research Consultant, in support of the application 

E‐2  CITY GREEN SOLUTIONS – Letter of Comment received June 17, 2008 from Peter Sundberg, Executive Director 

E‐3  LIGHT HOUSE SUSTAINABLE BUILDING CENTRE ‐ Letter of Comment received June 17, 2008 from Helen Goodland 

E‐4  CANADIAN HOME BUILDERS’ ASSOCIATION (VICTORIA) (CHBA)‐ Letter of Comment received June 18, 2008 from Casey Edge, Executive Officer 

E‐5  HEARTH, PATIO & BARBECUE ASSOCIATION OF CANADA (HPBAC) ‐ Letter of Comment received June 18, 2008 from Tony Gottschalk, Manager 

E‐6  FRASER BASIN COUNCIL – Letter of Comment received June 20, 2008 from Bob Purdy, Director, Corporate Development & Communications 

E‐7  PACIFIC RESOURCE CONSERVATION SOCIETY – Letter of Comment received June 24, 2008 from Darla Simpson, Executive Director 

E‐8  CANADIAN HOME BUILDERS’ ASSOCIATION (KAMLOOPS) (CHBA) ‐ Letter of Comment dated June 25, 2008 from Patsy Bourassa, Executive Officer 

E‐9  URBAN DEVELOPMENT INSTITUTE – PACIFIC REGION (UDI) ‐ Letter of Comment dated July 3, 2008 from Jeff Fisher, Deputy Executive Director 

E‐10  FRASER VALLEY HOME BUILDERS ASSOCIATION (FVHBA) ‐ Letter of Comment dated July 8, 2008 from Jan Field, Executive Officer 

E‐11  CANADIAN MANUFACTURERS & EXPORTERS – BC DIVISION ‐ Letter of Comment dated July 5, 2008 from Craig Williams, Vice President 

E‐12  NATURAL RESOURCES CANADA ‐ Letter of Comment dated July 9, 2008 from John Cockburn, Director, Office of Energy Efficiency 

APPENDIX 1 Page 6 of 6 

 Exhibit No.  Description  E‐13  CANADIAN HOME BUILDERS ASSOCIATION OF BC (CHBA BC) ‐ Letter of Comment dated July 

8, 2008 from M.J. Whitemarch, Chief Executive Officer 

E‐14  CITY OF NANAIMO ‐ Letter of Comment dated July 10, 2008 from Gary Korpan, Mayor 

E‐15  CITY OF VICTORIA ‐ Letter of Comment dated July 15, 2008 from Alan Lowe, Mayor 

E‐16  CITY OF LANGFORD ‐ Letter of Comment dated July 22, 2008 from Rob Buchan, Clerk‐Administrator 

E‐17  TOWN OF LADYSMITH – Letter of Comment dated July 24, 2008 from Mayor Robert Hutchins 

E‐18  CORPORATION OF THE VILLAGE OF CUMBERLAND ‐ Letter of Comment dated July 18, 2008 from Christine Makarowski, Corporate Services Manager 

E‐19  THE CORPORATION OF THE CITY OF NORTH VANCOUVER ‐ Letter of Comment dated July 29, 2008 from Darrell Mussatto, Mayor 

E‐20  THE CORPORATION OF THE DISTRICT OF WEST VANCOUVER ‐ Letter of Comment dated July 30, 2008 from Clay Nelson, Manager 

E‐21  BROOK + ASSOCIATES INC.  ‐ Letter of Comment dated July 2, 2008 from Blair Chisholm, Planning Manager 

E‐22  CITY OF POWELL RIVER ‐ Letter of Comment dated July 30, 2008 from Mair Claxton, City Clerk 

E‐23  CORPORATION OF DELTA ‐ Letter of Comment dated July 30, 2008 from Lois E. Jackson, Mayor 

E‐24  BC CHAMBER OF COMMERCE ‐ Letter of Comment dated August 11, 2008 from John R. Winter, President & CEO 

E‐25  CANADIAN GAS ASSOCIATION ‐ Letter of Comment dated August 14, 2008 from Michael Cleland, President & CEO 

E‐26  CITY OF SURREY ‐ Letter of Comment dated August 11, 2008 from Dianne L. Watts, Mayor 

E‐27  BUSINESS COUNCIL OF BRITISH COLUMBIA ‐ Letter of Comment dated August 15, 2008 from Virginia Greene, President & CEO 

 

                    

SIXTH FLOOR, 900 HOWE STREET, BOX 250 VANCOUVER, B.C.  V6Z 2N3   CANADA 

web site: http://www.bcuc.com 

    

  

 BRIT I SH  COLUMBIA  

UTIL I T I ES  COMMISS ION      ORDER    NUMBER   G‐141‐09  

 TELEPHONE:  (604)  660‐4700 BC TOLL FREE:  1‐800‐663‐1385 FACSIMILE:  (604)  660‐1102 

 

. . . /2 

IN THE MATTER OF the Utilities Commission Act, R.S.B.C. 1996, Chapter 473 

 and  

An Application by Terasen Gas Inc. for Approval of 2010 and 2011 Revenue Requirements and Delivery Rates 

  

BEFORE:  A.W.K. Anderson, Panel Chair/Commissioner   D.A. Cote, Commissioner  November 26, 2009   M.R. Harle, Commissioner  

O R D E R  

WHEREAS: A. On June 15, 2009 Terasen Gas Inc. (“Terasen Gas”) filed an application for approval of interim and permanent delivery 

rates effective January 1, 2010 and January 1, 2011 (the “Application”) pursuant to sections 59 to 61 and 89 of the Utilities Commission Act (the “Act”), representing an increase of 5.3 percent for 2010 and 4.1 percent for 2011; and  

B. Terasen Gas sought other approvals in the Application, including Orders pursuant to sections 59 to 61 of the Act, approving Tariff changes effective January 1, 2010 for Compression and Refueling and Transportation Services for Natural Gas Vehicles and economic models for evaluating biogas projects and alternative energy extensions for geo‐exchange, solar thermal and district energy systems to complement its core natural gas business; and 

 C. The interim and permanent delivery rates sought in the Application are subject to adjustment for any changes in 

Terasen Gas’ allowed return on equity and capital structure; and  D. Terasen Gas proposed a written hearing process to address the Application but was open to a Negotiated Settlement 

Process (“NSP”) addressing all of the issues; and  E. In accordance with Commission Order G‐76‐09, a Workshop was held July 6, 2009 for a review of the Application and a 

first Procedural Conference was held on July 15, 2009.  Commission Order G‐89‐09 established the requirement for a second Procedural Conference, held on September 25, 2009 to address the regulatory process and preliminary timetable; and 

 F. At the second Procedural Conference, the Commission Panel received submissions on the principal issues arising from 

or related to the Application, process options for the review of the Application, location of the proceedings and other matters that would assist the Commission’s efficient review of the Application.  The primary issues raised were whether a separate Certificate of Public Convenience and Necessity (“CPCN”) review was required for the Alternative Energy Solutions proposed in the Application and whether the regulatory process should be in the form of an oral or written hearing or NSP; and 

   

         

2   

ORDERS/G‐141‐09_TGI 2010‐2011RR NSP 

 BRIT I SH  COLUMBIA  

UTIL IT I ES  COMMISS ION      ORDER    NUMBER   G‐141‐09  

G. The Intervenors expressed a wish to avoid a separate CPCN process for the Alternative Energy Solutions and all Intervenors supported an NSP for the review of the Application.  The Intervenors submitted that, in the event that the NSP is not successful in resolving all issues, an Oral Public Hearing could be ordered by the Commission.  Terasen Gas requested that, if an Oral Public Hearing is established, it be limited in scope; and  

H. Terasen Gas proposed that its application for interim rate approval be deferred until the end of November 2009; and  I. By Order G‐119‐09, the Commission Panel established a regulatory timetable for an NSP commencing October 21, 

2009.  The settlement discussions concluded on November 3, 2009; and  J. On November 13, 2009, the Negotiated Settlement Agreement (“NSA”), together with the Letters of Support received 

from the participants in the NSP, the Letter of Comment from Commission Staff and Terasen Gas’ response to the Letter of Comment (“Settlement Package”), was made public and circulated to the Commission Panel; and 

 K. The Settlement Package was also distributed to Registered Intervenors who did not participate in the NSP (“Other 

Intervenors”).  The Other Intervenors were requested to provide their comments on the Settlement Package to the Commission by November 20, 2009.  The Commission Panel received no comments from Other Intervenors regarding the Settlement Package; and 

 L. The Commission Panel having reviewed the proposed NSA and the comments related thereto and noting the support of 

all parties to the proposed Negotiated Settlement Agreement, in which only sections 12(a) and (b) are severable, subject to the implementation of section 12.2, considers that approval is warranted. 

  NOW THEREFORE pursuant to sections 59 to 61 and 89 of the Act the Commission orders as follows:  1. The Negotiated Settlement Agreement attached as Appendix A to this Order is approved. 

 2. TGI is to file an amended Summary of Rates and Bill Comparison schedules based on the Negotiated Settlement 

Agreement.  3. The Commission will accept, subject to timely filing by TGI, amended permanent Gas Tariff Rate Schedules in 

accordance with the terms of this Order.  TGI is to provide notice of the permanent rates to customers via a bill message, to be reviewed in advance by Commission Staff to confirm compliance with this Order. 

  DATED at the City of Vancouver, In the Province of British Columbia, this             26th              day of November 2009.    BY ORDER    Original signed by:    A.W.K. Anderson   Panel Chair/Commissioner  Attachment  

APPENDIX A to Order G-141-09 Page 1 of 110

– 1 –

CONFIDENTIAL NEGOTIATED SETTLEMENT AGREEMENT

TERASEN GAS INC. DATED THURSDAY, NOVEMBER 5

IN THE MATTER OF

the Utilities Commission Act, R.S.B.C. 1996, Chapter 473

and

An Application by Terasen Gas Inc. for Approval of 2010 and 2011 Revenue Requirements and Delivery Rates

Negotiated Settlement Process

WHEREAS:

A. On June 15, 2009, Terasen Gas Inc. (“TGI”) filed its 2010 and 2011 Revenue Requirements Application, which was supplemented by a filing on July 9, 2009 and amended by filings on August 14 and September 18, 2009 (the “Application”); and

B. Amongst other things, the Application sought:

1. An order pursuant to sections 59 to 61 of the Utilities Commission Act (the “Act”), approving delivery rates for all non-bypass customers effective January 1, 2010 and January 1, 2011, representing an increase of 5.3 percent for 2010 and an additional 4.1 percent for 2011, subject to changes in TGI’s allowed return on equity (“ROE”) and capital structure; and

2. An order pursuant to section 44.2 of the Act approving an expenditure schedule for the continuation in 2011 of TGI’s residential and commercial Energy Efficiency and Conservation ("EEC") funding, as well as new EEC funding for 2010 and 2011 for interruptible industrial programs and innovative technologies; and

3. New tariff offerings and economic tests for Compression and Refuelling and Transportation Services for Natural Gas Vehicles ("NGV"), geo-exchange, solar thermal and district energy systems and a pilot program for Biogas; and

C. A complete listing of the relief sought by TGI in the Application was included in Section D (pages 513-516)1 of the Application; and

D. In accordance with Commission Order No. G-76-09 issued on June 19, 2009, a Workshop was held on July 6, 2009 for a review of the Application, a procedural conference was held on July 15, 2009, and TGI responded to two rounds of Information Requests; and

E. In accordance with Commission Order No. G-89-09 issued on July 20, 2009, a second procedural conference was held on September 25, 2009; and

1 Page 516 of the Application was amended on September 18, 2009.

APPENDIX A to Order G-141-09 Page 2 of 110

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CONFIDENTIAL NEGOTIATED SETTLEMENT AGREEMENT

TERASEN GAS INC. DATED THURSDAY, NOVEMBER 5

F. On October 2, 2009, the Commission issued Order G-119-09 establishing a Negotiated Settlement Process (“NSP”) for the Application; and

G. The Parties to the NSP were TGI, British Columbia Old Age Pensioners et al. (“BCOAPO”), Commercial Energy Consumers Association of British Columbia (“CEC”), Teck Coal Ltd. (“Teck”), and the Ministry of Energy, Mines and Petroleum Resources (“MEMPR”) (collectively referred to in this Agreement as the “Parties”); and

H. At the outset of the NSP on October 21, 2009, Commission Staff provided the Parties with a document prepared by the Commission Panel titled “Issues of Particular Concern to the Commission Panel”, a copy of which is appended as Appendix 1 to this Agreement; and

I. The NSP was held on October 21-23, 30, and November 3 and 4, 2009; and

J. The Parties have negotiated in good faith to achieve a compromise settlement, reflected in this Agreement, of the issues raised by the Application, and the Commission Panel document referenced in recital H above, and further consider the Agreement reached to be fair, just and reasonable; and

K. This Agreement consists of four Parts:

Part I includes general provisions;

Part II includes the items agreed to that differ from what was requested in the Application;

Part III includes the items agreed to that remain as proposed by TGI in the Application; and

Part IV includes revised financial schedules reflecting all items set out in the Agreement.

NOW THEREFORE THE PARTIES AGREE AS FOLLOWS

PART I – GENERAL

1. Agreement a Product of Compromise The Parties recognize and emphasize that this Agreement is the product of compromise on the part of all Parties, yielding an overall package that the Parties consider to be fair, just and reasonable. The Parties agree that any compromises resulting from this Agreement are without prejudice to the Parties’ ability to take different positions after 2011 and without prejudice to the Parties right to intervene in any applications contemplated in or resulting from this Agreement.

APPENDIX A to Order G-141-09 Page 3 of 110

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CONFIDENTIAL NEGOTIATED SETTLEMENT AGREEMENT

TERASEN GAS INC. DATED THURSDAY, NOVEMBER 5

2. Whole Agreement Unless otherwise stated in this Agreement, portions of this Agreement cannot be removed or changed by the Commission without nullifying the whole Agreement.

3. TGI to Manage Business The Parties agree that TGI will have the discretion to manage its business and determine how best to allocate the overall O&M and Capital expenditures stipulated in this Agreement.

4. Final IFRS Rate-regulated Activity Standard The Parties acknowledge that this Agreement is predicated on the Final IFRS Rate-regulated Activity Standard permitting the financial accounting treatment contemplated in this Agreement in the manner outlined in the current Exposure Draft on Rate-regulated Activities. The Parties agree that if, in TGI’s opinion, the Final IFRS Rate-regulated Activity Standard differs from the current Exposure Draft on Rate-regulated Activities so as not to permit the financial accounting treatment contemplated in this Negotiated Settlement Agreement, which among other things anticipates the recognition of regulatory assets and liabilities for external reporting purposes, then TGI is at liberty to apply to the Commission during the period of this Agreement for a determination of that issue, and to seek changes in the regulatory treatment contemplated in this Agreement to accord with the Final IFRS Rate-regulated Activity Standard, with the resulting impacts flowed through into rates commencing in 2011.

PART II – AGREED CHANGES FROM THE APPLICATION

5. Delivery Rates The Delivery rate changes for 2010 and 2011 that would flow from this Agreement would be a decrease of 1.73 per cent in 2010 and an increase of 3.93 per cent in 2011, subject to being updated as contemplated in this Agreement. Issue No. 5 in the Commission Panel’s “Issues of Particular Concern to the Commission Panel” stated:

“2010 Rate Changes – in the event that a 2010 rate reduction were to occur as a result of negotiations, the current rates should remain unchanged and place the revenue surplus into a deferral account to apply against 2011 and future rate increases with a phase in amortization that strives for rate stability.”

Therefore, the Parties agree that this Agreement will not result in a decrease in delivery rates for 2010 and that the 2010 forecast revenue surplus will be recorded in a 2010 Revenue Surplus Deferral Account and be applied to offset any forecast increase in delivery rates in 2011. The forecast 2010 revenue surplus of $9.2 million per Schedule 1 included in Part IV of this Agreement, is recorded in the 2010 Revenue Surplus Deferral Account, which

APPENDIX A to Order G-141-09 Page 4 of 110

– 4 –

CONFIDENTIAL NEGOTIATED SETTLEMENT AGREEMENT

TERASEN GAS INC. DATED THURSDAY, NOVEMBER 5

will be amortized in 2011 to reduce the 2011 forecast revenue deficit. The 2010 Revenue Surplus Deferral Account will be included in Rate Base. However, the delivery rates for 2010 and 2011 will be updated to reflect changes in TGI’s allowed ROE and capital structure flowing from the Commission’s decision in TGI’s concurrent ROE and Capital Structure Application2, or as adjusted from time to time by the Commission. Nothing in this Agreement precludes TGI from applying to the Commission in 2010 or 2011 for changes to its allowed ROE and capital structure.

6. Service Quality Indicators The Parties agree that TGI will report on the same SQI’s as set out in the 2004-2007 PBR Agreement and the 2008-2009 extension thereof through quarterly postings on TGI’s website.

7. Customer Additions Forecast The Parties agree that TGI’s net Residential customer additions forecast is revised to be 5,952 in 2010 (increase of 352 from Application3) and 6,166 in 2011 (increase of 316 customers from the number specified in the Application), reflecting the updated published CMHC Q3 2009 forecast, and TGI’s year end 2009 number of customers has additionally been updated to be 835,862. Customer additions for the other rate classes remain unchanged from what was specified in the Application4.

8. Use Per Customer Rates The Parties agree that the Residential annual use per customer is revised upward from 89.7 GJ to 91.7 in 2010 and from 88.3 to 90.3 in 2011. Use per customer rates for the other rate classes remain unchanged from what was included in the Application (other than Industrial as set out in item 9).

9. Industrial Demand Forecast The Parties agree that the industrial demand forecast is revised upwards from what was requested in the Application based on responses TGI has since received from the 2009 Industrial Survey and actual year-to-date demand. The revised industrial demand forecast includes forecast demand of 46.5 PJ and 46.5 PJ (compared to 43.4 PJ and 43.3 PJ as presented in the Application) for 2010 and 2011 respectively.

2 Filed jointly by the Terasen Utilities [TGI, Terasen Gas (Vancouver Island) Inc. and Terasen Gas (Whistler) Inc.] on

May 15, 2009. 3 See Application, page 276 4 IBID

APPENDIX A to Order G-141-09 Page 5 of 110

– 5 –

CONFIDENTIAL NEGOTIATED SETTLEMENT AGREEMENT

TERASEN GAS INC. DATED THURSDAY, NOVEMBER 5

10. Inclusion of SCP Capacity in MCRA The Parties agree that TGI will continue for 2010 and 2011 to include in the MCRA the $3.6 million representing the annual cost of Southern Crossing Pipeline (SCP) capacity, because the benefits and use of the SCP capacity are used by Core Market Customers (Rate Schedules 1-7).

11. Energy Efficiency and Conservation (“EEC”) Funding for 2010

The Parties agree as follows in respect of the EEC funding sought by TGI for 2010:

(a) TGI will reallocate from residential and commercial EEC programs an additional $1.6 million from the amount approved for 2010 in the EEC Decision5 to low income and rental housing programs. This brings the total for low income and rental housing programs to $2.4 million for 2010.

(b) EEC funding for industrial interruptible programs for 2010 will be $435,000, which is the

amount requested by TGI in the Application. (c) EEC funding for innovative technologies will be $2.3 million for 2010, which is the

amount requested by TGI in the Application.

(d) All agreed to EEC expenditures will be considered and evaluated within the existing portfolio, and be subject to the same financial treatment, as per the Commission’s EEC Decision dated April 16, 2009 (Application, page 514, Item 6). However, Innovative Technology programs will be managed by TGI as a separate segment of the overall portfolio to have a weighted average Total Resource Cost (“TRC”) of 1.0 or more. TGI will consult with stakeholders on the practical application of the weighted average TRC through the EEC Advisory Committee.

12. EEC Funding for 2011

12.1 The Parties agree as follows in respect of the EEC funding sought by TGI for 2011:

(a) EEC funding for residential and commercial programs for 2011 will be $23.075 million, which is the amount requested by TGI in the Application.

(b) TGI will reallocate from 2011 residential and commercial EEC funding ($23.075M for 2011) an additional $1.6 million (from the $0.8 million included in the Application) to low income and rental housing programs. This brings the total for low income and rental housing programs to $2.4 million for 2011.

5 Decision and Order No. G-36-09 dated April 16, 2009 in the TGI-TGVI Energy Efficiency and

Conservation Application

APPENDIX A to Order G-141-09 Page 6 of 110

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CONFIDENTIAL NEGOTIATED SETTLEMENT AGREEMENT

TERASEN GAS INC. DATED THURSDAY, NOVEMBER 5

(c) EEC funding for industrial interruptible programs will be $1.875 million for 2011, which is the amount requested by TGI in the Application.

(d) EEC funding for innovative technologies will be $4.669 million for 2011, which is the amount requested by TGI in the Application.

(e) All agreed to EEC expenditures will be considered and evaluated within the existing

EEC portfolio, and will be subject to the same financial treatment, as per the Commission’s EEC Decision dated April 16, 2009 (Application, page 514, Item 6). However, Innovative Technology programs will be managed by TGI as a separate segment of the overall portfolio to have a weighted average TRC of 1.0 or more. TGI will consult with stakeholders on the practical application of the weighted average TRC through the EEC Advisory Committee.

(f) TGI will report to the Commission on industrial interruptible and innovative technology programs as part of TGI’s annual report on EEC activities required under the EEC Decision.

The Parties offer the following rationale for the agreed upon 2011 EEC funding. All Parties agree that it is important to maintain EEC funding levels in 2011 to allow customers to have continued access to EEC programs and incentives. The residential and commercial EEC programs relating to the $23.075 million funding in 2011 on a portfolio basis in aggregate have a TRC of one or more. This means that, from a resource perspective and on a portfolio basis, these programs are expected to yield favourable results for customers. The predictability and continuity of these programs on a sustained basis is critical to their overall success. Issue No. 1 in the Commission Panel’s “Issues of Particular Concern to the Commission Panel” stated:

“EEC Program – TGI is to provide results of programs approved by the EEC Decision and expectations for new programs before the Commission Panel will approve additional EEC program funding.”

There are practical difficulties associated with the approach identified by the Commission Panel. They include the following: • As per the EEC Decision (Order No. G-36-09), TGI will be reporting 2009 activities

and results by no later than March 31, 2010. This report will also outline the forecasted activities and programs for 2010. Recognizing the timing of the recent EEC Decision and its current implementation in the Fall of 2009, the EEC Report for 2009 results will give the Commission and stakeholders another check point to validate the level of spend for 2011. However, there is expected to be very little additional information on the results of programs available in March 2010 than exists presently and is included in the evidentiary record of this proceeding. TGI’s

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EEC programs only completed start up phase in the Fall of 2009. It typically takes longer than 6-8 months to achieve momentum with EEC programs. There will be no information available in March 2010 on results for industrial programs or programs relating to innovative technologies initiated in 2010 as a result of this Agreement. The information that the Commission Panel appears to desire will be more likely included in TGI’s 2010 results report to be filed in March 2011.

• Employees responsible for the programs at TGI, whose salaries are funded from EEC funding, will face the prospect of losing their jobs in 2011. This could lead to employee retention issues. Employee turnover issues may disrupt the program implementation progress and potentially be more costly if EEC activity is ceased and later resumed.

• Programs will need to begin winding down in advance of 2011 if the 2011 funding is not approved. For example, programs will need to have an end date of December 31, 2010 which may not yield positive results since programs will be winding up in the middle of the heating season.

12.2 The Parties agree that the Commission may sever Section 12.1 (a) and (b) above from

this Agreement, with the remainder of this Agreement remaining in force and effect. If the Commission severs Section 12.1 (a) and (b), then the Parties agree that the following provisions take effect:

(a) The Residential and Commercial EEC programs totaling $23.075 million in 2011

will be removed from the EEC expenditure forecast and the revenue requirements for 2011. (If 12.2 takes effect, the financial schedules in Part IV of this Agreement and the revenue requirements resulting from this Agreement will be revised to reflect this).

(b) The Parties agree that the first annual report on EEC Activities, which was due to be filed on March 31, 2010 pursuant to Order No. G-36-09, can be filed on or before June 30, 2010. Concurrent with that report, TGI will file an application with the anticipation of a decision within 120 days after filing. The application will include requests for:

i. approval of the above EEC funding for 2011;

ii. approval of the same financial treatment approved in the EEC Decision; and

iii. approval for the continuation of the portfolio approach and assessment methodology as approved in the EEC Decision.

13. Alternative Energy Solutions Alternative Energy Solutions (“AES”) means Geo-exchange, Solar-thermal and District Energy Systems as those terms are described in the Application.

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Natural Gas service taken in combination with AES will be charged under TGI’s natural gas rates. The Parties agree that the costs incurred by TGI to provide AES should not be recovered as part of natural gas service rates, and visa versa. The Parties agree that TGI’s proposed New Energy Solutions Deferral Account, attracting AFUDC, is an appropriate mechanism to address allocation issues as between TGI’s gas customers and TGI’s AES customers. Therefore, the Parties agree that the new Energy Solutions Deferral Account will remain in effect pending a future rate design application at an unspecified future date after 2011 and will capture and record the following (plus AFUDC) to be recovered from AES customers: (a) Direct costs associated with AES projects as outlined on pages 267-268 of the

Application, including cost of design, equipment, etc. constructing and financing; and

(b) Sales and marketing O&M and other development costs will be directly charged to the deferral account by time sheets or other direct charge (estimated at $1.0 million in 2010 and $1.5 million in 2011, representing a portion of the agreed upon Gross O&M reduction from gas customers of $4.0 million in 2010 and $5.5 million in 2011); and

(c) An appropriate overhead allocation, which the parties have agreed will be $500,000 in each of 2010 and 2011 (representing a portion of the agreed upon Gross O&M reduction from gas customers of $4.0 million in 2010 and $5.5 million in 2011).

Revenues received from customers for all AES projects, which are based on contracts approved by Commission will be recorded in the AES deferral account.

The risk of non-recovery of amounts in the New Energy Solutions Deferral Account will not be borne by natural gas ratepayers. The Parties agree that any debit balance in the New Energy Solutions Deferral Account will not be recovered through natural gas rates and any credit balance will not be applied to reduce natural gas rates. In evaluating AES projects, TGI will apply the economic test outlined in the Application. The Parties agree that the proposed GT&C (Section 12A – Alternative Energy Extensions) are acceptable. Pursuant to the Utilities Commission Act, within the Alternative Energy class of service, project-specific contracts with AES customers will be filed with the Commission for acceptance as a rate, at which time the Commission may review and adjust the economic test and GT&C Section 12A – Alternative Energy Extensions. The CPCN threshold of $5 million applies to AES projects brought forward in 2010 and 2011. The Parties agree that it is premature to address issues relating to the gas load and gas consumption profiles of AES projects that incorporate a natural gas component. Such issues are appropriately addressed in a future rate design application, once TGI has sufficient AES customers that take gas so as to provide reliable information on gas load and gas consumption profiles.

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TGI will capture costs and revenue on a project specific basis and will report on AES projects as part of the next Revenue Requirements application.

14. Natural Gas for Vehicles (“NGV”) The Commission Issue No. 2 in the Commission Panel’s “Issues of Particular Concern to the Commission Panel” stated:

“Natural Gas Vehicles (“NGV”) – if NGV is to proceed why should the natural gas ratepayer fund this initiative rather than Terasen’s non-regulated businesses or the competitive market?”

The Parties agree: (a) NGV Rate Schedule 26 - NGV Transportation Service should be approved as filed.

(b) The marketing costs in support of NGV that are included in the revenue requirements Application are appropriately recoverable in 2010 and 2011 rates.

(c) Upon acceptance of this Agreement by the Commission, TGI withdraws its request in this Application for the following:

i. Rate Schedule 6C NGV Compression and Refueling Service and 6A NGV Refueling Service; and

ii. the Compression Service (“CS”) Test; and

iii. NGV non-rate base deferral account.

The Parties acknowledge that these requests are being withdrawn by TGI to facilitate a settlement on other issues presented in this Application. The Parties agree that TGI’s withdrawal of its requests regarding NGV is without prejudice to TGI’s right to bring forward similar requests in 2010 or 2011 or otherwise in the future. The Parties acknowledge that TGI intends to develop this area of business and that TGI anticipates it will bring forward applications on NGV projects to the Commission on a case-by-case basis during the term of this Agreement and in future years. The Parties agree that TGI is at liberty to do so.

15. Biogas Issue No. 3 in the Commission Panel’s “Issues of Particular Concern to the Commission Panel” stated:

“Biogas – to be reviewed by a CPCN which demonstrates market uptake of customers that are willing to pay the full cost.”

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The Parties agree that, upon acceptance of this Agreement by the Commission, TGI withdraws its requests in this Application related to Biogas. The Parties acknowledge that these requests are being withdrawn to facilitate a settlement on other issues presented in this Application. The Parties agree that TGI will bring forward an application (the “Biogas Application”) during the test period that will: (a) Address the economic assessment model; and

(b) Provide Biogas rates (including green rate, transportation rate, etc.); and

(c) Provide for recovery of costs associated with providing Biogas service. TGI may include in the Biogas Application any Biogas Projects under development at that time. TGI is, however, not precluded from applying for Commission approval in respect of individual Biogas Projects at any time, either prior to the Biogas Application or afterwards.

16. CPCN Threshold Issue No. 6 in the Commission Panel’s “Issues of Particular Concern to the Commission Panel” stated:

“CPCN threshold – stay at $5 million.” The Parties accordingly agree that the CPCN threshold will remain at $5 million for 2010 and 2011. TGI’s Category B Capital Expenditures forecast for the forecast period will be revised to reflect this change (please see item 18 below).

17. Category A Capital The Parties agree that Category A Capital will be $43.3 million for 2010 and $46.0 million for 2011, reflecting the proposed amount updated to reflect the published CMHC Q3 2009 forecast, and TGI’s adjusted re-forecasted year end net customer addition numbers (as set out in item 7).

18. Category B and Category C Capital As a consequence of the CPCN threshold being established at $5 million for 2010 and 2011 (see item 16 above), TGI will file CPCN applications for the Huntingdon and Kootenay Crossing projects identified in TGI’s Application. The Category B Capital will consequently be reduced by $2.2 million in 2010 and $16.0 million in 2011. TGI will seek deferral treatment for 2011 of the capital costs associated with those projects at the time of filing the CPCN Applications. The Parties agree that Category B and C Capital will be reduced by a total of $3 million in each of 2010 and 2011. For the purposes of the determination of revenue requirements

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with this Application, Category B Capital has been reduced by $1 million and Category C IT Capital has been reduced by $2 million. The revised Category B Capital Expenditures, reflecting both the CPCN adjustment and the $1 million reduction in spending, are now $17.4 million in 2010 and $14.9 million in 2011. The revised Category C Capital Expenditures, reflecting the $2 million IT Capital reduction, are now $32.8 million in 2010 and $32.7 million in 2011.

19. Gross O&M (to be recovered from gas customers) The Parties agree that the proposed gross O&M, before shared service allocations, recoverable from gas customers for 2010 and 2011 is reduced from the amounts included in the original Application by $4.0 million in 2010 and a further $1.5 million (for a total impact of $5.5 million) in 2011. This reduction of Gross O&M will result in a reduction in the pool of costs subject to the Shared Services Agreement with TGVI and with TGW by an estimated $3.3 million in 2010 and $4.8 million in 2011. Therefore, and as discussed in Item 21, the final Gross O&M to be included in TGI’s cost of service for 2010 and 2011 will be determined based on the Shared Services and Corporate Services allocations determined in the TGVI RRA.

20. Interest Expense The Parties agree that TGI will update its assumptions around both the issuance of long-term debt and the associated interest rates. TGI has determined that Long-term Debt Series 25 will not be issued December 1, 2009 as originally forecast and is now anticipated to be issued April 1, 2010. In addition, the interest rate forecast for Long-term Debt Series 26, to be issued July 1, 2011, has been revised downwards from 6.13 per cent to 5.65 per cent.

21. Shared Services/Corporate Services Allocations The 2010 and 2011 revenue requirements stipulated in this Agreement are based on TGI’s proposed Shared Services and Corporate Services allocation for 2010 and 2011. The Parties acknowledge, however, that the final amount allocated to TGI for Shared Service and Corporate Services cannot be confirmed until the Commission determines the TGVI RRA. The Parties agree that if the amounts allocated to TGVI for Shared Services and/or Corporate Services for 2010 or 2011 changes from that agreed to in this Agreement as a result of a settlement or decision in the concurrent TGVI RRA proceeding, then the amount(s) allocated to TGI and its revenue requirements for 2010 and 2011 will be updated by a corresponding amount to ensure recovery of all of the combined Corporate Services and Shared Services costs.

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22. Depreciation Study The Parties agree that the depreciation rates specified in the Gannett Fleming study included the Application under Appendix H-2 for Parts I-III, and in the Supplemental filing dated July 8, 2009 for Parts IV and V, will be implemented effective January 1, 2010, with the exception of: (a) Masonry Structures, which has been updated to 40 years instead of 22.88 years; and

(b) the component of those rates that represent recovery of negative salvage (see item 23 below).

Adjusting for the Masonry Structures, negative salvage, and the impacts of capitalized overhead and capital additions changes yields total depreciation expense of $98.3 million in 2010 and $100.5 million in 2011, of which approximately $6.3 million results from the updated Gannett Fleming depreciation study. The Parties agree that TGI will undertake an updated depreciation study to be included as part of TGI’s next Revenue Requirements Application. This study will address the methodology and rates for net negative salvage to be included in cost of service for future periods. TGI will work with Commission staff and a depreciation rate specialist in determining the requirements of the study.

23. Negative Salvage Values On an annual basis, TGI includes a provision for estimated net negative salvage value (removal costs less proceeds) in its depreciation rates. This treatment recognizes that net negative salvage value is a cost of providing service using the asset and should be recovered from customers over the useful life of the asset. An alternative treatment is to recover the net negative salvage values at the time they are incurred resulting in future customers paying for the removal costs, which TGI views as inappropriate. The inclusion of a provision for estimated net negative salvage value in depreciation rates is a practice that has been followed by TGI historically, and with this RRA TGI had proposed continuation of this treatment. This treatment is consistent with the BCUC Uniform System of Accounts and is generally followed by other investor-owned utilities in British Columbia and across Canada. The Parties agree that for the purposes of the two year period covered by this Agreement, the provision for net negative salvage (net removal costs) will be removed from the depreciation estimates. Instead, an estimate of the amount of net removal costs to be incurred in each of the years 2010 and 2011 ($8.038 million and $11.29 million) will be included in the cost of service and recovered from customers in each of those years. Any variances between the actual amount of net removal costs realized and the estimated amounts included in cost of service will be recorded in a new deferral account created for this purpose that will be called the “Removal Cost Deferral Account”. The amount accumulated in the Removal Cost Deferral Account over the two year period of this Agreement will be recovered from (or returned to) customers in 2012.

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TGI continues to be of the position that removal costs should be recovered over the service life of the asset and not at the time the removal costs are actually incurred. TGI will work with Commission staff and a depreciation rate specialist in determining both the methodology and estimates for the removal costs and include the documentation to support the rates in its next depreciation study filed as part of its next Revenue Requirement Application.

24. Unrecovered Losses Issue No. 7 in the Commission Panel’s “Issues of Particular Concern to the Commission Panel” stated:

“Unrealized losses in rate base – should some of these losses be to the shareholder? Parties should present a separate settlement package.”

Unrealized (unrecovered) losses relate to Unrecovered Depreciation on assets used 100 per cent for the provision of utility service to ratepayers (as discussed in the response to BCUC IR 2.131.1.4). The Parties agree that the treatment for unrecovered losses as proposed in the Application is acceptable for the 2010 and 2011 period covered by this agreement. TGI will work with Commission staff and a depreciation rate specialist in determining both the methodology and estimates for the unrecovered losses and include the documentation to support the rates in its next depreciation study filed as part of its next Revenue Requirement Application.

25. Changes to CCA Rates TGI amended its 2007 and 2008 tax returns to reflect changes to CCA rates announced in 2007 but not enacted until 2009. TGI proposed this benefit be shared in accordance with the terms of the PBR settlement. Some Parties have expressed the view, however, that all of the benefit should have been flowed through to customers via the Tax Deferral Account. The Parties, acting in good faith, have concluded that they have a fundamental and legitimate disagreement regarding the terms of the 2004-2009 PBR Settlement Agreement as it relates to the items to be included in the Tax Deferral Account. TGI has nevertheless agreed, as a compromise in furtherance of reaching an overall Agreement among the Parties, to include the full value of the incremental tax benefit associated with the difference in the CCA rates for 2007 and 2008 totalling $921,000 and remove the proposed 50% sharing benefit from the Earnings Sharing Mechanism.

26. Taxes – Tax Benefits Relating to Prior Periods – SCP Landscaping Costs TGI had proposed to accelerate the deduction of the remaining Regulatory Tax balance of SCP Landscaping costs (amounting to approximately $8.2 million) in 2009. That proposal would have resulted in the related tax benefit of approximately $2.4 million being flowed through the Earnings Sharing Mechanism pursuant to the PBR Settlement Agreement, resulting in a net benefit to customers of approximately $1.2 million.

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The Parties agree that, instead, TGI will continue to amortize the balance of SCP Landscaping costs for 2009 as contemplated in the approved rates for 2009 and consistent with prior years, resulting in a deduction of approximately $0.3 million for Regulatory Tax purpose in 2009 and a related tax benefit. TGI will then deduct the remaining balance (approximately $7.9 million) in 2010 with the full value of the remaining benefit (approximately $2.3 million) going to customers reflected as a reduction in revenue requirements in 2010. The Parties agree that the acceleration of this benefit to customers was the result of tax planning actions taken by TGI and acknowledge that the agreed upon treatment set out above reflects customers receiving 100% of the value of the deductions of the SCP Landscaping costs. The intervenor Parties to this Agreement will not seek any additional recovery in respect of SCP Landscaping costs.

27. Overheads Capitalized The Parties agree to a change in the overheads capitalized rate to 14 per cent of Gross O&M for 2010 and 2011 which reflects the approximate actual Overheads Capitalized rate for 2009.

28. International Financial Reporting Standards (“IFRS”) 2010 Impact Issue No. 4 in the Commission Panel’s “Issues of Particular Concern to the Commission Panel” stated:

“International Financial Reporting Standards (“IFRS”) – no IFRS impact in 2010.” The Parties agree to defer the 2010 revenue requirement impact of IFRS to be recovered in rates in 2011 (relating specifically to capitalization of the current service portion of pension and OPEB related costs; capitalization of inspection costs; and timing of depreciation expense) up to a maximum of $1.0 million. Amounts, if any, over $1.0 million would be deferred and recovered in rates after 2011 based on the amortization approved by the Commission at that time.

PART III – REQUESTS UNCHANGED FROM THE APPLICATION

The Parties agree to the following items set out in this section, which are consistent with the proposals in TGI’s Application.

29. Rate Proposals as per Application Part III, Section D .1 - Approvals Sought

The Parties agree to the following rate proposals, as set out in TGI’s Application:

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(a) Allocation of delivery margin rate changes - Annual margin increase allocated to variable (volumetric & demand) based delivery charges, with no change to fixed (basic and admin fee) charges in each year (Application Page 513, Item 1).

(b) Earnings Sharing Mechanism (ESM) rider (incl. end of term capital) - Change the ESM rate rider to be ($0.040)/GJ effective January 1st, 2010, and change the estimated ESM rate rider to be ($0.046)/GJ effective January 1st. 2011. ESM amount to include End of Term Capital phase out and to be amortized over two years. The final 2011 rider amount will be adjusted based on 2009 actual earnings. TGI will submit an application to change the 2011 ESM rate rider at the same time it submits its Q4 quarterly gas cost report in early December 2010 (Application Page 513, Item 3).

(c) Rate Stabilization Adjustment Mechanism (RSAM) rider - Change the RSAM rate rider to be ($0.053)/GJ effective January 1st, 2010 and change the estimated RSAM rate rider to be ($0.052)/GJ effective January 1st, 2011. The 2011 rider amount will be adjusted based on 2009 actual results and 2010 year to date actual results. TGI will submit an application to change the 2011 RSAM rate rider at the same time it submits its Q4 quarterly gas cost report in early December 2010 (Application - Page 514 Item 4).

30. Accounting Policy Changes as per Application Part III, Section D.1 - Approvals Sought - to be effective January 1, 2010

The Parties agree to the following accounting policy changes, as set out in TGI’s Application: (a) Training and Feasibility Study Costs to be treated as O&M expense, rather than capital

(Application Page 515 and 516, Item 11).

(b) Capitalization of Major Inspection Costs, including the creation of a new Asset Class (Application Page 515 and 516, Item 11).

(c) Capitalization of the Current Service portion of Pensions and OPEBs expense that is applicable to capital projects (Application Page 515 and 516, Item 11).

(d) Capitalization of Deprecation on Assets used in Construction (Application Page 515 and 516, Item 11).

(e) All capital expenditures, including CPCNs, to be included in plant in service (and rate base) in the month following the available-for-use date, with depreciation starting at that time (Application Page 515 and 516, Item 11).

(f) Treatment of Vehicle Lease as a capital lease and inclusion of the NBV of vehicles in rate base (Application Page 515 and 516, Item 11).

(g) Discontinuation the Software Tax Credit as part of the CIAC additions (Application Page 515 and 516, Item 11).

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31. Various Accounting Related Proposals as per Application Part III, Section D .1 - Approvals Sought effective January 1, 2010

The Parties agree to the following accounting related changes, as set out in TGI’s Application: (a) Adoption of the Cash Working Capital Lead/Lag Days as set out in the Lead/Lag study

(Application page 515, Item 8c).

(b) Consolidated Core Market Administration Expenses (for TGI, TGVI and TGW), including allocation percentages to TGVI and TGW (Application page 515, Item 8d).

(c) Modify the Pricing Methodology for Company Use Gas to be based on market-based Sumas pricing, rather than pricing for expired "netback" contracts (Application page 514, Item 7a).

(d) The MCRA will absorb any volumes not used or excess volumes required for company use gas, as opposed to the O&M costs being adjusted for the differences (Application page 514, Item 7b).

32. Tariff Change Proposals as per Application Part III, Section D .1 - Approvals Sought, Item 12 & 13

The Parties agree to the following Tariff changes, as set out in TGI’s Application:

(a) New NGV Transportation Service (RS 26)

(b) Revised Fee New Customer Application fee from $85 to $25

(c) Revised Fee Meter Testing fee from $30 to $60

33. Deferral Account Proposals as per Application Part III, Section D .1 - Approvals Sought, Item 10

The Parties agree to the continuation, modification or adoption of the following deferral accounts as set out in TGI’s Application: (a) Deferral Accounts - No Change:

i. CCRA, MCRA, RSAM, and associated Interest and Revelstoke Propane (Application pages 429 and 430, Items (1) (a), (1) (b), (1) (c), (1) (d), (1) (e)).

ii. NGV Conversion Grants (Application page 432, Item (2) (b)).

iii. Property Tax variance (Application page 433, Item (3) (a)).

iv. Insurance variance (Application page 433, Item (3) (b)).

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v. BCUC Levies variance (Application page 433, Item (3) (d)).

vi. Interest variance (Application page 434, Item (3) (e)).

vii. Olympic Security costs (Application page 434, Item (3) (g)).

viii. IFRS conversion costs (Application page 435, Item (3) (h)).

ix. Accounts Amortized in 2010 (Application page 438, Item (6) (a)).

x. SCP PST Reassessment (Application page 439, Item (6) (b)).

xi. Deferred Service Line Installation Fee (Application page 439, Item (6) (d)).

xii. ESM (Application page 440, Item (6) (e)).

(b) Deferral Accounts - Modified:

i. SCP Mitigation Revenues Variance Account - combine the two currently approved accounts into one account (Application page 431, Item (1) (f)).

ii. Pension & OPEB variance - modify to add OPEB (Application page 433, Item (3) (c)).

iii. Tax variance - broader (changes in tax laws, practices, reassessments) (Application page 434, Item (3) (f)).

iv. Pension and OPEB funding Differences - expand to include pension funding differences and include addition in rate base not net of tax (Application page 437, Item (5) (c)).

(c) Deferral Accounts - New:

i. Interest variance calculation on gas in storage inventory (Application page 434, Item (3) (e)).

ii. Costs of applications (CCE, ROE, RRA) (Application page 435, Item (4)).

iii. IFRS Transitional Deferral Account (Application page 435, Item (5) (a)).

iv. Gains and Losses on Asset Disposition (Application page 436, Item (5) (b)).

v. CCE CPCN Costs (incremental non-capital costs plus timing impacts) (Application page 437, Item (5) (d)).

vi. LILO Reassessment (Application page 439, Item (6) (c)).

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34. Transfer Pricing Policy (TPP) and Code of Conduct (COC) The Parties agree that the existing COC and TPP Policies will be maintained.

PART IV – REVISED FINANCIAL SCHEDULES

The revised Financial Schedules follow.

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Terasen Gas Inc. 2010-2011 Revenue Requirements Application

Negotiated Settlement Process

Issues of Particular Concern to the Commission Panel

In accordance with sections 3 and 9 of the Negotiated Settlement Process-Policy, Procedures and

Guidelines, the Commission Panel has identified the following issues of particular concern that parties

should be aware of during the negotiations:

1. EEC Program-TGI is to provide results of the programs approved by the EEC Decision and

expectations for new programs before the Commission Panel will approve additional EEC

program funding.

2. Natural Gas for Vehicles ("NGV")-if NGV is to proceed why should the natural gas ratepayer fund

this initiative rather than Terasen's non-regulated businesses or the competitive market?

3. Biogas-to be reviewed by a CPCN which demonstrates market uptake of customers that arewilling to pay the full cost.

4. International Financial Reporting Standards ("IFRS")-no IFRS impact in 2010.

5. 2010 Rate Changes-in the event that a 2010 rate reduction were to occur as a result of thenegotiations, the current rates should remain unshanged and place the revenue surplus into adeferral account to apply against 2011 and future rate increases with a phase in amortizationthat strives for rate stability.

6. CPCN threshold-stay at $5milion.

7. Unrealized losses in rate base-should some of these losses be to the shareholder? Parties

should present a separate settlement package.

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The British Columbia Public Interest Advocacy Centre 208–1090 West Pender Street Vancouver, BC V6E 2N7 Coast Salish Territory Tel: (604) 687-3063 Fax: (604) 682-7896 email: bcpiac@bcpiac.com http://www.bcpiac.com

Valerie Conrad 687-3017 Sarah Khan 687-4134 Eugene Kung 687-3006 James L. Quail 687-3034 Ros Salvador 488-1315 Leigha Worth 687-3044

Barristers & Solicitors Peggy Lee

Article Student

Our file: 7432 November 12, 2009

VIA EMAIL Erica M. Hamilton Commission Secretary BC Utilities Commission Sixth Floor, 900 Howe Street Vancouver, BC V6Z 2N3 Re: Terasen Gas Inc. Revenue Requirements 2010-2011 Negotiated Settlement This is to confirm that we are satisfied that the draft Settlement Agreement circulated by Mr. Thompson and Mr. Loski on November 5, 2009 accurately captures the consensus reached by the parties to the Negotiated Settlement Process in this proceeding, and that we have been instructed by our clients, BCOAPO et al., to endorse it. Accordingly, we ask that the Commission incorporate it into a consent Order for the resolution of all issues in the Application. Our only further comments, made here only "for the record" and in no way detracting from our clients' endorsement of the Settlement, concern the “Alternative Energy Solutions" addressed under heading 13 of the document. While we believe that the ultimately appropriate corporate and regulatory formats for these lines of business are subject-matters which may require eventual determination by the Commission, our clients are content with the treatment of these issues in the Settlement Agreement over its term, in that it provides a “firewall” to ensure that the utility’s natural gas distribution customers do not subsidize or otherwise contribute to these nascent programs through their rates. Yours truly, BC PUBLIC INTEREST ADVOCACY CENTRE Original in file signed by: Jim Quail Executive Director cc: parties of record

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1

From: Nakoneshny, Philip BCUC:EXSent: Friday, November 13, 2009 12:59 PMTo: Commission Secretary BCUC:EXSubject: FW: Terasen Gas -Revenue Requirements-Negotiated Settlement

  ‐‐‐‐‐Original Message‐‐‐‐‐ From: Dave Newlands [mailto:dnewlands@telus.net]  Sent: Friday, November 13, 2009 9:40 AM To: 'Al Kleinschmidt'; Brownell, Bob BCUC:EX; Bystrom, Chris; Chris Weafer; J. David Newlands; Roy, Diane; David Craig (dwcraig@allstream.net); Domingo, Yolanda BCUC:EX; Stout, Douglas; 'Eugene Kung'; 'Frederick Metcalfe'; 'Leigha Worth'; McMahon, Claudia BCUC:EX; Carman, Michelle; Nakoneshny, Philip BCUC:EX; 'Paul Cassidy'; Hill, Shawn; Loski, Tom; Wieringa, Paul EMPR:EX; Ghikas, Matt; Sue, Suzanne BCUC:EX; Thomson, Scott ‐ TGI; James L. Quail (JimQuail@bcpiac.com) Cc: Bernadet Mark SPO Subject: Terasen Gas ‐Revenue Requirements‐Negotiated Settlement   Philip Nakoneshny Director of Rates and Finance British Columbia Utilities Commission  Dear Philip                Terasen Gas Revenue Requirements Application‐2010/2011                                 Negotiated Settlement I write on behalf of Teck Coal.  Teck Coal participated in the Negotiated Settlement Process ("NSP"),facilitated by the Staff of the British Columbia Utilities Commission, and held in the offices of the Commission ,which commenced on October 21,2009.  Teck Coal in the negotiations took into consideration the 7 "Issues of Particular Concern to the Commission Panel ",as provided by the Commission Panel at the commencement of the negotiation.  Issue Number 5 stated " 2010 Rate Changes‐ in the event that a 2010 rate reduction were to occur as a result of the negotiations ,the current rates should remain unchanged and place the revenue surplus into a deferred account to apply against 2011 and future rate increases with a phase in amortization that strives for rate stability"  Teck Coal supports the Negotiated Settlement Agreement Package ("TGI NSP Agreement Package ") dated and circulated by Terasen Gas Inc incorporating a decrease of (1.73% ) in the Fiscal Year commencing January 1,2010,previously an increase of 5.3%.and an  increase of 3.93% in the Fiscal Year Commencing January 1,2011,previously an increase of 4.1% .  The Negotiated Settlement Agreement Package, incorporates ,amongst others,Issues of Particular Concern to the Commission Panel No. 5  

APPENDIX A to Order G-141-09 Page 103 of 110

2

Teck Coal recognizes and emphasizes that this Agreement is the product of compromise on the part of all Parties, yielding an overall package that the Parties consider to be fair, just and reasonable.  The Parties agreed that any compromises resulting from this Agreement are without prejudice to the Parties¹ ability to take different positions after 2011 and without prejudice to the Parties right to intervene in any applications contemplated in or resulting from this Agreement.  Yours Truly  J.David Newlands  Cc Mark Bernadet ,General Manager ,Business Improvement,Teck Coal       

APPENDIX A to Order G-141-09 Page 104 of 110

            

PHILIP W. NAKONESHNY DIRECTOR, RATES AND FINANCE Philip.Nakoneshny@bcuc.com web site: http://www.bcuc.com 

        

SIXTH FLOOR, 900 HOWE STREET, BOX 250 VANCOUVER, B.C.  CANADA  V6Z 2N3 

TELEPHONE:  (604)  660‐4700 BC TOLL FREE:  1‐800‐663‐1385 FACSIMILE:  (604)  660‐1102 

    November 13, 2009   Erica M. Hamilton Commission Secretary British Columbia Utilities Commission Sixth floor, 900 Howe Street, Box 250 Vancouver, BC   V6Z 2N3  Dear Ms. Hamilton:  

Re:  Terasen Gas Inc. 2010 and 2011 Revenue Requirements Application 

Negotiated Settlement Agreement Letter of Comment 

 Commission staff participated in the settlement discussions that led to a Negotiated Settlement Agreement (“Settlement Agreement”) being reached between Terasen Gas Inc. (“Terasen Gas”) and the registered Intervenors (collectively, the “Parties”) in accordance with the Negotiated Settlement Process‐Policy, Procedures and Guidelines, January 2001 (“NSP Guidelines”).  Commission staff has informed the Parties that the agreements reached on certain issues were not supported by Commission staff and that Commission staff intended to submit a Letter of Comment in respect of those issues.  The Parties agreed to Commission staff adopting that course.  There are three items in the Settlement Agreement that Commission staff do not support:  1. Item 10‐Inclusion of SCP Capacity in MCRA 

 Commission Order G‐98‐05 states that: “The Commission approves the debiting of the annual charge of $3.6 million (based on the monthly instalments) against the Midstream Cost Reconciliation Account, with an equal and offsetting amount to be credited to the delivery margin the revenue account for a limited period as a unique and unusual transaction in the circumstances of the SCP and the termination of the BC Hydro TSA.  The debiting and the crediting will commence on either November 1, 2005 or January 1, 2006, as consistent with the amount of the BC Hydro/Terasen Inc. TSA revenue that Terasen Gas forecast in its Annual Review submission for 2005 and will end on the earlier of the November 1, 2010 or such other date as the Commission may determine.”  The Settlement Agreement continues to include the annual charge of $3.6 million against the MCRA with an offsetting credit to the delivery margin.  In Commission staff’s view, extending this treatment beyond November 1, 2010 as contemplated by Order G‐98‐05 requires a determination by the Commission Panel.  

…/2 

APPENDIX A to Order G-141-09 Page 105 of 110

  

2  

 

…/3 

Commission staff accepts that such determination will occur if the Commission Panel approves the Settlement Agreement. 

 2. Item 13‐Alternative Energy Solutions  

Terasen Gas added 9 enhanced sales and business development staff in 2009 estimated to cost $1.35 million and proposes increases of $3.0 million in 2010 for an additional 10 enhanced sales and business development staff including $1.1 million for consultants and studies and a further $0.6 million in 2011 for 4 enhanced sales and business development staff (BCUC IR 1.72.2 and IR 2.96.2 to 2.96.4; IR 1.114.7).  The number of customers are expected to increase between 1.0 to 1.1 percent from 2009 to 2011, but the level of spending in Customer Solutions and Services increases by 17 percent, 27 percent and 8 percent respectively from 2009 to 2011 (BCUC IR 1.96.3). 

 The New Energy Solutions Deferral Account is to capture direct costs, sales and marketing O&M and other development costs by timesheets or other direct charge and an overhead allocation.  In Commission staff’s view, due to the modest growth in customer additions from 2009 to 2011, the additional enhanced sales and business development staff were primarily hired in 2009 to 2011 to develop and market Alternative Energy Solutions.  The use of timesheets, direct charges and overhead allocations may result in a proper reallocation of costs from the gas utility to the New Energy Solutions Deferral Account. 

 The down time or idle time that will likely be experienced while the Alternative Energy is being marketed may not be captured by the timesheet allocation and could remain as a cost to the gas utility.  In Commission staff’s view, it would be preferable to directly charge the fully loaded cost of the additional enhanced sales and business development staff and the costs of consultants and studies to the New Energy Solutions Deferral Account to avoid any of these costs being borne by natural gas customers. 

 If Terasen Gas is able to demonstrate that the use of timesheets, direct charges and overhead allocations would result in none of the costs that are incurred for Alternative Energy Solutions including down time and the costs of consultants and studies to be borne by gas customers, then Commission staff’s concern is addressed. 

 3. Item 14‐Natural Gas for Vehicles (“NGV”) 

 Terasen Gas proposes to treat as general O&M, rather than track separately, NGV marketing and project development costs incurred prior to signing a contract with a customer for compression and refuelling service (BCUC IR 1.21.1).  Commission staff attempted to obtain information on the NGV marketing costs that are currently incurred through information requests, but were unsuccessful.  In Commission staff’s view, information on the incremental marketing costs being incurred will be required if Terasen Gas, during 2010 and 2011, applies  

APPENDIX A to Order G-141-09 Page 106 of 110

  

3  for approval of Rate Schedule 6 C NGV Compression and Refuelling Service and 6A NGV Refuelling Service ,  including recovery of the incremental marketing costs, and the Commission is to review the applications on a case‐by‐case basis as contemplated in the Settlement Agreement. 

   Yours truly,     Original Signed by        Philip W. Nakoneshny   Director, Rates and Finance   

PF/TGI‐2010RR/NSP Doc/Ltr to EMH_Comm staff‐Ltr of Comment 

APPENDIX A to Order G-141-09 Page 107 of 110

~ Torn A. Loskl

TeraSen Gas

Chief Regulatory OfIioer

16705 Fraser Highway Surrey, B.C. V4N OES Tel: (604) 592-7464 Cell: (604) 250-2722 Fax: (604) 576-7074

November 13, 2009

British Columbia Utilities Commission Sixth Floor, 900 Howe Street Vancouver, B.C. V6Z 2N3

Attention: Mr. Philip Nakoneshny, Director, Rates and Finance

Dear Mr. Nakoneshny:

Re: Terasen Gas Inc. ("Terasen Gas") 2010 and 2011 Revenue Requirements Application

Negotiated Settlement Agreement

Email: tom.loski@terasengas.com www.terasengas.com

Regulatory Affairs Correspondenoe Email: regulatory.affairs@terasengas.com

On June 15, 2009, Terasen Gas filed its 2010 and 2011 Revenue Requirements Application, which was supplemented by a filing on July 9, 2009 and amended by filings on August 14 and September 18, 2009 (the "Application").

In accordance with Commission Order No. G-76-09 issued on June 19, 2009, a Workshop was held on July 6, 2009 for a review of the Application, a Procedural Conference was held on July 15, 2009, and Terasen Gas responded to two rounds of Information Requests. In accordance with Commission Order No. G-89-09 issued on July 20,2009, a second Procedural Conference was held on September 25, 2009 and on October 2, 2009, the Commission issued Order G-119-09 establishing a Negotiated Settlement Process ("NSP") for the Application. In accordance with Order No. G-120-09, the NSP commenced on Wednesday, October 21, 2009 and concluded on Wednesday, November 4, 2009.

Terasen Gas has reviewed the attached settlement documents, including the Negotiated Settlement Agreement and associated financial schedules (collectively the "Negotiated Settlement") arising from the NSP. Terasen Gas recognizes the Negotiated Settlement as being the product of good faith compromises among parties with diverse interests in the issues raised by the Application. The Parties have expressly considered the Commission Panel's Issues. In fulfilling their role pursuant to the Commission's Negotiated Settlement Process Policy, Procedures and Guidelines (the "Guidelines"), Commission Staff made additional information available to the parties which they believed was in the public interest. The parties considered all such information in reaching the compromise Settlement Agreement and Terasen Gas considers the resulting Negotiated Settlement to be fair, just and reasonable. As the Negotiated Settlement represents compromises among the parties and an overall balance of interests, Terasen Gas stresses that the Negotiated Settlement should be considered as a package, with no part being severed unless otherwise stated in the Agreement. On that basis, Terasen Gas accepts the Negotiated Settlement.

Commission Staff have provided written comment on the NSP, and TGI responds to those comments below.

APPENDIX A to Order G-141-09 Page 108 of 110

November 13, 2009 ~ British Columbia Utilities Commission Terasen Gas 2010 and 2011 Revenue Requirements Application Negotiated Settlement Agreement

Terasen Gas

Page 2

Inclusion of Southern Crossing Pipeline ("SCP") Capacity in the Midstream Cost Reconciliation Account ("MCRA"): TGI notes for reference that the evidence on the inclusion of the SCP costs in the MCRA is found in the Application on pages 314 to 315 and its response to BCUC IRs 1.68.1 and 2.92.1-7. The result of taking the approach in the Agreement is a lower delivery rate, all else equal, with an offsetting charge to the MCRA.

Alternative Energy Solutions (GeothermallDistrict Energy Systems and Solar Thermal): Staff's position on this issue turns on its view that, "due to the modest growth in customer additions from 2009 to 2011, the additional enhanced sales and business development staff were primarily hired in 2009 to 2011 to develop and market Alternative Energy Solutions." While that may be Staff's position, it is at odds with TGl's evidence. Staff's conclusion appears to rest on the notion that TGI could not truly require additional staff for marketing if there is only modest growth in customer additions, i.e. that there is a linear correlation between marketing effort and customer additions. TGl's evidence was that the competitive factors facing the gas business mean that it is necessary to invest more to maintain and grow the business, including the gas business.

Staff also identifies an issue relating to overhead allocation to the alternative energy class of service, so as to ensure gas customers are not bearing costs attributable to the pursuit of geothermal, solar thermal and district energy systems. The cost allocation methodology outlined in the Agreement is structured to avoid cross subsidization by gas customers. The Agreement contemplates a $500,000 annual overhead allocation to alternative energy solutions, and a corresponding reduction in overhead allocated to gas customers. This is a direct benefit to gas customers. As a point of comparison, the allocation of overhead to alternative energy solutions is approximately two times the allocation to Terasen Gas (Whistler) Inc., suggesting that the issue of overhead allocation is addressed adequately. The risk of non-recovery lies with TGl's shareholder, not gas customers. Notably, the gas customers themselves have endorsed the Agreement.

NGV Marketing Costs: TGI notes that it has an existing NGV tariff and the amount of NGV marketing costs in the revenue requirements for 2010 and 2011 is very modest (see TGl's responses to BCUC IR 1.21.2 (last paragraph) and BCUC IR 2.96.2). Issues relating to NGV have been deferred by the terms of the Settlement Agreement. TGI respectfully submits that there is no need for the Panel to address Staff's issue at this time.

TGI wishes to make one final comment relating to our procedural concerns regarding the publication of Staff's comments. Commission Staff unquestionably plays an important role during the confidential settlement discussions in providing information and assisting the parties, and providing a perspective regarding their view on the public interest. That role is one sanctioned by, and described in, the Commission's Guidelines. However, under the Guidelines (at page 8) Commission Staff is precluded from, "endorsing a particular position". TGI therefore questions whether the letter provided by Commission Staff is consistent with the Guidelines.

APPENDIX A to Order G-141-09 Page 109 of 110

November 13, 2009 British Columbia Utilities Commission Terasen Gas 2010 and 2011 Revenue Requirements Application Negotiated Settlement Agreement Page 3

~ Terasen

Gas

TGI respectfully submits that the requirement for the Commission Staff not to take positions on issues makes good sense. Commission Staff is not a party to the resulting Agreement; rather, the Negotiated Settlement Agreement is simply an agreement among intervenors and the applicant that a certain outcome is acceptable to them and should be jOintly submitted for consideration by the Panel. In this case, the Agreement is clear that the Parties, having fully considered the information provided by Staff during the course of the NSP, have reached a compromise agreement that they consider to be in all respects fair, just and reasonable. As is inherent in every compromise, there will be outcomes about which a particular party was only supportive in exchange for other concessions. By commenting on the Agreement reached, Commission Staff places the parties in the position of having to justify individual items without being able to detail the steps that led to the outcome (which would not be appropriate in any event). It similarly places focus on isolated issues in the absence of the whole context of the negotiation that occurred in confidence. As a means of highlighting the difficulty this type of commentary creates, it is not possible for TGI to address in this letter Staff's statements about the information on NGV provided by TGI with reference to any additional information provided in the course of the confidential discussions.

To the extent that Staff has decided to make its views known on the present Agreement, TGI appreciates Staff having done so in a transparent manner; the alternative of having these views being conveyed in a non-transparent manner without any ability to respond would have been unpalatable. TGI nevertheless respectfully submits that the overall Settlement Agreement package should be assessed without isolating for consideration three issues where Staff might potentially have preferred a different outcome.

With that comment, Terasen Gas would like to express sincere thanks to Commission Staff and Intervenor representatives for their active participation in achieving this Negotiated Settlement Agreement on the Application. Terasen Gas also wishes to thank the NSP facilitator, Mr. Paul Cassidy, for his leadership, guidance and assistance to all parties throughout the NSP process.

If there are any questions regarding the attached, please contact the undersigned.

Yours very truly,

APPENDIX A to Order G-141-09 Page 110 of 110

  

  

IN THE MATTER OF    

TERASEN UTILITIES (TERASEN GAS INC., TERASEN GAS (WHISTLER) INC. 

AND TERASEN GAS (VANCOUVER ISLAND) INC.)  

 2010 LONG TERM RESOURCE PLAN 

     

DECISION     

February 1, 2011     

Before:  

D.A. Cote, Panel Chair/Commissioner A.W.K. Anderson, Commissioner 

L.A. O’Hara, Commissioner  

TABLE OF CONTENTS 

  Page No. 

EXECUTIVE SUMMARY  1 

1.0  INTRODUCTION  3 

1.1  Application  3 

1.2  Orders Sought  4 

1.3  Regulatory Process  4 

1.4  Context  5 

1.4.1  Resource Planning Guidelines  5 1.4.2  New and Alternative Energy Solutions  6 1.4.3  Terasen Description of the 2010 LTRP  7 1.4.4  Regulatory Construct  7 

1.5  Issues Arising  8 

2.0  COMMISSION PANEL DECISION ON THE APPLICATION  11 

2.1  UCA Section 41.1(2) Requirements  12 

2.2  Resource Planning Guidelines  13 

2.3  UCA Section 41.1 (8) (a) and (b) Requirements  14 

2.3.1   Alignment with British Columbia’s Energy Objectives  14 2.3.2  Requirements Under Sections 6 and 19 of the Clean Energy Act  16 2.3.3  Adequate, Cost‐Effective Demand‐Side Measures  16 2.3.4   Consideration of the Interests of Persons in British Columbia  18 

2.4  Commission Panel Observations  19 

2.5  What Acceptance of the Plan Means  20 

3.0  DISCUSSION OF ISSUES ARISING  21 

3.1  Quality of the 2010 LTRP  21 

3.2  New Initiatives  26 

 COMMISSION ORDER G‐14‐11  APPENDICES  APPENDIX A  Utilities Commission Act Section 44.1 APPENDIX B  The Regulatory Process APPENDIX C  2010 Long Term Resource Plan and British Columbia’s Energy Objectives APPENDIX D  Demand‐Side Measures Regulation, B.C. Reg. 326/2008 APPENDIX E  List of Exhibits   

 

1 

EXECUTIVE SUMMARY 

 

The Terasen Utilities filed an Application on July 15, 2010 for acceptance of the 2010 Long Term 

Resource Plan pursuant to section 44.1(6) of the UCA.  The 2010 LTRP provides a high level 

examination of future demand and supply source expectations over the next 20 year period and 

outlines in broad terms the actions required over the next four year period to ensure the energy 

needs of customers are met over the long‐term.  In addition, the Application also covers the 

following: 

 

• The changing British Columbia energy planning environment. 

• Low and No‐Carbon Initiatives. 

• Energy Efficiency and Conservation‐Demand Side Resources. 

• Gas Supply and Regional Infrastructure Planning.  

 

The Application was reviewed by way of a written hearing process. 

 

In considering the Application, the Commission Panel must determine whether the requirements of 

section 44.1(2) of the UCA have been met.  In addition, as required by section 44.1(8), 

consideration must be given to provisions related to British Columbia’s energy objectives, the 

requirements of the CEA, demand side measures and public interest.  

 

The Interveners as a group supported the Commission’s acceptance of the 2010 LTRP.  However, 

two Interveners, BCOAPO and the CEC did raise concerns with the plan with specific reference to its 

scope, its comprehensiveness and Terasen’s lack of detail in describing how it will address the 

future.  The Commission Panel was in agreement with these criticisms and identified them as an 

issue to be dealt with in the Decision.  In addition, the issue of Terasen’s New Initiatives and how 

they are most appropriately handled within a regulatory context was raised.  The Panel is in 

agreement with the submissions of the parties and determined that this proceeding is not an 

appropriate venue to reach a determination on this matter.  However, the Panel views the issue as 

sufficiently important to warrant further examination within this proceeding and direction as to 

how it may be addressed in the future. 

2   

 

 

The Commission Panel, after an assessment of the Application in terms of the requirements 

outlined in sections 44.1(2) and 44.1(8) of the UCA and the evidence before it, accepts the Terasen 

2010 LTRP under section 44.1(6) of the UCA as being in the public interest. 

 

In this Decision, the Panel comments on the quality of the 2010 LTRP and has made a number of 

directives concerning the preparation of future resource plans.  These concern the following areas: 

 

• The development of a longer term vision for Terasen Utilities. 

• Integration of the EEC programs, New Initiatives and GHG reduction targets in demand forecasting. 

• The approach to Demand forecasting given the new business environment. 

 

An examination of Terasen’s New Initiatives in terms of the regulatory questions raised, public 

interest concerns, competitive considerations and issues related to ‘who pays’ led to a Panel 

recommendation that the issues arising are sufficient to warrant a more formal process to address 

them at a future date. 

 

   

3   

 

1.0  INTRODUCTION 

 

This Application is submitted by the Terasen Utilities, comprising Terasen Gas Inc., Terasen Gas 

(Vancouver Island) Inc. and Terasen Gas (Whistler) Inc. (Terasen, the Company, Terasen Utilities) 

for acceptance of their 2010 Long Term Resource Plan (2010 LTRP) which covers a twenty‐year 

period through 2030. 

 

1.1  Application 

 

Terasen provides natural gas service to more than 935,000 residential, commercial, and industrial 

customers in over 125 communities throughout British Columbia.  Terasen Utilities are subsidiaries 

of Terasen Inc., which since May 2007 has been owned by Fortis Inc.  

 

On July 15, 2010 Terasen submitted its 2010 LTRP to the British Columbia Utilities Commission (the 

Commission, BCUC) for review.  Terasen Utilities filed the Application in accordance with the 

Commission’s Resource Planning Guidelines (RP Guidelines) and are seeking acceptance of the 

2010 LTRP pursuant to section 44.1 of the Utilities Commission Act (the Act, UCA).  The previous 

plan, Terasen’s 2008 Resource Plan, was accepted by Commission Order G‐194‐08. 

 

The 2010 LTRP examines future demand and supply resource conditions over the next 20 years and 

recommends actions needed during the next four years to ensure customers’ energy needs are met 

over the long‐term.  It also discusses the rapidly changing energy planning environment in British 

Columbia, the low carbon strategies of Terasen Utilities, the new demand forecasting activities, the 

need to seek additional and on‐going funding approvals for the Company’s Energy Efficiency and 

Conservation (EEC) programs as well as regional infrastructure issues. 

 

Terasen points out that the activities of a fourth company, Terasen Energy Services (TES), also 

provide important background in planning for the future of Terasen Utilities.  It appears that 

beginning 2010 Terasen Utilities have begun assuming the role previously played by TES in relation  

   

4   

 

to new projects.  These activities include the development, construction and operation of 

alternative energy systems as well as setting of rates and cost recovery for those systems. 

(Exhibit B‐1, p. 3) 

 

1.2  Orders Sought 

 

Terasen is seeking acceptance of the 2010 LTRP in accordance with section 44.1 of the Act.  This 

section, entitled “Long‐term resource and conservation planning”, is reproduced in its entirety in 

Appendix A.  Specifically, the Company requests that the Commission, after reviewing the 

Application, finds that carrying out the 2010 LTRP is in the public interest and accepts it accordingly 

pursuant to s. 44.1(6) of the Act.  The Commission’s public interest determination under s. 44.1(6) 

must also be guided by the criteria identified in s. 44.1(8), including the consideration of British 

Columbia’s energy objectives, whether the plan shows that the public utility intends to pursue 

adequate, cost‐effective demand‐side measures, and consideration of the interests of persons in 

British Columbia who receive or may receive service from the public utility. 

 

While the 2010 LTRP submission includes five‐year capital plans and descriptions of facility 

expansions, Terasen Utilities are not seeking approval of those capital plans at this time.  Terasen 

states that each company will file separate CPCN applications, if and as necessary, for any of those 

projects in accordance with the Commission’s guidelines.  

 

1.3  Regulatory Process 

 

The Regulatory Process is described in detail in Appendix B.  Five organizations registered as 

Interveners for the Application.  They are: 

 

• Ministry of Energy, Mines and Petroleum Resources 

• British Columbia Hydro and Power Authority 

• B.C. Sustainable Energy Association and the Sierra Club of British Columbia Chapter (BCSEA) 

5   

 

• British Columbia Old Age Pensioners’ Organization et al. (BCOAPO) 

• Commercial Energy Consumers’ Association of British Columbia (CEC) 

 

Among these BC Hydro, BCSEA, BCOAPO and the CEC, intervened by actively participating in some 

or all of the Processes. 

 

Noteworthy is a question by a member of the Commission Panel during the Procedural Conference 

on September 21, 2010.  The inquiry was about a statement made by the Company on page 186 of 

the Application: “Going forward, the utilities will seek approval of an overall business and 

regulatory model and seek CPCN approval of specific projects.” (T1:7)  This raised the issue of a 

need to better understand the view of Terasen with respect to the line separating regulatory and 

non‐regulatory activities as the companies pursue what some might define as potentially 

competitive enterprises as opposed to those in a more traditional regulatory environment.  By 

Order G‐146‐10 the Commission Panel requested submissions of the parties as to the need of a 

Second procedural Conference to address this topic.  These submissions are summarized in 

Section 1.4.4 as they focus on the context in which the Panel has considered the 2010 LTRP. 

 

1.4  Context 

 

1.4.1  Resource Planning Guidelines 

 

The Commission’s mandate to direct and evaluate the resource plans of energy utilities is intended 

to facilitate the cost‐effective delivery of secure and reliable energy services.  In other words, 

resource planning aims at assisting the selection of cost‐effective resources that yield the best 

overall outcome of expected impacts and risks for ratepayers in the long‐term.  The RP Guidelines 

provide general guidance regarding the Commission’s expectations of the process and methods for 

utilities to follow in developing their plans that reflect their specific circumstances and include the 

following key phases and/or steps: 

 

• Identification of the planning context and the objectives of a resource plan; 

6   

 

• Development of a range of gross pre Demand Side Management (DSM) demand forecasts; 

• Identification of supply and demand resources; 

• Measurement of supply and demand resources; 

• Development of multiple resource portfolios; 

• Evaluation and selection of resource portfolios; 

• Development of an action plan; 

• Stakeholder input; 

• Regulatory input; 

• Consideration of government policy; and 

• Regulatory review. 

 

Further, utility specific directions may address issues regarding the elements of the resource plan 

or the underlying methodology.  The Commission reviews resource plans in the context of the 

unique circumstances of the utility in question. 

 

1.4.2  New and Alternative Energy Solutions 

 

The Company states that energy services which integrate low and no‐carbon fuel technologies with 

conventional energy supply provide solutions to some of the province’s most pressing challenges.  

These challenges include increasing demand for energy, escalating energy costs, carbon emissions, 

job creation and economic stability.  In 2010 Terasen Utilities began integrating a range of 

alternative energy solutions and services into their core natural gas transportation and delivery 

business, while at the same time increasing expenditures on energy efficiency and conservation 

programs.  Terasen states that in the context of the 2010 LTRP, alternative energy systems are 

those low and no carbon technologies that provide renewable thermal energy solutions for the end 

user; such as geo‐exchange, waste heat recovery, solar thermal and combined heat and power as 

well the combination of any of these types of technologies with conventional energy services in 

discrete and district energy systems.  In addition, Terasen is pursuing new low carbon initiatives 

and projects which are designed to reduce Greenhouse Gas (GHG) emissions. Terasen further 

7   

 

states that the 2010 LTRP “builds on those initial steps to transform Terasen Utilities into a 

complete, integrated energy provider of alternative energy solutions incorporating the reliability of 

conventional energy services.” (Exhibit B‐1, p. E‐1, p. 3, pp. 9‐10) 

 

1.4.3  Terasen Description of the 2010 LTRP 

 

The Company submits that the 2010 LTRP is “a contextual document that considers the planning 

environment, including B.C.’s energy objectives, input from customers and other stakeholders with 

insight into the future needs of the utility and the issues Terasen Utilities must continue to monitor 

in order to continue serving customers in the most cost‐effective, safe and reliable manner.”  

Terasen further explains that the existence of other regulatory processes directly related to 

resource planning have influenced the scope of what can be efficiently addressed in the 2010 LTRP.  

Terasen Utilities cites Annual Contracting Plans, individual gas supply contracts, the Gas Supply 

Mitigation Incentive Plan and applications for EEC funding as examples of these processes. 

 

Finally, Terasen submits that because a section 44.1 filing is a higher‐level planning document, 

there is a need for further Commission consideration of key matters described in the 2010 LTRP, 

including the action plan.  As an example, Terasen points out it can generally only proceed with 

significant capital projects once a CPCN has been obtained.  Similarly, the low or no‐carbon 

initiatives will also require Commission approvals. (Terasen Final Submission, p. 2)  

 

1.4.4  Regulatory Construct 

 

In response to Order G‐146‐10 Terasen submits “the Commission’s understandable desire to 

explore the issue of the scope of regulation in respect of these initiatives is most appropriately left 

to other processes to be concluded in the near future.”  Terasen further submits that this would 

allow the 2010 LTRP process to be most efficiently and effectively addressed in a written process 

based on the existing record.  Terasen provides the following reasons for its position: 

 

8   

 

• Each of the low‐carbon initiatives is unique, and therefore is not conducive to a “one size fits all” determination in a section 44.1 proceeding devoted to high‐level planning. 

• The initiatives are, or will be in the immediate future, the subject matter of project specific proceedings that are more conducive to addressing regulatory issues of this nature. 

• This approach is consistent with the Commission‐approved Negotiated Settlement Agreement (NSA) in the recent Terasen Gas Inc. and Terasen Gas (Vancouver Island) Inc. 2010 and 2011 revenue requirements applications. 

(Exhibit B‐11, pp. 1‐2) 

 

BCOAPO submits that ultimately there will be a requirement for a holistic examination of the larger 

question of “what kinds of activity will properly reside with the utility, as markets, policy and rules 

regarding greenhouse gas‐emitting hydrocarbon fuels develop” in the world of Terasen Utilities.  

However, BCOAPO further submits that because this Application “fails to provide a basis for the 

Commission to develop a meaningful handle on the fundamental questions facing it as the 

regulator of natural gas utilities” it would be premature to address this issue in the 2010 LTRP 

proceeding. (Exhibit C4‐4, pp. 1‐3) 

 

BCSEA agrees with BCOAPO that the record in the 2010 LTRP proceeding is insufficient to support a 

high level examination of policy issues raised by the downstream, or “below the utility meter”, 

business opportunities that Terasen Utilities are now developing.  (Exhibit C3‐4, pp. 1‐2) 

 

1.5  Issues Arising 

 

Terasen is seeking acceptance of its Long Term Resource Plan which it describes as “a point in time 

in the Terasen Utilities high level, dynamic, and ongoing planning process.”  The Company notes 

that the process leading to this plan is not linear but iterative in nature with the final stage being 

the development of a four‐year action plan which encompasses the implementation of the plan’s 

recommendations and ensures resource requirements and alternatives receive ongoing 

assessment. 

 

   

9   

 

Terasen submits that the 2010 LTRP has met the requirements of the UCA and is in the public 

interest.  (Terasen Final Submission, p 1‐2; Exhibit B‐1, p. 1) 

 

It is Terasen’s position that resource planning is an ongoing process and subject to change as it 

responds to new events and information.  Terasen states that this freedom is a necessity if it is to 

take action to ensure a supply which is safe, secure and reliable.  The Company further states that 

acceptance of the 2010 LTRP does not commit the Commission to approving cost estimates for 

future applications which relate to projects or programs included in this plan.  Due to the likelihood 

of new relevant evidence being brought forward in these applications, it is not essential that the 

Commission approve costs in a LTRP. (Exhibit B‐5, BCUC 1.1.1) 

 

The Interveners as a group are in support of the Commission accepting the 2010 LTRP.  However, 

two of the stakeholders, BCOAPO and the CEC have expressed concerns with the plan in terms of 

its scope, its comprehensiveness and the lack of specific detail in describing plans to address the 

future.  BCOAPO is critical of the quality of the plan and questions whether it fulfills the purpose of 

resource planning.  BCOAPO further notes that the point of resource planning is for the parties to 

reflect on the utilities trajectory as it relates to emerging issues.  This entails dealing with what it 

refers to as the “Big Question” concerning the lines of business utilities pursue and how they 

operate in the future.  Moreover, it notes that the “Long Term Plan” appears to be a short term 

exercise and suggests the Commission provide guidance to Terasen with respect to the preparation 

of future resource plans.  The CEC refers to Terasen’s 2010 LTRP as “essentially business as usual 

with a tweak” and contends that overall the plan does not go far enough in creating change over 

the 20 year period.  The CEC also submits that the level of resource planning considering provincial 

GHG targets will be inadequate in setting a base for the kind of response which will be required.  

Further, the CEC notes the four year Action Plan which addresses low or no carbon initiatives is 

very short term in perspective.  The CEC submits there would be little value in asking Terasen to 

redo its resource plan but recommends the Commission request Terasen to show substantial 

improvement in its next LTRP. (BCOAPO Final Submission, pp. 1‐3; CEC Final Submissions, pp. 4‐6) 

   

10   

 

Taking into consideration these comments and the submissions from Interveners, as well as its 

review of the evidence submissions of Terasen, the Commission Panel has identified a number of 

issues which require more detailed examination.  They are as follows: 

 

1. The Adequacy and the Quality of the 2010 LTRP 

The Commission Panel views the adequacy and the quality of the 2010 LTRP as two separate issues.  

The adequacy of the 2010 LTRP is very much a question in determining whether it should be 

accepted by the Commission.  Primary considerations in reaching a determination on this include 

requirements of section 44.1 of the UCA, alignment with British Columbia’s energy objectives and 

Provincial Government policy, the RP Guidelines and any previous directions provided by the 

Commission with respect to future resource plans. 

 

Aside from any decision with regard to the adequacy of the LTRP is the consideration of its level of 

quality.  Both BCOAPO and the CEC have expressed concerns with whether the plan is sufficiently 

robust and complete and whether it adequately addresses the future.  The Panel has similar 

concerns and believes that a closer examination of this issue within this Decision will lead to 

improvements in future LTRP applications. 

 

2. Understanding the Meaning of Acceptance 

The Commission Panel notes that the meaning of “acceptance” of the 2010 LTRP is addressed by 

Terasen Utilities in a number of IR responses and in its Final Submission.  However, we believe 

there would be a benefit in providing clarity to define exactly what is meant by “acceptance.”  Our 

concern lies in ensuring that the meaning of acceptance of this plan is understood and does not “tie 

the hands” of Panels in reviewing future applications related to many of the initiatives considered 

in this Application. 

 

3. New Initiatives 

As raised previously, there is a need to address the issue of how best to handle Terasen’s move into 

what are non‐traditional and potentially competitive business lines from a regulatory perspective.  

11   

 

This remains an issue with the BCOAPO which in its Final Submission stated that Terasen must deal 

with this “Big Question” if the resource planning exercise is to be meaningful.  It further notes that 

if the issue is left to be answered on an ad hoc basis through one‐off applications it will mean 

“missing the opportunity for a careful and systematic consideration of the complex regulatory 

issues embedded within it.”  (BCOAPO Final Submission, p. 1) While the parties have agreed that 

this proceeding is not an appropriate place to reach a determination on this matter, it remains an 

issue worthy of further examination and some direction as to how it may be addressed in the 

future would be constructive. 

 

This Decision will first address whether to accept or reject in whole or in part this Application.  This 

will be covered in Section 2.0 which will also include the Panel’s consideration of what it views 

“acceptance” to mean and the implications.  In Section 3.0 the Panel will address what it believes 

to be key issues arising from the Application.  This will include a discussion of the 2010 LTRP and 

requirements for future resource plans as well as a discussion of the issues related to Terasen’s 

plans to move forward with initiatives in new business areas.  

 

2.0  COMMISSION PANEL DECISION ON THE APPLICATION 

 

In reaching its decision as to whether to accept Terasen’s 2010 LTRP, the Panel must determine 

whether the requirements of section 44.1 (2) of the UCA have been met.  Further, in accordance 

with section 44.1 (8), the Panel must consider the provisions therein related to British Columbia’s 

energy objectives, requirements of the Clean Energy Act (CEA), demand‐side measures and public 

interest. 

 

Finally, the Panel must consider the 2010 LTRP within the context of the RP Guidelines and the 

evidence presented by the Applicant and Interveners. 

 

In assessing the 2010 LTRP in terms of its requirements and considering the British Columbia 

energy objectives and policy as well as the evidence before it, the Commission Panel  accepts the 

Terasen 2010 LTRP under section 44.1 (6) of the UCA as being in the public interest. 

12   

 

2.1  UCA Section 41.1(2) Requirements 

 

For a long term resource plan to be accepted it must satisfy the requirements of section 41.1(2) of 

the UCA.  This section is provided in Appendix A and includes the following: 

 

• A plan to reduce demand. 

• Demand estimates both before and after taking into account demand‐side measures. 

• A description of new or extensions to existing facilities. 

• Information regarding energy purchases. 

• An explanation of why either energy purchases or facility requirements are not replaced by demand side measures.  

• Any other information required by the Commission. 

 

Throughout the proceedings Terasen Utilities has referred to the 2010 LTRP as a high level planning 

exercise.  In keeping with this, the Company has broadly outlined the issues it is concerned about 

and its direction over the long term.  Included are demand forecasts for the next twenty year 

period which take into account EEC measures which have been implemented to date. (Exhibit B‐5, 

BCUC 1.15.1.1)  While Terasen has developed scenarios based on future funding levels it has 

provided no detail to EEC measures beyond 2011.  Further, Terasen has addressed the need for 

additional infrastructure requirements to adequately meet demand in the future as well as its 

intent to move forward with a number of low or no‐carbon initiatives.  The 2010 LTRP makes note 

of these in the 8‐point action plan guiding activity over the next four year period.  A number of 

these points will result in further applications which, when filed, will provide a description of the 

initiatives and their impact.  (Exhibit B‐1, pp. 185‐188) 

 

None of the Interveners raised concern with respect to whether the requirements of 

section 44.1(2) have been met. 

 

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The Commission Panel is satisfied that the 2010 LTRP as filed by Terasen is adequate to meet the 

requirements as laid out section 44.1(2) of the UCA.  The Panel notes that additional detail on 

much of what is proposed will follow in subsequent filings.  Accordingly, the Panel finds there is no 

reason to reject Terasen 2010 LTRP on the basis of failure to meet these requirements. 

 

2.2  Resource Planning Guidelines 

 

The purpose and key requirements for the development of long term resource plans have been 

outlined previously in Section 1.4.1.  The RP Guidelines were developed in 2003 and predate much 

of the recent legislation and changes to the UCA.  Nonetheless they are still relevant as they 

provide overall direction but are not prescriptive in mandating a specific outcome to the process or 

specific investment decisions. 

 

It is apparent that Terasen Utilities took some guidance in the preparation of the LTRP from the RP 

Guidelines.  However, it is also clear the 2010 LTRP which has been filed by Terasen does not 

incorporate the guideline requirements fully.  Most notable by their absence are the following: 

 

• The lack of a clear outline detailing the measurement of supply‐side and demand‐side resources against established objectives. 

• The lack of development of multiple resource portfolios for each demand forecast and related assessment of alternative resource portfolios against various gross demand forecasts. 

 

On the positive side, Terasen has identified the planning context and objectives of the resource 

plan, developed four year action plans and has invited stakeholder input as outlined in the 

guidelines.  With respect to stakeholder input, the Panel is most encouraged by Terasen’s intention 

to establish a Resource Plan Advisory Group as it may provide a sounding board and assist in the 

preparation of future plans. 

 

   

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The Commission Panel recognizes that the 2010 LTRP has been prepared at a high level and lacks 

detail.  Further, Terasen admits that many of the New Initiatives included in the plan are not 

sufficiently developed to where they can be fully incorporated in the planning process.  (Terasen 

Final Submission, p. 6)  In addition, given the significant change and evolution of British Columbia’s 

energy objectives and Provincial Government policy since the RP Guidelines were issued, a review 

and update of the guidelines is likely warranted.  As a result, the Panel in considering these factors 

and the fact that Terasen did incorporate many elements of the RP Guidelines within its 2010 LTRP, 

sees no value in rejecting it based on its failure to incorporate all guideline elements. 

 

2.3  UCA Section 41.1 (8) (a) and (b) Requirements  

 

Section 44.1(8) of the Act outlines a number of provisions which must be considered by the 

Commission in reaching a decision as to whether to accept a long term resource plan.  A discussion 

of each of these follows. 

 

2.3.1   Alignment with British Columbia’s Energy Objectives 

 

The Panel finds that the Application is generally consistent with British Columbia’s energy 

objectives as outlined in the Clean Energy Act.  Section 2 of the CEA sets out British Columbia’s 

energy objectives.  Those most relevant to this proceeding include: 

 

(d)  to use and foster the development in British Columbia of innovative technologies that support energy conservation and efficiency and the use of clean or renewable resources; 

(g)  to reduce BC greenhouse gas emissions 

(i)  by 2012 and for each subsequent calendar year to at least 6% less than the level of those emissions in 2007, 

(ii)  by 2016 and for each subsequent calendar year to at least 18% less than the level of those emissions in 2007, 

(iii)  by 2020 and for each subsequent calendar year to at least 33% less than the level of those emissions in 2007, 

(iv)  by 2050 and for each subsequent calendar year to at least 80% less than the level of those emissions in 2007, and 

(v)  by such other amounts as determined under the Greenhouse Gas Reduction Targets Act; 

15   

 

(h)  to encourage the switching from one kind of energy source or use to another that decreases greenhouse gas emissions in British Columbia; 

(i)  to encourage communities to reduce greenhouse gas emissions and use energy efficiently; 

(j)  to reduce waste by encouraging the use of waste heat, biogas and biomass; 

(k)  to encourage economic development and the creation and retention of jobs;   Terasen speaks to these objectives within the 2010 LTRP.  Further, the Company has provided a 

table summarizing how a number of initiatives it is undertaking within the plan are supported by 

British Columbia’s energy objectives (Appendix C). 

 

With reference to this table and its contents, the BCSEA‐SCBC notes that the list of energy 

objectives is accurate and the 2010 LTRP is consistent with the “government’s energy objectives.”  

(BCSEA‐SCBC Final Submission, p.4) The CEC indicates its desire to draw attention to British 

Columbia’s energy objective 2 (g) which outlines reductions in GHG emissions over a 40 year 

timeline.  The CEC’s position is that Terasen’s response to these objectives is confined to EEC 

programs and low and no‐carbon initiatives which it believes “will be insufficient to see the 

province achieve anywhere close to the energy objectives.”  The CEC notes that the achievement of 

these GHG targets will require dramatic change over the next 20 years and, while these initiatives 

represent a good start, they do not provide an adequate basis for the nature and scale of activities 

required to contribute significantly to the energy objectives.  In its view, the modest change of plus 

or minus 20 PJ in demand over the 20 year planning horizon will not approach the scale necessary 

to meet provincial objectives.  Further, the CEC submits that “resource planning which does not 

show a full response to the scale of provincially legislated objectives is deficient.” (CEC Final 

Submission, pp 3‐5) 

 

In Reply Terasen Utilities note that the GHG reduction targets outlined in British Columbia’s energy 

objectives are for the province as a whole and points out that no specific sector allocations have 

been made.  Additionally, the Company points out that the 20‐year demand forecast within the 

2010 LTRP does not take into account additional EEC program funding beyond that which is 

currently approved.  It states that it plans to seek expanded EEC funding for 2012 and, as a result,  

   

16   

 

the current forecast does not include the full impact of Terasen EEC programs for 2012 and 

beyond.  (Terasen Reply, p. 4) 

 

The Commission Panel accepts the view of Terasen Utilities with respect to the lack of sector 

specific allocations for GHG targets and that its demand forecasts have not included the impact of 

additional EEC program funding.  However, we are disappointed that Terasen did not broaden its 

scenario options and, more importantly, provide more detailed information in preparing its 

alternative future scenarios.  The purpose of resource planning is, in part, to create a better 

understanding of how the actions which are being taken in the present and over the medium term 

will impact the long term future.  To limit the number of scenarios and details related to each 

reduces the usefulness of the 2010 LTRP as a tool designed to further understanding.  Therefore, 

the Panel, while finding that the 2010 LTRP is consistent with British Columbia’s energy objectives 

notes that the opportunity to create further understanding and perhaps debate over a key 

component of the plan has not been explored.  

 

2.3.2  Requirements Under Sections 6 and 19 of the Clean Energy Act 

 

Sections 6 and 19 of the CEA apply to electric utilities only and accordingly are not relevant to this 

Application.  

2.3.3  Adequate, Cost‐Effective Demand‐Side Measures 

 

Section 44.1(8) (c) requires the Commission to consider whether the LTRP demonstrates an 

intention to pursue adequate, cost‐effective demand‐side measures.  The Demand‐Side Measures 

Regulation, B.C. Reg. 326/2008 provides direction as to what is required and is listed in its entirety 

in Appendix D. 

 

Terasen states that EEC programs are an integral part of its drive to meet the province’s current 

and future energy needs and ensure the efficient use of natural gas.  In April, 2009 the Commission 

approved funding for Terasen Utilities of $41.5 million for EEC activities through the end of 2010.  

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This was added to in the 2010‐2011 Revenue Requirements Negotiated Settlement Agreement 

which increased the total funding to $72.3 million through the end of 2011.  Terasen reports in its 

2009 EEC Annual Report that the 2009 EEC activities were cost‐effective and had a Total Resource 

Cost ratio of 1.2. 

 

Terasen also reports it was conducting a Conservation Potential Review (CPR) in late 2010.  The 

purpose of the CPR is to determine potential for EEC emissions savings from its customer base.  

Terasen states that it plans to submit a request for on‐going funding beyond 2011 for all Terasen 

Utilities in its 2012 Revenue Requirement Application. 

 

In the 2010 LTRP three EEC scenarios have been outlined.  Each reflects a different funding level 

and resulting impact on natural gas and GHG savings.  Terasen is careful to note that the scenarios 

have been developed using the best available data but are subject to change once the CPR results 

are available.  Terasen explains that the funding and resulting savings amounts outlined in the 

Application are not targets but have been “presented to illustrate a range of EEC funding scenarios” 

since the full analysis required to make a formal EEC funding application is not yet complete.  

(Exhibit B‐1, pp.115‐123; Exhibit B‐2, BCUC 1.38.1) 

The CEC submits that a key element for EEC resource planning is the available funding for programs 

and the ability to plan and carry them out over multi‐year time frames to achieve the market 

transformation being sought by Terasen Utilities.  The CEC is concerned that EEC activity in the 

resource plan is confined to scenarios A, B and C and does not consider “the market transformation 

options and potentials related, particularly to markets in which Terasen is already well versed.”  

The CEC further submits that the 2010 LTRP is less robust than it could be if the EEC programs and 

activities were planned as multi‐year undertakings to achieve market transformations working with 

governments and stakeholder associations to achieve efficiencies, reduced use and GHG 

reductions.  Having made the above observations the CEC recommends that “the Commission 

accept the Terasen Long Term Resource Plan, with reservations regarding the adequacy of the EEC 

component of the plans.”  (CEC Submission, pp. 12‐13) 

 

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The Terasen 2010 LTRP provides little detail to assist in the assessment of whether the EEC 

measures it will undertake in the future are adequate and cost effective.  This is because there is 

much work to be completed in advance of the formal EEC funding request which will accompany 

2012 RRA to be filed later this year.  The Commission Panel understands that this program is in the 

initial stages and limited results are available to permit a comprehensive assessment of the 

program to date.  However, we are satisfied sufficient information has been presented to support 

the view that Terasen intends to pursue adequate, cost effective demand‐side measures.  Firstly, 

the Company has indicated that when the required analytical work for future EEC funding has been 

completed it will include measures for low income housing, rental accommodations and student 

education in its service area which are the key requirements for program adequacy.  Secondly, 

while the cost effectiveness of planned EEC measures cannot be validated, the fact that only 

“acceptance” of the LTRP is sought will require Terasen to address this when a detailed funding 

request is filed.  Accordingly, the Commission Panel sees no reason to reject Terasen’s EEC 

measures due to a failure to be adequate or cost effective. 

 

In conclusion, the Panel again notes its concern with respect to the lack of detail on EEC plans 

available for consideration at this time. 

 

2.3.4   Consideration of the Interests of Persons in British Columbia 

 

The Commission Panel considers acceptance of the 2010 LTRP to be in the interest of British 

Columbians who receive or may receive service from Terasen Utilities.  In our view the 2010 LTRP 

is adequate to meet the requirements as laid out in section 44.1 (2) of the UCA, has adequately 

considered the Resource Planning Guidelines and has adequately met the provisions for 

consideration as laid out in section 44.1 (8) of the Act.  In reaching this conclusion the Panel notes 

that acceptance of the 2010 LTRP does not constitute approval of any of the programs or initiatives 

addressed within the plan. 

 

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2.4  Commission Panel Observations 

 

As noted previously, the Interveners as a group were in support of the Commission accepting the 

Terasen 2010 LTRP.  However, in providing this support some reservations were expressed with the 

plan in terms of its content, scope, completeness and the level of detail.  In addition, some of the 

Interveners had recommendations as to ways in which future long term resource plans could be 

improved. 

 

The Commission Panel in accepting the 2010 LTRP would like to be clear that in its view the plan is 

adequate only and it agrees with the Interveners that there are many areas which could be 

improved upon in future resource plan submissions.  In the view of the Panel, the long term 

resource plan is an integral part of the strategic planning process.  If prepared in sufficient scope 

and detail it will provide a solid framework upon which to base future decision making.  In 

providing a more robust LTRP, Terasen will provide the stakeholders the opportunity to conduct a 

more meaningful examination of the longer term future.  In addition, the plan will be useful in 

supporting initiatives which flow from it. 

 

The Panel observes that the lack of a more robust and complete LTRP may present challenges to 

Terasen in persuading the Commission that future applications are appropriate in the absence of 

longer term visions, strategies and resource requirement for the utilities. It may become 

increasingly difficult for the Commission to favourably consider one‐off applications without the 

benefit of a much more comprehensive LTRP. 

 

Section 3.1 which follows will examine the 2010 LTRP and Intervener comments in some detail and 

provide some recommendations with respect to future submissions.  The Panel believes that these 

recommendations along with the stated intention of Terasen Utilities to setup a Resource Plan 

Advisory Group will be helpful in promoting further development of the long term planning 

process.  In addition, in Section 3.2 the Panel will address Terasen’s new business initiatives and 

their implications.  Before proceeding we would first like to examine the matter of acceptance of 

the 2010 LTRP and what it means from the perspective of the Commission. 

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2.5  What Acceptance of the Plan Means 

 

Terasen Utilities in its Final Submission states that it is not seeking approval of any specific 

initiatives in the 2010 LTRP.  As previously outlined, it is the Company’s intent to bring forward 

applications for programs, projects and initiatives outlined in the 2010 LTRP when they are 

completed utilizing an appropriate regulatory process.  In answer to various IRs Terasen has been 

direct and unequivocal in stating that the acceptance of its 2010 LTRP  under section 41.1(6) of the 

UCA in no way commits the Commission to approval of any program or initiative which might have 

been outlined in the resource planning process.  In support of this, Terasen in answer to BCUC IR 

1.1 states that unless the Commission were to exercise its jurisdiction under section 44.1(7) of the 

UCA “the acceptance of the LTRP does not commit the Commission to approve cost estimates in 

future applications which may rely on plans recommended in the LTRP...”  Terasen makes similar 

statements in its response to BCUC IR 1.56.1 and again in BCUC IR 1.8.1.  Worthy of note, however, 

is the caveat introduced in its response to BCUC IR 1.1 where Terasen states that acceptance of a 

LTRP “may be relevant and persuasive depending on the matter at issue and arbitrarily inconsistent 

decisions are not expected.” 

 

The Commission Panel agrees with Terasen’s interpretation that acceptance of its 2010 LTRP does 

not commit the Commission to approve future applications once they are filed.  We acknowledge 

the Company’s efforts to keep the more strategic higher level resource planning process separate 

from the approval process related to programs and initiatives.  In addition, for clarity purposes the 

Panel would like to point out our understanding of acceptance includes the following: 

 

• The programs and initiatives outlined in the plan which seem reasonable at a high level are not sufficiently “fleshed out” to determine whether they will pass careful scrutiny when more detail is put forward and an application filed. 

• A number of the new initiatives represent a new direction for Terasen and additional process may be required to determine how these new ventures will fit within the context of a regulated utility. 

21   

 

• After further analysis Terasen at its discretion may decide to not move forward with some initiatives outlined in the plan. 

 

3.0  DISCUSSION OF ISSUES ARISING 

 

3.1  Quality of the 2010 LTRP 

 

In Section 2.0 the Commission Panel determined that acceptance of the Terasen Utilities 2010 LTRP 

is in the public interest.  In making this determination, the Panel noted that the 2010 LTRP was in 

its view adequate only and there were a number of areas which could be improved upon in future 

resource plan submissions. 

 

Among the Interveners, both the CEC and BCOAPO have expressed concerns with respect to the 

2010 LTRP. 

 

The CEC submits that there are numerous items which have not been factored into Terasen’s 

capital and supply plans over the 20 year planning time frame.  These result in the Company failing 

to undertake a broader integrated and consolidated view of the issues facing it and the initiatives it 

may be considering.  In addition, the CEC notes that Terasen’s resource plan fails to “lay sufficient 

ground work for the nature and scale of the activities which would be required to contribute 

significantly to the BC Energy Objectives.”  (CEC Final Submission, pp. 2‐4)  The CEC makes the 

following recommendations with respect to inclusions in future plans: 

 

• Scenarios which include a full 20 year response to the British Columbia’s energy objectives with particular regard to GHG emission reduction planning. 

• Development of a practical number of scenarios related to GHG reduction, electricity and fuel pricing, fuel switching and technology development to allow Terasen to demonstrate its response to varying circumstances. 

• Scenarios covering the transformation of trucking markets in BC to natural gas which would include analysis of and impact on the government’s objectives for GHG reduction. 

• With respect to EEC funding to address key market transformations to be considered for long term funding based on the requirements necessary to achieve the desired result.  

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• To broaden its resource planning to cover the full 20 year time‐frame and examine alternatives to defray system upgrade costs.  Referring to this the CEC submits that among the alternatives consideration should be given to targeted EEC programs where the result might be the deferral of capital expenditures due to conservation and efficiency improvements. 

(CEC Final Submission, pp. 6, 8, 11, 13 and 14) 

 

BCOAPO, in addition to raising concerns as to the need to address what it terms to be the “big 

question,” makes the observation that given the sector is facing dramatic transformation, the 2010 

LTRP projects minimal consideration of the changes which might be expected over the 20 year 

period covered by the plan.  It is BCOAPO’s position that an aim of the plan is to provide a roadmap 

for the evolution and direction of Terasen in future years.  Aside from suggesting that Terasen 

Utilities may wish to consider a more robust econometric forecasting approach, BCOAPO provides 

little specific comment on how the plan can be improved. (BCOAPO Final Submission, pp. 1‐3) 

 

Terasen in Reply notes that the purpose and scope of the resource planning process is found in 

section 44.1 of the UCA and the Commission’s Resource Planning Guidelines.  Additionally, the 

Company submits that the focus for the 2010 LTRP is on forecasted demand and its plans to meet 

that demand through resource acquisition and demand‐side measures.  Terasen’s position is that 

while long‐term resource planning may support or provide context for planned initiatives, it does 

not replace the need for individual UCA approvals allowing them to move forward.  With respect to 

the CEC’s specific recommendations, Terasen notes that many of the requests for further analysis 

are in process and points to its answer to the CEC 2.1.1 as supporting this.  Further, it sees no need 

for the econometric forecasting approach suggested by BCOAPO.  On a final note Terasen Utilities 

support the value of scenario analysis but express the need to limit the types of analysis as a 

practical matter. (Terasen Reply, pp. 1‐6) 

 

   

23   

 

Commission Panel Directives 

 

As stated previously by the Panel, the 2010 LTRP, while accepted, is viewed as being just adequate.  

It falls short of our expectation that resource plans should provide a comprehensive 20 year view of 

a utilities trajectory and provide a strong support for programs and initiatives which will be filed 

with the Commission.  The Panel is also disappointed that there was no attempt to describe a vision 

of Terasen Utilities 15‐20 years from now.  Adding this sense of vision completes the picture of how 

the actions being undertaken in the near future in combination with plans in an early stage of 

development will create the Terasen of tomorrow.  In this way Terasen can demonstrate it is 

capable of meeting the challenges presented by British Columbia’s energy objectives and evolving 

government policy. 

 

The foundation of any planning exercise is the analysis which is conducted to better understand the 

issues and challenges arising or anticipated to arise in the coming years.  This is often supported by 

the development of well crafted scenarios outlining in detail a potential outcome or series of 

outcomes.  The CEC has pointed out in its recommendations that Terasen would benefit from 

additional work in this area.  Its concern is the limited number of scenarios and lack of detail for 

each falls short of providing a clear picture of the impact of the challenges faced by the Company 

and how its plans will assist in meeting these challenges.  The Panel agrees with the CEC on this 

matter. 

 

The Commission Panel has considered this and the balance of evidence in developing a series of 

directives for the next resource planning exercise.  We believe these will provide some guidance in 

moving this process forward.  Accordingly, pursuant to section 44.1(2) (g) of the UCA, the Panel 

directs the following be included in the next LTRP: 

 

1. Terasen Utilities – A 20 Year Vision 

This vision could describe what Terasen may look like in the future: its business lines, its customers, 

the expectations for supply and demand and the major issues it will deal with over the 20 year 

resource plan timeframe. 

24   

 

 

Areas which are appropriate to be covered in preparing this Vision include but are not limited to 

the following: 

 

• The extent to which markets will be transformed. 

• The extent to which Terasen can contribute to overall British Columbia GHG reduction objectives. 

• The impact the Company’s contributions to GHG reduction will have on demand. 

• The importance new technology and new initiatives will have on the overall business, and their significance in terms of percentage share of its traditional business. 

• An outline of what initiatives are currently planned or being considered and the status. 

• The impact Terasen’s efforts have, and expect to have, on meeting British Columbia’s energy objectives. 

• The key drivers impacting the need and timing for human, physical and other (information technology, capital etc.) resource requirements.  

 

2. GHG Reduction Targets – EEC Planning and Impacts of New Initiatives 

In respect of GHG reduction targets as impacted by EEC Planning and New Initiatives the 

Commission Panel directs future LTRPs to include the following: 

 

• An analysis of the GHG targets as set out in British Columbia’s energy objectives and an estimate of the portion of the required reduction that the Company believes it can reasonably attain over time. 

• Greater coordination between EEC planning and the development of future resource plans. This will allow for a more detailed presentation of future EEC programs over a longer time period with expected impacts to be included as part of the LTRP process. 

• Development of a limited number of scenarios detailing the impacts of varying degrees of EEC Planning measures on the demand forecast and GHG emission reductions. 

• An outline of the impact of the implementation of New Initiatives on the demand forecast and GHG emission reductions. 

 

   

25   

 

3. New Business Environment and Approach to Demand Forecasting 

Future LTRPs need to more adequately convey Terasen Utilities’ understanding of the new energy 

and business environment, its impact on gross demand and how resource plans will be reflective of 

future demand growth.  Accordingly, Terasen is directed to include the following in future resource 

plans. 

 

• A description of the new end‐use forecasting methodology, how it compares with Terasen’s traditional demand forecasting approach, and reconciliation of the results of the two different approaches. 

• The development of a most likely or reference case demand forecast and outline of the underlying assumptions taking into account potential legislative, regulatory or market transformation changes. 

• An integration of the reference case demand forecast with the EEC scenarios and a description of the impacts.  

• A detailed outline of New Initiatives and their impact on future demand and GHG reduction targets backed by rigorous analysis of potential scenarios. 

• A description of the impact of each scenario on future resource requirements with consideration of the variables which could further affect these scenarios. 

 

Finally, Terasen is directed to provide an estimate of the extent to which its proposed programs 

and initiatives will contribute to the achievement of British Columbia’s energy objectives. 

    

26   

 

3.2  New Initiatives 

 

In Section 1.0 the Commission Panel identified Terasens’ low and no‐carbon initiatives (New 

Initiatives) as one of the prominent issues of the 2010 LTRP and acknowledged the Interveners’ 

ultimate concern as to what lines of businesses and regulatory constructs the Utilities will pursue in 

the future.  The Panel also noted the agreement among parties that this proceeding is not the 

appropriate forum for a systematic consideration of various, complex regulatory issues embedded 

in these new ventures.  In Section 2.0 the Commission Panel accepted the 2010 LTRP but qualified 

this acceptance in the case of New Initiatives by stating that “additional process may be required to 

determine how these new ventures will fit within the context of a regulated utility.” 

 

Terasen Utilities state that they are pursuing integrated energy solutions through three 

approaches: 

 

• Integrated energy systems to encourage use of renewable and low‐carbon thermal technologies for homes, businesses and institutional facilities (the built environment); 

• Natural gas vehicles to promote natural gas as a low carbon transportation fuel alternative to diesel and gasoline; and 

• The development of carbon neutral biomethane to displace conventional natural gas for homes, businesses and potentially in vehicles. 

(Exhibit B‐1, p. 52) 

 

Terasen submits that these New Initiatives are all regulated services and “in the public interest for 

Terasen Utilities to pursue.”  Terasen acknowledges, however, that it is appropriate for the 

Commission to deal with the legal issue as to the extent to which New Initiatives are regulated 

public utility services, along with other initiative‐specific considerations, in the other proceedings 

addressing the specific initiatives.  (Terasen Argument, pp. 6‐7) 

 

   

27   

 

A fundamental concern of the Panel is how the Commission, as the regulator of public utilities in 

British Columbia can oversee the evolution of a traditional utility in the new Clean Energy Act 

environment from the regulatory standpoint.  The Panel concurs with the views of the Interveners, 

especially BCOAPO, which were highlighted in Section 1.0.  If the issue of evolution of New 

Initiatives and the related business models is left to be answered on an ad hoc basis through one‐

off applications, as suggested by Terasen, the Commission and Interested Parties would miss the 

opportunity for a comprehensive and systematic consideration of complex regulatory issues 

embedded in the New Initiative applications.  This subject is further discussed below. 

 

Regulatory Questions 

 

When New Initiatives involve a movement away from traditional utility services, issues concerning 

matters such as business risk, risk premiums, stranded assets, “who pays for what,” and 

applicability of EEC funding emerge.  There may be a requirement for a template or framework 

within which individual projects and applications can be developed.  While Terasen submits that 

each situation is different and therefore requires its own unique approach, the Panel believes that 

perhaps each ‘unique situation’ needs to be tailored within a regulatory policy framework to be 

determined after a more holistic review. 

 

Competitive Business vs. Regulated Public Utility 

 

As Terasen Utilities adapts to changes in the new policy environment by diversifying into new low 

and no‐carbon business ventures the question also arises as to which activities in the “new world” 

belong under the umbrella of a regulated utility.  Is there a risk of unfair advantage enjoyed by the 

utility which could undermine creation of new competitive enterprises? Is there also a risk of other 

unintended consequences which are not evident today but may surface in the near term as the 

New Initiatives evolve? 

 

   

28   

 

Utilities Commission Act 

 

The Commission makes determinations regarding rates pursuant to sections 58 to 61 of the UCA 

and must ensure that an application or agreement places fundamentally no greater or less risk on 

the ratepayer at large than other rates.  In this regard, the Commission Panel remains to be 

persuaded that the public interest is served by placing some of the costs and risks related to New 

Initiatives on the traditional ratepayer.  An example of this challenge is the recent Biomethane 

Decision (Order G‐194‐10) which allowed Terasen move forward with the Biomethane Program on 

a test basis only for a two year period. 

 

British Columbia Legislation 

 

British Columbia enacted legislation designed to promote carbon reduction and the reduction of 

GHG’s.  The New Initiatives introduced by Terasen are generally in keeping with BC legislation and 

government policy.  However, the UCA is silent on specific provisions for the ‘who pays’ question 

regarding carbon and GHG reduction related initiatives.  Questions therefore arise as to whether 

rate payers are subsidising new ventures which may receive a capital contribution from EEC 

funding and whether such funding is any different than other EEC subsidies such as incentive 

payments for fuel switching, high efficiency furnace replacements etc. 

 

Future Process 

 

The Commission Panel considers that the issues raised above are beyond the scope of the 2010 

LTRP and are therefore not further addressed in this Decision.  However, the Panel believes that 

the changes being contemplated and the issues arising from them are significant enough to 

warrant a formal process to address them at a future date in the not too distant future. 

 

   

29   

 

DATED at the City of Vancouver, in the Province of British Columbia, this  First  day of February 2011.       _____Original signed by:_________________   DENNIS A. COTE   PANEL CHAIR/COMMISSIONER       _____Original signed by:_________________   LIISA A. O’HARA   COMMISSIONER      _____Original signed by:_________________   A.W. KEITH ANDERSON   COMMISSIONER   

                    

SIXTH FLOOR, 900 HOWE STREET, BOX 250 VANCOUVER, BC  V6Z 2N3   CANADA web site: http://www.bcuc.com 

    

  

 BRIT I SH  COLUMBIA  

UTIL I T I ES  COMMISS ION      ORDER    NUMBER   G‐14‐11  

 TELEPHONE:  (604)  660‐4700 BC TOLL FREE:  1‐800‐663‐1385 FACSIMILE:  (604)  660‐1102 

 

…/2 

IN THE MATTER Of The Utilities Commission Act, R.S.B.C. 1996, Chapter 473 

 and  

Terasen Gas Inc. and Terasen Gas (Vancouver Island) Inc. and Terasen Gas (Whistler) Inc. 2010 Long Term Resource Plan 

  

BEFORE:  D.A. Cote, Panel Chair/Commissioner   A.W.K. Anderson Commissioner  February 1, 2011   L.A. O’Hara, Commissioner  

O R D E R WHEREAS:  A. On July 15, 2010 Terasen Gas Inc., Terasen Gas (Vancouver Island) Inc. and Terasen Gas (Whistler) Inc. 

(collectively Terasen Utilities) filed their 2010 Long Term Resource Plan (2010 LTRP; or Application) in accordance with section 44.1 of the Utilities Commission Act (the Act) and the British Columbia Utilities Commission’s (the Commission) Resource Planning Guidelines;  

 B. The Application seeks acceptance of the 2010 LTRP pursuant to section 44.1(6) of the Act and, among other 

items, examines future demand and supply resource conditions over the next 20 years and recommends actions needed during the next four years to ensure customers’ energy needs are met over the long term.  Terasen Utilities does not seek approval of any particular elements of the plan;  

 C. On August 4, 2010, the Commission issued Order G‐124‐10 initiating a regulatory review process that 

included a Procedural Conference on September 21, 2010 and two rounds of Information Requests;   

D. Following the Procedural Conference held on September 21, 2010, Order G‐146‐10 was issued on September 24, 2010 and established an Amended Regulatory Timetable, which provided for (a) a schedule for all Parties to make submissions on the need for a Second Procedural Conference, (b) a Default Schedule for a Written Hearing without the provision of a Second Procedural Conference and (c) an Alternative Schedule for a Written Hearing with the provision for a Second Procedural Conference; 

 E. Following the Commission Panels’ consideration of the submissions of the Parties with respect to the need 

for a second Procedural Conference, Commission Order G‐169 established that the regulatory review of the 2010 LTRP will proceed as a Written Hearing in accordance with the Default Schedule in the Amended Regulatory Timetable attached to Order G‐146‐10;  

         

2   

Orders Orders/G‐14‐11_TUS 2010 LTRP Decision 

 BRIT ISH  COLUMBIA  

UTIL IT IES  COMMISS ION      ORDER   NUMBER   G‐14‐11  

 F. The Commission Panel has reviewed the Application, the evidence and the submissions and concludes that 

acceptance of the 2010 LTRP is in the public interest.   NOW THEREFORE the Commission orders that the 2010 LTRP is accepted.  Terasen Utilities is to comply with the directives contained in the Decision, issued concurrently with this Order, when filing its next long term resource plan.   DATED at the City of Vancouver, in the Province of British Columbia, this            First          day of February 2011.    BY ORDER    Original signed by:    D.A. Cote   Panel Chair/Commissioner  

APPENDIX A Page 1 of 2 

  

Utilities Commission Act Section 44.1  Long‐term resource and conservation planning 

44.1  (1) [Repealed 2010‐22‐65.] 

(2) Subject to subsection (4), a public utility must file with the commission, in the form and at the times the commission requires, a long‐term resource plan including all of the following: 

(a) an estimate of the demand for energy the public utility would expect to serve if the public utility does not take new demand‐side measures during the period addressed by the plan; 

(b) a plan of how the public utility intends to reduce the demand referred to in paragraph (a) by taking cost‐effective demand‐side measures; 

(c) an estimate of the demand for energy that the public utility expects to serve after it has taken cost‐effective demand‐side measures; 

(d) a description of the facilities that the public utility intends to construct or extend in order to serve the estimated demand referred to in paragraph (c); 

(e) information regarding the energy purchases from other persons that the public utility intends to make in order to serve the estimated demand referred to in paragraph (c); 

(f) an explanation of why the demand for energy to be served by the facilities referred to in paragraph (d) and the purchases referred to in paragraph (e) are not planned to be replaced by demand‐side measures; 

(g) any other information required by the commission. 

(3) The commission may exempt a public utility from the requirement to include in a long‐term resource plan filed under subsection (2) any of the information referred to in paragraphs (a) to (f) of that subsection if the commission is satisfied that the information is not applicable with respect to the nature of the service provided by the public utility 

(4) [Repealed 2010‐22‐65.] 

(5) The commission may establish a process to review long‐term resource plans filed under subsection (2). 

(6) After reviewing a long‐term resource plan filed under subsection (2), the commission must 

(a) accept the plan, if the commission determines that carrying out the plan would be in the public interest, or 

(b) reject the plan. 

(7) The commission may accept or reject, under subsection (6), a part of a public utility's plan, and, if the commission rejects a part of a plan, 

(a) the public utility may resubmit the part within a time specified by the commission, and 

APPENDIX A Page 2 of 2 

  

(b) the commission may accept or reject, under subsection (6), the part resubmitted under paragraph (a) of this subsection. 

(8) In determining under subsection (6) whether to accept a long‐term resource plan, the commission must consider 

(a) the applicable of British Columbia's energy objectives, 

(b) the extent to which the plan is consistent with the applicable requirements under sections 6 and 19 of the Clean Energy Act, 

(c) whether the plan shows that the public utility intends to pursue adequate, cost‐effective demand‐side measures, and 

(d) the interests of persons in British Columbia who receive or may receive service from the public utility. 

(9) In accepting under subsection (6) a long‐term resource plan, or part of a plan, the commission may do one or both of the following: 

(a) order that a proposed utility plant or system, or extension of either, referred to in the accepted plan or the part is exempt from the operation of section 45 (1); 

(b) order that, despite section 75, a matter the commission considers to be adequately addressed in the accepted plan or the part is to be considered as conclusively determined for the purposes of any hearing or proceeding to be conducted by the commission under this Act, other than a hearing or proceeding for the purposes of section 99. 

 

 APPENDIX B Page 1 of 1 

  

THE REGULATORY PROCESS   

ACTION  DATE (2010) 

Intervener Registration Deadline  September 14 

Procedural Conference  September 21 

Commission Information Request No. 1  September 22 

Intervener Information Requests No. 1  September 28 

Terasen Utilities Responses to Information Requests No. 1  October 18 

Commission and Intervener Information Requests No. 2  October 28 

Terasen Utilities Responses to Information Requests No. 2  November 8 

Submissions on the Need for a Second Procedural Conference  November 10 

Terasen Utilities Final Argument  November 16 

Interveners’ Final Arguments  November 30 

Terasen Utilities Reply  December 10 

  The Commission received Final Arguments from BCOAPO, BCSEA and the CEC.  Terasen Utilities addressed the Intervenor Arguments in its Reply on December 10, 2010.   

APPENDIX C Page 1 of 1 

 2010 LONG TERM RESOURCE PLAN AND BRITISH COLUMBIA’S ENERGY OBJECTIVES 

   Source: Terasen Utilities Final Submission, pp. 7‐8  

PROVINCE OF BRITISH COLUMBIA REGULATION OF THE MINISTER OF

ENERGY, MINES AND PETROLEUM RESOURCES

Ministerial Order No.

1, Richard Neufeld, Minister of Energy, Mines and Petroleum Resources, order that the attached regutation is made.

I NOV 7 2008 1

wavawz bef h,ao d Minister of Energy, Mines and

Petroleum Resources

(7hi1pan h for dminitlroh've purpores only mui b not pan of <he Order) Authority under which Order is made:

Act and section:- utilities Commission Act, R.s.B.C. 1996, c. 473. s. 125. 1 (4) (e)

Other (specify):-

November 3,2008 a1 175n008n7

APPENDIX D Page 1 of 5

DEMAND-SIDE MEASURES REGULATION

Definitions

1 In this regulation:

"Act" means the Utilities Commisswn Act;

"bulk electricity purchaser" means a public utility that purchases electricity from the authority for resale to the public utility's customers;

"community engagement program" means a program delivered by (a) a public utility to a public entity either

(if to increase the public entity's awareness about ways to increase energy conservation and energy efficiency or to encourage the public entity to conserve energy or use energy efficiently, or

(ii) to assist the public entity to increase the public's awareness about ways to increase energy conservation and energy efficiency or to encourage the public to conserve energy or use energy efficiently, or

(b) a public utility in cooperation with a public entity to increase the public's awareness about ways to increase energy conservation and energy efficiency or to encourage the public to conserve energy or use energy efficiently;

"education program" means an education program about energy conservation and efficiency, and includes the funding of the development of such a program;

"energy device" has the same meaning as in the Energy EBciency Act: "energy efficiency training" means training for persons who

(a) manufacture, sell or install energy-efficient products, (b) design, construct or act as a real estate bmker with respect to

energy-efficient buildings, (c) manage energy systems in buildings, or (d) conduct energy efficiency audits;

"energy-using produet" has the same meaning as in the Energy EfFciency Act (Canada);

"expenditure portfolio" means the class of demand-side measures that is composed of all of the demand-side measures proposed by a public utility in an expenditure schedule submitted under section 44.2 of the Act;

"low-income household" means a household whose residents receive service from the public utility and who have, in a taxation year, a before-tax annual household income equal to or less than the low-income cut off established by Statistics Canada for that year for households of that type;

"plan portfolio" means the class of demand-side measures that is composed of all of the demand-side measures proposed by a public utility in a plan submitted under section 44.1 of the Act;

"pubtic awareness program" means a pmgram delivered by apublic utility

page 2 of 5

APPENDIX D Page 2 of 5

(a) to increase the awareness of the public, including the public utility's customers, about ways to increase energy conservation and energy efficiency or to encourage the public, including the public utility's customers, to conserve energy or use energy efficiently, or

(b) to increase participation by the public utility's customers in other demand-side measures proposed by the public utility in an expenditure portfolio or a plan portfolio

but does not include a program to increase the amount of energy sold or delivered by the public utility;

"public entity" means a local government, fmt nation, non-profit society incorporated under the Sociery Act or trade union;

"regulated item" means (a) an energy device, (b) an energy-using product, (c) a building design, or (d) thermal insulation;

"school" means a school regulated under the School Act or the Independent School Act;

"specitied demand-side measure" means (a) a demand-side measure referred to in section 3 (c) or (d), @) the funding of energy efficiency training, (c) a community engagement program, or (d) a technology innovation program;

*specified standard" means a standard in any of the following: (a) the Energy Efficiency Standards Regulation, B.C. Reg. 389193; (b) the Energy Efficiency Regulations S.0.R.194-651; (c) the British Columbia Building Code, if the standard promotes energy

conservation or the efficient use of energy; "technoIogy innovation program" means a program

(a) to develop a technology, a system of technologies, a building design or an industrial facility design that is

(i) not commonly used in British Columbia, and (ii) the use of which could directly or indirectly result in significant

reductions of energy use or significantly more efficient use of energy, (h) to do what is described in paragraph (a) and to give demonstrations to the

public of any results of doing what is described in paragraph (a), or (c) to gather information about a technology, a system of technologies, a

building design or an industrial design referred to in paragraph (a).

Application

2 (1) This regulation applies only with respect to demand-side measures pmposed by the authority.

page 3 of 5

APPENDIX D Page 3 of 5

(2) Effective June I, 2009, (a) subsection (I) is repeated, and (b) section 3 does not apply to a public utility that is owned or operated by a

local government or has fewer than 10,000 customers.

Adequacy

3 A public utility's plan portfolio is adequate for the purposes of section 44.1 (8) (c) of the Act only if the plan portfolio includes all of the following:

(a) a demand-side measure intended speeificaily to assist residents of low-income households to reduce their energy consumption;

(b) if the plan portfolio is submitted on or after June 1, 2009, a demand-side measure intended specifically to improve the energy efficiency of rental accommodations;

(c) an education program for students enrolled in schools in the public utility's service area,

(d) if the plan portfolio is submitted on or after June 1, 2009, an education program for students enrolled in post-secondary institutions in the public utility's service area.

Cost effectiveness

4 (1) Subject to subsections (4) and (5). the commission, in determining for the purposes of section 44.1 (8) (c) or 44.2 (5) (d) of the Act the cost-effectiveness of a demand-side measure proposed in an expenditure portfolio or a plan portfolio, may compare the costs and benefits of (a) the demand-side measure individually, (b) the demand-side measure and other demand-side measures in the portfolio,

or (c) the portfolio as a whole

(2) In determining whether a demand-side measure referred to in section 3 (a) is cost effective, the commission must, (a) in addition to conducting any other analysis the commission considers

appropriate, use the total resource cost test, and (b) in using the total resource cost test, consider the benefit of the demand-side

measure to be 130% of its value when determined without reference to this subsection.

(3) In determining whether a demand-side measure of a bulk electricity purchaser is cost-effective, the commission must consider the benefit of the avoided supply cost to be the authority's long-term marginal cost of acquiring new electricity to replace the electricity sold to the bulk electricity purchaser and not the bulk electricity purchaser's cost of purchasing electricity from the authority.

(4) The commission must determine the cost-effectiveness of a specified demand-side measure proposed in a plan portfolio or an expenditure portfolio by determining whether the portfolio is cost effective as a whole.

page 4 of 5

APPENDIX D Page 4 of 5

(5) If the commission is satisfied that a public awareness program proposed in a plan portfolio or an expenditure ponfolio is likely to accomplish the goals set out in paragraph (a) or (b) of the defmition of "public awareness program", the commission must determine the cost-effectiveness of the program by determining whether the portfolio is cost-effective as a whole.

(6) The commission may not determine that a proposed demand-side measure is not cost effective on the basis of the result obtained by using a ratepayer impact measure test to assess the demand-side measure.

(7) In considering the benefit of a demand-side measure that, in the commission's opinion, will increase the market share of a regulated item with respect to which there is a specified standard that has not yet commenced, the commission may include in the benefit a proportion of the benefit that, in the commission's opinion, will result from the commencement and application of the specified standard with respect to the regulated item.

page 5 of 5

APPENDIX D Page 5 of 5

APPENDIX E Page 1 of 3 

 IN THE MATTER OF 

the Utilities Commission Act, R.S.B.C. 1996, Chapter 473  

and  

Terasen Gas Inc., Terasen Gas (Vancouver Island) Inc. and Terasen Gas (Whistler) Inc.  2010 Long Term Resource Plan  

Project No.  

EXHIBIT LIST 

 Exhibit No.  Description  COMMISSION DOCUMENTS  A‐1  Letter dated August 4, 2010 – Appointment of Commission Panel 

A‐2  Letter dated August 4, 2010 –  Preliminary regulatory timetable 

A‐3  Letter dated August 10, 2010 –  Amended regulatory timetable 

A‐4  Letter dated September 22, 2010 – Commission Information Request No. 1 

A‐5  Letter dated September 24, 2010 – Reasons for Decision and Regulatory Timetable 

A‐6  Letter dated October 28, 2010 – Commission Information Request No. 2 

A‐7  Letter dated October 28, 2010 – Start Time for Second Procedural Conference 

 A2‐1  Letter dated October 27, 2010 – BCUC Staff Submission “Retail Markets 

Downstream of the Utility Meter Guidelines (April 2007)” 

A‐8  Letter dated November 12, 2010 – Second Procedural Conference cancelled 

 APPLICANT DOCUMENTS TUS  B‐1  TERASEN GAS INC., TERASEN GAS (VANCOUVER ISLAND) INC. AND TERASEN GAS (WHISTLER) INC. 

(TUS)  Letter dated July 15, 2010 ‐  Application for 2010 Long Term Resource Plan   

B‐2  Letter dated October 18, 2010 – REVISED Filing to BC Hydro IR No. 1 to include Attachments  

APPENDIX E Page 2of 3   Exhibit No. Description  B‐3  Letter dated October 18, 2010 – TUS Filing Response to BCOAPO IR No.1 

B‐4  Letter dated October 18, 2010 – TUS Filing Response to BCSEA IR No.1 

B‐5  Letter dated October 18, 2010 – TUS Filing Response to BCUC IR No.1 

B‐6  Letter dated October 18, 2010 – TUS Filing Response to CEC IR No.1 

B‐6‐1  Letter dated November 8, 2010 – TUS Filing Erratum to CEC  IR1.22.4 

B‐7  Letter dated November 8, 2010 – TUS Filing Response to BCOAPO IR No.2 

B‐8  Letter dated November 8, 2010 – TUS Filing Response to BCSEA IR No.2 

B‐8‐1  Letter dated November 8, 2010 – CONFIDENTIAL Attachment 23.1 BCSEA IR2 

B‐9  Letter dated November 8, 2010 – TUS Filing Response to CEC IR No.2 

B‐10  Letter dated November 8, 2010 – TUS Filing Response to BCUC IR No.2 

B‐11  Letter dated November 10, 2010 – TUS Submissions on Second Procedural Conference 

 INTERVENOR DOCUMENTS  C1‐1  MINISTRY OF ENERGY, MINES AND PETROLEUM RESOURCES (MEMPR) Online registration 

dated September  9, 2010 ‐ Request for Intervener Status by Erik Kaye 

C2‐1  BRITISH COLUMBIA HYDRO AND POWER AUTHORITY (BCH) – Online registration dated September  13, 2010 ‐ Request for Intervener Status by Joanna Sofield 

C2‐2  Letter dated September 28, 2010 – BCH Filing Information Request No. 1 to TUS 

C3‐1  BC SUSTAINABLE ENERGY ASSOCIATION AND SIERRA CLUB OF BRITISH COLUMBIA CHAPTER (BCSEA)‐ Online Registration dated September 13, 2010 ‐ Filing Intervener Registration by William  Andrews and Thomas Hackney  

C3‐2  Letter dated September 28, 2010 – BCSEA Filing Information Request No. 1 

C3‐3  Letter dated October 28, 2010 – BCSEA Filing Information Request No. 2 

C3‐4  Letter dated November 10, 2010 – BCSEA Submissions on Second Procedural Conference  

APPENDIX E Page 3 of 3 

  Exhibit No. Description  C4‐1  BRITISH COLUMBIA OLD AGE PENSIONERS’ ORGANIZATION (BCOAPO) VIA EMAIL  Letter Dated 

September 14, 2010  ‐ Request for Intervener Status by Jim Quail and James Wightman 

C4‐2  Letter dated September 28, 2010 – BCOAPO Filing Information Request No. 1 

C4‐3  Letter dated October 28, 2010 – BCOAPO Filing Information Request No. 2 

C4‐4  Letter dated November 10, 2010 – BCOAPO Submissions on Second Procedural Conference  

C5‐1  COMMERCIAL ENERGY CONSUMERS ASSOCIATION OF BRITISH COLUMBIA (CEC) – Letter dated September 20, 2010 – Request for Intervener Status by Owen Bird Law Corporation 

C5‐2  Letter dated September 30, 2010 – CEC Filing Information Request No. 1 

C5‐3  Letter dated October 28, 2010 – CEC Filing Information Request No. 2 

C5‐4  Letter dated November 10, 2010 – CEC Submissions on Second Procedural Conference 

 

  

  

IN THE MATTER OF    

CORIX MULTI‐UTILITY SERVICES INC.  

NEIGHBOURHOOD UTILITY SERVICE AT UNIVERCITY BURNABY 

 CERTIFICATE OF PUBLIC CONVENIENCE AND NECESSITY 

   

DECISION     

May 6, 2011      

BEFORE:  

D. A. Cote, Commissioner L. A. O’Hara, Commissioner D. Morton, Commissioner 

 

TABLE OF CONTENTS 

  Page No. 

 

1.0  EXECUTIVE SUMMARY  1 

2.0  INTRODUCTION  4 

2.1  The Applicant  4 

2.2  Key Stakeholders  4 

2.3  Orders Sought  7 

2.4  Regulatory Process  7 

2.5  Evolving Energy Environment  7 

3.0  PROJECT DESCRIPTION  9 

3.1  Background and Need  9 

3.2  Load Analysis and Energy Demand Forecast  9 

3.3  Project Alternatives  10 

3.3.1  Screening Analysis  10 

3.3.2  Potential for Combined Solution for UniverCity and SFU Campus  12 

3.4  Project Scope  12 

3.4.1  Description of District Energy System  12 

3.4.2  Production Facilities  14 

3.4.3  Thermal Distribution System and Energy Transfer Stations  17 

3.5  Implementation Schedule  17 

4.0  PROJECT COSTS AND RATE STRUCTURE  19 

4.1  Capital Costs  19 

4.2  Capital Contribution and Incentives  20 

4.3  System Operating Costs  20 

4.4  Debt and Equity Financing  22 

4.4.1 Capital Structure  22 

4.4.2  Debt Cost  23 

4.4.3  Return on Equity  23 

4.5  Revenue Requirements  24 

4.6  Rate Design  25 

TABLE OF CONTENTS 

  Page No. 

 

4.7  Project Risk  26 

4.8  Proposed Levelized Rate  27 

5.0  KEY ISSUES  28 

5.1  Introduction  28 

5.2  Adequacy of Public Consultation  28 

5.3  Alignment with Clean Energy Act and Provincial Government Policy  30 

5.3.1  Alignment with British Columbia’s Energy Objectives  30 

5.3.2  Approved Integrated Resource Plan  30 

5.3.3  Requirements under Sections 6 and 19 of the Clean Energy Act  31 

5.4  Availability and Costs of Biomass  31 

5.5  Load Analysis and Energy Forecast  33 

5.6  Consideration of Agreements with SFU Trust and BC Hydro  34 

5.7  Risk of Stranded Assets  35 

5.8  Adequacy of Project Description  37 

5.9  Adequacy of Project Cost Estimates  40 

6.0  COMMISSION DECISION AND DETERMINATIONS  42 

6.1  Commission Decision  42 

6.2  Further Determinations  44 

6.2.1  Rate Design  45 

6.2.2  Capital Structure  45 

6.2.3  Debt Cost  45 

6.2.4  Return on Equity  46 

6.2.5  Levelized Rates  49 

6.2.6  Terms and Conditions of Service  49 

7.0  COMMISSION PANEL COMMENT  50 

8.0  SUMMARY OF DIRECTIVES  51 

 

   

TABLE OF CONTENTS 

  Page No. 

 

COMMISSION ORDER C‐7‐11  APPENDICES  APPENDIX A  Regulatory Timetable APPENDIX B  Clean Energy Act APPENDIX C  List of Exhibits    

  

1.0  EXECUTIVE SUMMARY 

 

On November 26, 2010, Corix Multi‐Utility Services Inc. (CMUS or the Company) filed an 

Application for a Certificate of Public Convenience and Necessity (CPCN) under sections 45 and 46 

of the Utilities Commission Act (the Act) to construct and operate an alternative energy‐based 

district energy system for the UniverCity residential community on Burnaby Mountain.  The 

Company also sought approval  under sections 56, 60, and 61 of the Act for a deemed capital 

structure, Return on Equity (ROE), long term debt financing costs, a levelized rate structure and a 

revenue deficiency deferral account. 

 

UniverCity is being developed by Simon Fraser University (SFU) Trust in four Phases.  This 

application pertains to Phases 3 and 4 which were started in 2011 with a completion date 

scheduled for 2019.  The objective of SFU Trust is to implement alternative energy technologies to 

achieve reductions in GHG emissions and enhance the sustainability of the UniverCity community.  

Accordingly, SFU Trust is mandated to develop UniverCity in a sustainable manner and building 

developers must adhere to a set of green building requirements. 

 

The proposed district energy system consists of a production facility and a distribution system.  The 

production facility is planned to be built in two steps; a natural gas fuelled temporary Central 

Energy Plant (CEP) followed in 2016 by a permanent CEP fuelled by an alternative energy source 

likely to be Biomass.  Both of these will be supported by a distribution system consisting of main 

trunk pipes, branch connections and energy transfer stations which will be constructed using a 

phased approach.  Based on the anticipated energy intensities of the expected types of buildings, 

CMUS estimates peak heating load at 5.7 MW with annual heat sales of 14,020 MWh. 

 

In assessing the alternative energy sources a number of options were considered and following a 

screening analysis CMUS has proposed using Biomass to provide the base load energy for the 

permanent CEP.  In addition, the potential for a combined solution for UniverCity and SFU campus 

as well as the data centre option remains under consideration. 

 

2   

The total capital costs for the temporary and permanent CEPs are forecast to be $12.215 million 

over the nine year development period.  The developers will make a contribution of $1.00 per 

square foot of buildable area on each development parcel which is expected to defray 

$2.223 million of these costs.  In addition, BC Hydro through its Power Smart Sustainable 

Communities Program has indicated support for the project.  The parties are in the process of 

developing an agreement which is estimated will provide a capital incentive of $1.3 million to 

CMUS following implementation of the permanent CEP.  Operating costs for the permanent CEP 

are estimated at $319,000 annually in 2017. 

 

During the review process the Commission Panel identified the following key issues: 

 

• Adequacy of Public Consultation; 

• Alignment with Clean Energy Act and Provincial Government Policy; 

• Availability and Costs of Biomass; 

• Adequacy of the Load Analysis and Energy Forecast; 

• Consideration of Agreements with SFU Trust and BC Hydro; 

• Risk of Stranded Assets; 

• Adequacy of Project Description; and 

• Adequacy of Cost Estimates. 

 

After considering these key issues, the Commission Panel has determined there is sufficient 

evidence to support partial acceptance of this CPCN Application.  Accordingly, the Panel grants a 

CPCN for the temporary CEP but does not approve at this time construction of the permanent CEP.  

The Panel is supportive of the alternative energy solution but is concerned with the lack of 

certainty and detail related to it.  In accordance with this, the Panel has suspended further 

consideration of this matter until CMUS is able to more adequately meet the requirements as 

outlined in this Decision. 

 

For the purpose of determining the rates to be changed the Commission Panel has, among other 

things, also approved the following: 

3  

  

• A Premium of 50 basis points over the benchmark ROE; 

• The proposal to finance 60 percent of the rate base with deemed debt and the remaining 40 percent with common equity; 

• A debt rate of 6 percent; 

• The proposal for a rate design with a 60 percent fixed monthly charge and a 40 percent variable charge but to be recalculated using a 20 year levelized rate based solely on the temporary CEP. 

 

 

   

4   

2.0  INTRODUCTION 

 

This Decision deals with an application by Corix Multi‐Utility Services Inc. for a Certificate of Public 

Convenience and Necessity to construct and operate an alternative energy‐based district energy 

system (DES) for UniverCity, a residential community being developed on Burnaby Mountain (the 

Application).  The DES, which consists of a central energy plant, a distribution piping system and 

energy transfer stations, will provide thermal energy service for space heating and hot water to this 

community. 

 

The proposed Biomass based DES will be developed in phases with early building loads served by a 

temporary natural gas boiler plant that will be transitioned to what may be a permanent biomass‐

based central energy plant when the customer load reaches sufficient volume.  The rationale for 

this phased approach is to allow the utility to match capital investment with growth “while 

providing a flexible and economic solution for transition to renewable energy.”  (Exhibit B‐1, p. 6) 

 

2.1  The Applicant 

 

Corix Multi‐Utility Services Inc. is a subsidiary of Corix Utilities Inc. (Corix), a company incorporated 

in British Columbia and headquartered in Vancouver.  CMUS provides multi‐utility and energy 

utility services to customers across Canada and manages a portfolio of regulated utility systems in 

BC.  CMUS will be responsible for development and ownership of the Neighbourhood Utility Service 

(NUS), which is a community based utility with a primary responsibility to develop, implement, 

operate and maintain the district energy system. 

 

2.2  Key Stakeholders 

 

UniverCity is a residential community being developed by SFU Community Trust which is building a 

sustainable community that provides its residents with highly energy efficient buildings and a true 

live‐work‐play community.  Accordingly, the environmental benefits associated with a DES based 

on alternative energy sources are attractive to the SFU Community Trust. 

5  

  

BC Hydro has entered into discussions with CMUS to provide a capital incentive to build the NUS at 

UniverCity.  In addition to the CPCN, the NUS will require a building and development permit from 

the City of Burnaby to construct the central energy plant.  Urban Wood Waste Recyclers have 

entered into discussions to develop a fuel supply agreement for the UniverCity NUS Biomass 

project.  Both BC Hydro and Urban Wood Waste Recyclers have submitted Letters of Interest to 

Corix.  (Exhibit B‐1, Appendix B) 

 

The proposed project will influence different groups of individuals which should be considered 

from the public interest perspective.  The first group is the ratepayers who include current and 

future purchasers of Phase 3 and Phase 4 of the UniverCity development.  The second group is 

made up of those in the surrounding area who may be affected by the project.  The third group is 

comprised of the general public who stand to gain because of reduced carbon emissions and GHG 

levels. 

 

6   

The following diagram depicts the key stakeholders of the project. 

 

7  

  

2.3  Orders Sought 

 

The Company is seeking the following: 

 1. A CPCN under Sections 45 and 46 of the Utilities Commission Act (Act, UCA) for the 

construction and operation of a proposed community‐based district energy system at UniverCity, Burnaby, BC;  

2. Approval under sections 56, 60 and 61 of the Act of the proposed revenue requirements, rate design and rates described in the Application; specific approvals requested in this area include:  

• A deemed capital structure of 60 percent debt and 40 percent equity; 

• Long‐term debt financing costs estimated at 7.0 percent, subsequently revised down to 6.5 percent (Exhibit B‐3‐1, BCUC 1.17.4) and a ROE that is 200 points above the benchmark utility; (Exhibit B‐1, p. 26) 

• A 20‐year levelized rate structure and rate design of 60 percent fixed and 40 percent variable; and 

• A revenue deficiency deferral account which is to capture those portions of revenue requirements which are not recovered in the early stages of development.  (Exhibit B‐1, pp. 11‐12) 

 

2.4  Regulatory Process 

 

The review of the Application was conducted by way of a written proceeding.  The only Intervener 

was FortisBC Energy Inc. (formerly Terasen Gas Inc.).  The Regulatory Timetable is summarized in 

Appendix A. 

 

2.5  Evolving Energy Environment 

 

This Application is an illustration of the evolving energy environment driven by both society at large 

as well as the initiatives and legislation introduced by the Provincial Government.  One of the 

earlier similar examples is the Dockside Green Energy (DGE) Project in Victoria, BC.  The  

8   

Commission granted a CPCN to the DGE in April 2008 to construct and operate a district energy 

system to provide energy service to the Dockside Green development built on the Inner Harbour in 

Victoria.  (Order C‐1‐08) 

 

In the 2007 BC Energy Plan the Provincial Government introduced a series of initiatives intended to 

reduce GHG missions, improve energy efficiency and conservation and to achieve sustainability.  In 

particular, the plan provided policy guidelines in the area of alternative energy that support the 

development of non‐traditional sources of energy and encourage conservation to enable the 

Province to achieve electrical energy self‐sufficiency by 2016. 

 

CMUS states that the implementation of an alternative energy‐based district energy system aligns 

with the Provincial Government’s green energy objectives under the 2007 BC Energy Plan and the 

Clean Energy Act (CEA) because it will result in energy savings and will ultimately provide a benefit 

of Green House gas (GHG) reductions to the whole community on Burnaby Mountain.  (Exhibit B‐1, 

pp. 6, 52) 

 

Relevant sections of the CEA are reproduced in Appendix B. 

 

 

   

9  

 3.0  PROJECT DESCRIPTION 

 

3.1  Background and Need 

 

The development is on land adjacent to the SFU campus.  Property in the UniverCity development 

is leased by the SFU Community Trust (SFU Trust) to private developers on 99 year prepaid leases. 

 

UniverCity is being developed in four Phases.  The buildings in Phase 1 and Phase 2 have already 

been completed and are not part of this Application.  Phases 3 and 4 were begun in 2011, with 

completion scheduled for 2019.  When completed, the total development area is projected to be 

206,572 square meters, of which 99 percent will be multi‐unit residential and 1 percent 

commercial/office/daycare.  (Exhibit B‐1, p. 13‐14) 

 

CMUS states that SFU Trust has identified the NUS as one of the ways to enhance sustainability of 

the UniverCity community.  Developers of Phase 3 and Phase 4 are required to adhere to a set of 

green building requirements.  The Trust’s objectives are to provide community residents and 

businesses with cost‐competitive thermal energy thereby enhancing the environmental 

performance of the development.  CMUS submits that the NUS will be the exclusive provider of 

thermal energy services for both space heating and domestic hot water for Phases 3 and 4 of 

UniverCity, as well as Parcel 25.  (Exhibit B‐1 p. 13)  CMUS also states that the City of Burnaby’s 

Bylaw No. 12760 requires the developer to comply with the UniverCity Design Guidelines and 

Requirements.  The Green Building Requirements in that Bylaw also require the developers to build 

a thermal energy system that is compatible and able to connect to the NUS and prohibits them 

from using electric resistance heating.  (Exhibit B‐4, BCUC 2.2.1, 2.2.2) 

 

3.2  Load Analysis and Energy Demand Forecast 

 

Based on the development schedule as provided by SFU Trust and anticipated energy intensities of 

the expected types of buildings, CMUS estimates the peak heating load at 5.7 MW with annual 

energy sales of 14,020 MWh.  The annual demand forecast reflecting the build out of new units 

10   

over the period is listed in Table 1 (below). 

 

Annual Demand Forecast Table 1 

 Source: (Exhibit B‐1, p. 16) 

 

CMUS states that this data was used to construct the load duration curve to facilitate proper sizing 

of the energy system to satisfy load requirements.  (Exhibit B‐1, pp. 14‐16) 

 

CMUS has noted that the demand forecast has a high level of uncertainty and will require actual 

operating experience before the energy demand can be forecasted with any degree of accuracy.  In 

fact, CMUS states that it has no assurance that it will achieve the projected customer base.  In 

addition, the developer of each building will have the option of implementing onsite efficiency 

measures.  The potential exists for the efficiency of the building to be increased with a 

corresponding decrease in energy use from the CEP.  (Exhibit B‐1, pp. 24‐28) 

 

3.3  Project Alternatives 

 3.3.1  Screening Analysis 

 

CMUS has focused the screening analysis on alternative energy sources for fuelling the CEP.  The 

following scenarios were modelled: 

 

• Local Sewer Flows; 

• Energy from the ground source heat pumps (GSHPs); 

• Waste energy captured from the data centre (Data Centre); 

• Available woody residues (Biomass); and 

• Natural Gas in a co‐generation scheme (Cogeneration) 

11  

  

CMUS presented a screening analysis of the above alternatives compared to a base case of natural 

gas heating.  The local sewer option was combined with the GSHPs because the Company claimed 

there was insufficient heat recovered from the sewer system alone.  The screening analysis criteria 

were: 

 

• Land Area for plant 

• Alternative energy delivered 

• Natural Gas and/or electricity used  

• Inputs 

• Maintenance and Staff Costs 

• Capital Costs 

• Natural Gas costs  

• Electricity Cost 

• Alternate Fuel Costs 

• Payback in years at current utility pricing 

• Payback in years at future utility pricing 

• Greenhouse Gas savings 

 

CMUS states that payback times for the Data Centre and the Biomass option were under 20 years, 

while the Cogeneration option was approximately 38 years and the Sewer/GSHP was greater than 

50 years.  GHG savings for the Sewer/GSHP, Data Centre and Biomass were approximately 

2,400 tonnes as compared to the natural gas and electricity base case, while the Cogeneration 

option produced 4,300 additional tonnes over the base case.  (Exhibit B‐1, p. 17) 

 

Based on results of the screening analysis, CMUS eliminated both the sewer and the Natural Gas 

Cogeneration options.  The Biomass and the data centre heat pump options were selected for 

further analysis.  (Exhibit B‐1, p. 19) 

 

   

12   

For the Data Centre option, CMUS considered using the waste heat from SFU’s new data centre.  

The new facility is part of a five year capital plan prepared by SFU in 2008.  A funding application for 

the upgrades to the building to house the data centre was not approved.  Consequently, SFU is 

continuing to develop the new data centre in phases, but there is currently no approved capital 

budget and the development plan is 1‐2 years behind schedule.  Accordingly, the Company 

suspended consideration of the data centre due to the development risk, but states that it may 

look at it again if the data centre proceeds.  (Exhibit B‐3, BCUC 1.7.1, 1.7.2, 1.7.2.1, 1.7.2.2) 

 

As a result of the screening analysis, CMUS provided a further detailed technical and cost analysis 

of its proposal to use Biomass for the base load energy for the permanent CEP.  (Exhibit B‐1, p. 33) 

 

3.3.2  Potential for Combined Solution for UniverCity and SFU Campus 

 

As an additional solution CMUS states that Corix, SFU and SFU Community Trust are collectively 

working together to assess the potential of a combined solution to provide thermal energy to 

UniverCity residents as well as the SFU campus (Combined Solution).  This scenario calls for a 

Biomass based central energy plant to be implemented earlier than the smaller scale NUS CEP.  

CMUS reports that applications for assistance funding filed jointly with SFU Campus are being 

considered by various agencies.  (Exhibit B‐1, p. 21) 

 

There is no specific plan in place at this time for the Combined Solution although its 

implementation could be as early as 2012.  The Company confirms this would eliminate the need 

for the stand‐alone NUS that is proposed in this Application.  (Exhibit B‐3, BCUC 1.11.2) 

 

3.4  Project Scope 

 3.4.1  Description of District Energy System 

 

The NUS plans to operate a DES to supply the space heating and domestic hot water to the 

required buildings from a central plant.  As outlined in Diagram 2, the DES consists of a CEP and a 

Distribution System connected to buildings within the development.  The CEP, which produces the 

13  

 energy for domestic hot water and space heat for the UniverCity development, will be built in two 

steps.  The first step is a temporary CEP, fuelled by natural gas which will be followed in 2016 with 

a permanent CEP fuelled by an alternative energy source. 

 

DIAGRAM 2 

DESCRIPTION OF DISTRICT ENERGY SYSTEM 

   Source:  Derived from Exhibit B‐1 

 

CMUS is investigating Biomass as the fuel source for the permanent CEP, but indicates that it may 

consider other fuel sources.  The permanent CEP will be situated in a different location from the 

temporary CEP.  (Exhibit B‐4, BCUC 2.40.2; Exhibit B‐3, BCUC 1.37.1) 

 

Energy from the CEP will be delivered to the residential units by the Distribution System, which will 

have the following three components: 

14   

 1. Main Trunk Distribution Pipes 

2. Branch Connections; and 

3. Energy Transfer Stations (ETS) 

  (Exhibit B‐1, p. 36) 

 

3.4.2  Production Facilities 

 

The Production Facilities generate the thermal energy for consumption by the residential units.  

This section describes these facilities, how they are fuelled and the disposal of waste from the 

combustion of biomass. 

 

Initially, the Production Facility will consist of a temporary CEP, which, according to CMUS, will be 

constructed in the fall of 2011 with a capacity of 1.9 MW.  The temporary CEP will be able to meet 

forecast loads up to 2013.  At that time, additional boilers will increase the capacity up to 4.4 MW 

which will be sufficient to meet forecast loads up to 2016, after which the permanent CEP will be in 

place.  (Exhibit B‐1, pp. 3, 37, 48) 

 

CMUS states that the boilers and variable speed pumps from the temporary CEP may be moved to 

the Biomass plant to provide peaking and backup power.  All other items, including engineering, 

electrical and mechanical installations will not be reusable, although the building enclosure may 

have some salvage value.  (Exhibit B‐4, BCUC 2.19.3) 

 

The proposed permanent CEP will be located on property south of the intersection of Tower Road 

and South Science Road.  The site is currently owned by SFU and is zoned for institutional use.  The 

BC Hydro Right‐of‐Way (ROW) is close to the proposed location as is the Telus ROW.  Detailed 

discussions with BC Hydro and Telus concerning the ROWs were not completed at the time of the 

Application, but CMUS attests that it will work in close cooperation with SFU Trust on the ROW 

requirements.  (Exhibit B‐4, BCUC 2.40.1) 

 

15  

 CMUS reports the proposed location of the permanent CEP is in a forested area with water stream 

crossings.  CMUS notes that no environmental assessment has yet been conducted, although one 

will be completed before the detailed design of the permanent CEP commences.  Furthermore, 

CMUS states that noise, air emissions, traffic impacts, and geotechnical assessments will not be 

completed until later in the design and engineering phase of the permanent CEP.  (Exhibit B‐1, 

pp. 46‐47)  A truck access route has not been determined at this time.  (Exhibit B‐4, BCUC 2.39.1) 

 

CMUS has not provided specific details about the technology of the Biomass plant.  The Company 

states that it is proposing a flexible approach to developing the NUS in order to accommodate 

changes in technology and allow decisions to be made when they are required to ensure the most 

appropriate technology is selected.  (Exhibit B‐3, BCUC 1.36.6)  It further states that the technical 

solution for the NUS is flexible enough to incorporate the data centre, should it be developed.  

(Exhibit B‐3, BCUC 1.7.2.2) 

 

Also worthy of note is that CMUS recognizes the uncertainty related to evolving technologies and 

solutions and suggests an approach that would allow it to continue to explore and evaluate the 

best biomass solutions.  (Exhibit B‐4, BCUC 2.33.1) 

 

Biomass Fuel Supply 

 

To fuel the permanent CEP, CMUS is principally targeting woody biomass material from clean 

sources such as forestry residues and also municipal or urban generated woody residues or clean 

construction and demolition waste.  CMUS estimates the amount of biomass (woody residue) 

required to meet the annual energy requirement at up to 8,000 “green” tonnes per year 

(approximately 4,000 “bone‐dry” tonnes).  CMUS states that it will require an estimated 11 

deliveries per five day work‐week in order to meet peak heating demand over a seven day period.  

(Exhibit B‐1, p. 39) 

 

   

16   

CMUS has identified a number of risks associated with the fuel for the biomass systems.  Included 

among these are variances in feedstock consistency, the impact of foreign substances and 

oversized feedstock as well as maintenance considerations.  It claims that while these issues add 

additional risk to the operation of biomass system, they can be managed with careful design, good 

practice and operational experience.  (Exhibit B‐4, BCUC 2.11.1) 

 

CMUS submits there are suppliers in the Vancouver area that collect, process and sell Biomass for 

boiler systems.  (Exhibit B‐1, p. 39)  Included among these are the City of Burnaby, Urban Wood 

Waste Recyclers and several tree services companies.  The Company states that it used preliminary 

discussions with potential fuel suppliers as a means of establishing the forecast price of $30/tonne 

as well as the availability of fuel.  (Exhibit B‐1, pp. 22‐23)  In response to numerous Commission 

staff information requests with respect to pricing and supply, CMUS submits that it will be 

undertaking a wood waste supply study in 2011 and continues by stating “we will continue to be in 

contact with potential wood suppliers to keep current on the availability of potential wood waste 

supply should a decision be made to proceed with a biomass solution”.  (Exhibit B‐3, BCUC 1.12.9)  

While currently unable to estimate the amount of feedstock in the region, the Company believes it 

to be substantial.  (Exhibit B‐4, BCUC 2.18.2)  With respect to pricing CMUS states that it has a high 

confidence level that the price for Biomass will fall between a range from plus 50 percent to minus 

50 percent against the base case projections of $30 per ton.  (Exhibit B‐3, BCUC 1.15.1) 

 

Waste Ash Disposal 

 

CMUS states the biomass boiler will produce an estimated amount of bottom ash of approximately 

220 tonnes per year.  CMUS maintains that the testing of the bottom ash will be done regularly to 

prevent any potential contaminants to be land filled.  (Exhibit B‐3, BCUC 1.37.6)  The ash can be 

used as a fertilizer if the testing is favourable, however CMUS has not completed any analysis as 

the fuel source is not yet determined.  (Exhibit B‐3, BCUC 1.37.1)  As a result, the opportunities for 

potential salvage of the bottom ash remain unknown.  If the bottom ash would not be suitable for 

beneficial use, it will be sent to the landfill.  (Exhibit B‐3, BCUC 1.37.6.3)  Bottom ash which contains 

leachate levels in excess of the allowable provincial standards must be disposed of in a facility 

17  

 licensed to receive this material such as the facility located in Princeton, BC.  (Exhibit B‐4, 

BCUC IR 2.37.3) 

 

3.4.3  Thermal Distribution System and Energy Transfer Stations 

 

The Thermal Distribution System (TDS) consists of all of the pumps, piping and ducting required to 

transfer the thermal energy from the Production Facility to the Energy Transfer Station (ETS). 

 

The ETS are located in the residential buildings at the point of transfer between the Distribution 

System and the building’s internal heating system.  The key components of the ETS are: 

 

• Shut off valves 

• Pipes between the shut off valves and the heat exchangers used to provide heat 

• Controls to regulate the flow of heat 

• Energy meters 

• Separate heat exchangers for space heating and domestic hot water 

 

CMUS proposes a phased approach for both the TDS and the ETS implementation to match the 

planned development schedule of the residential units.  (Exhibit, B‐1, pp. 40‐50) 

 

3.5  Implementation Schedule 

 

The implementation schedule for the NUS is driven by the development schedule set by SFU Trust.  

CMUS has provided a phased schedule covering a period of 10 years, through completion of build‐

out. 

 

18   

Development Schedule 

Milestone  Date 

DES required for the first of the Phase 3 buildings.  DES consists of temporary 

NG facility with one boiler. 

2011 

2011 

Additional Boiler required for temporary CEP  2013 

Biomass Plant (1 Boiler)  2016 

Biomass Plant (additional boiler)  2018 

Completion of Phase 4 build out  2019 

(Source: Exhibit B‐4, BCUC 2.5.2) 

 

 

   

19  

 4.0  PROJECT COSTS AND RATE STRUCTURE 

 

4.1  Capital Costs 

 

CMUS states that it completed a feasibility assessment of the project and provided a capital cost 

estimate for the NUS (Exhibit B‐1, page 20 and 48), indicating that the total capital costs for the 

temporary and permanent plant is forecast to be $12.215 million over a period of 9 years. 

 Table 7 – Capital Costs Summary 

   (Source: Exhibit B‐1, page 20) 

 

Included in the temporary plant costs of the initial year (2011) are solar thermal panels estimated 

at $110,000 and the project development cost of $90,000. 

 

CMUS has applied a 5 percent optimization/reduction to both the Heating Plant capital and 

Distribution Piping System capital estimates while a 25 percent optimization/reduction is applied to 

the Energy Transfer Station capital estimate.  The optimization estimates are intended to reflect 

the current construction market conditions as compared to those in previous years which were 

considered as a baseline for development of the infrastructure cost.  CMUS claims that the capital 

cost estimate for the total Project has a P90 probability confidence level meaning that the total 

capital cost, 9 times out of 10, will be the within the estimated price.  Given the CMUS’ knowledge 

with these types of projects, the accuracy of the capital cost estimate for the CEP, the DPS, and the 

ETS has a Class 3 (‐15 percent and +25 percent) level of accuracy.  (Exhibit B‐3, BCUC 1.46.2)  CMUS 

also states that updates to the cost estimates and detailed breakdown of the various cost 

components will be provided to BCUC upon completion of the 50 percent design.  (Exhibit B‐3, 

BCUC 1.46.6) 

 

20   

4.2  Capital Contribution and Incentives 

 

Under the terms of the Infrastructure Agreement between Corix and SFU Trust, developers will 

make a contribution to the capital costs at the rate of $1.00 per square foot of buildable area on 

each development parcel.  CMUS indicates that this developer contribution (connection fee) is not 

affected by the implementation of only the temporary CEP  as the developers need to pay the 

connection fees at the time of the lease closing(Exhibit B‐4, BCUC 2.12.1.2). 

 

In addition, CMUS states that this Project is eligible under BC Hydro’s Power Smart Sustainable 

Communities Program which supports the implementation of a DES utilizing alternative energy 

sources for heating.  (Exhibit B‐1, p. 21)  This direct financial incentive would reduce CMUS’ funding 

requirement and improve the payback for the DES.  A Letter of Intent filed by BC Hydro is included 

as Appendix B in the Application and Corix and BC Hydro are in the process of developing an 

Incentive Agreement.  CMUS has included an estimated capital incentive of $1.3 million in 2016 

upon the development and implementation of an alternative energy system.  (Exhibit B‐1, p. 21)  

Although the agreement is not explicitly subject to approval of the entire project by the 

Commission, CMUS insists that it does not believe BC Hydro would negotiate an agreement if only 

the temporary solution was approved for development.  (Exhibit B‐4, BCUC 2.14.1) 

 

CMUS is also seeking other grant opportunities that could provide further financial benefits.  

However, details of the potential grants are not yet available.  (Exhibit B‐1, p. 21) 

 

4.3  System Operating Costs 

 

CMUS defines operating, maintenance and administrative costs to include costs for NUS employees 

salaries, training, office supplies, subcontractors and maintenance and repair services provided by 

maintenance personnel.  (Exhibit B‐1, p. 22)  Since the central energy plant will be built over time 

as new residential load is added, CMUS explains that the facility may not require a full‐time 

operator until the biomass boilers are installed in 2016. 

 

21  

 While the temporary CEP is operating on one or two boilers, CMUS is confident that it would be 

registered as a “General Supervision” plant meeting the requirements of section 55 of Safety 

Standard Act BC Reg. 104/2004.  As such, limited off site supervision via remote access and alarm 

monitoring will be acceptable.  (Exhibit B‐3, BCUC 1.14.1; Exhibit B‐4, BCUC 2.22.1)  General 

supervision allows for scheduled inspections rather than 24 hour supervision and is a key to a 

viable business case for this scale of system.  However, CMUS states that the final ruling of this 

status is determined solely by the BC Safety Authority and can only be finalized once equipment for 

the permanent CEP is selected.  (Exhibit B‐1, p. 44)  CMUS estimates that the initial operations and 

maintenance cost of the temporary boiler plant will be subcontracted at a cost of $30,000 per year, 

which includes basic emergency coverage and two site visits per week.  (Exhibit B‐1, p. 22) 

 

Insurance costs are estimated at $4,000 per year while office and administration costs are 

budgeted at $50,000 per year.  These include legal services, accounting, tax services, auditing, 

human resources, and regulatory costs. 

 

CMUS states that operating costs will increase in 2017 after implementation of the biomass plant.  

The bulk of the operating costs will be related to the full‐time operator at $200,000 per year plus 

2 percent annual escalation.  A breakdown of the system operating costs is detailed in Table 9 of 

the Application: 

   Table: 9 – Annual O&M Costs 

   (Source: Exhibit B‐1, p. 22)  

22   

4.4  Debt and Equity Financing 

 

4.4.1 Capital Structure 

 

CMUS states that it expects to finance 60 percent of the rate base with deemed debt and the 

remaining 40 percent with common equity.  (Exhibit B‐1, p. 24)  CMUS indicates that long‐term 

debt will be available through an inter‐company demand loan from CMUS to the NUS under which 

it may borrow, repay and re‐borrow funds as required.  Because the NUS will be financed using an 

intercompany loan, CMUS indicates that there will not be any fees, security requirements or 

covenants.  (Exhibit B‐3‐1, BCUC 1.17.2) 

 

Corix has borrowing capacity of $150 million through a $100 million revolving credit facility with a 

$50 million accordion (Exhibit B‐1, p. 9) although CMUS states that none of the capital structure will 

be financed by short term debt.  (Exhibit B‐3‐1, BCUC 1.17.3)  The Commission Panel notes that 

“The (Ontario Energy) Board has determined that short‐term debt should be factored into rate 

setting, and that a deemed amount should be included in the capital structures of electricity 

distributors.  The short‐term debt amount will be fixed at 4 percent of rate base.”  (Exhibit A‐2‐1, 

p. 9) 

 

CMUS rejects the appropriateness of including a 4 percent deemed short‐term debt for the NUS 

capital structure on the basis that “the assets that are being financed are long‐term assets and 

should be financed with long‐term debt.”  CMUS further adds that the “model currently projects no 

working capital in the project since working capital is expected to be small in relation to the rate 

base.  As such, the short‐term debt requirements for the project are negligible relative to the 

overall financing requirement and would have a negligible impact on the overall debt rate for the 

project.”  (Exhibit B‐4, BCUC 2.26.1) 

 

   

23  

 4.4.2  Debt Cost 

 

CMUS indicates that all debt will be financed at the same interest rate.  (Exhibit B‐3‐1, BCUC 1.17.3)  

CMUS is proposing that the interest rate be equal to the prevailing Benchmark Ten‐Year 

Government of Canada bond yield at time of funding plus a credit spread of 300 basis points.  This 

credit spread is based on the creditworthiness of SFU and the proposed capital structure.  CMUS 

notes that SFU is rated AA (low) by Dominion Bond Rating Services and Aa2 by Moody and the 

credit spread for entities with that credit risk is in the range of 200 basis points.  CMUS further 

submits that the “NUS warrants [an incremental 100 basis points in] credit spread over SFU 

because of the different security supporting the debt and the incremental risk associated with the 

project, including, but not limited to, development risk, utility operations risk and customer credit 

risk.”  Based on the current Benchmark Bond Yield, the proposed interest rate is 6.50 percent.  

(Exhibit B‐3‐1, BCUC 1.17.2 and 1.17.3)  CMUS is also proposing to fix the debt rate for a ten‐year 

period with any adjustments to the debt rate to be reflected in the revenue requirement 

applications that will be filed periodically with the Commission.  (Exhibit B‐3‐1, BCUC 1.17.4.1) 

 

Worthy of note is that the OEB “Cost of Capital Parameter Updates for 2011 Cost of Service 

Applications for Rates Effective January 1, 2011” dated November 15, 2010, indicates a Deemed 

Long‐term Debt Rate Forecast that includes an A‐rated Utility Bond Yield Spread September 2010 

of 1.539 percent for 30‐year debt.  (Exhibit A2‐2) 

 

4.4.3  Return on Equity 

 

CMUS believes that the NUS is a start up company and does not share the advantages of the 

benchmark utility.  As such, CMUS is requesting a risk premium of 200 basis points above the 

benchmark utility (FortisBC Energy Inc.).  (Exhibit B‐1, pp. 24‐26)  CMUS states that the proposed 

risk premium is reasonable in order to compensate for the additional development business risks 

faced by the NUS utility as described in Section 4.7. 

 

   

24   

Directive No. 5 in Order C‐1‐08 for Dockside Green Energy (DGE) approved an ROE that is 100 basis 

points premium over the benchmark ROE.  CMUS argues “that using the 100 basis points premium 

granted to DGE in 2007 as a point of comparison is not an appropriate measure of the risks 

associated with small utility operations such as NUS” and “that the more appropriate comparison 

for determining the relative risk of the NUS is against the larger established utilities regulated by 

the Commission”.  (Exhibit B‐3‐1, BCUC 1.20.1, 1.20.2) 

 

In addition, CMUS argues that “the agreed ROE (between the utility and SFU Trust) should be given 

considerable weight by the Commission”.  (Exhibit B‐3‐1, BCUC 1.19.1)  BCUC IR No. 2.29.1 notes 

that SFU Trust and the NUS customers are different stakeholders in this project and may not share 

the same interests with respect to the ROE.  When asked to explain to what extent those interests 

may be similar or divergent, CMUS explains that since potential customers of housing units would 

factor the costs for energy in their purchase decision, it ensures the Trust and the customers are 

“aligned in their desire to have affordable energy rates that ensure the long term viability of the 

community and of the utility that provides service to that community”.  Thus, CMUS believes there 

is “a very clear and strong alignment of interests between SFU Trust and the NUS customers.”  

(Exhibit B‐4, BCUC 2.29.1) 

 

4.5  Revenue Requirements 

 CMUS states that the financing cost of the capital investment represents the largest component of 

the Cost of Service.  Operating costs and fuel costs each represent a significant portion as outlined 

in Table 14 (below). 

 

25  

 

   (Source: Exhibit B‐1, p. 27) 

 

CMUS also proposes that the non‐controllable costs be flowed‐through in future rates, which 

include: 

 1. changes in commodity costs including biomass, natural gas and electricity; 

2. changes in operating costs resulting from changes in regulatory and legal requirements; and 

3. any changes in law. 

  (Exhibit B‐1, p. 46)  

4.6  Rate Design 

 

CMUS is proposing a fixed/variable rate structure that recovers 60 percent of forecast revenues 

from strata through a fixed monthly charge per square meter and 40 percent through a volume‐

based rate.  To support its proposed rate structure, CMUS points to both the utility’s cost structure 

and the high level of uncertainty in forecasting energy demand.  (Exhibit B‐1, p. 28) 

 

   

26   

CMUS is requesting “a larger portion on the fixed charge in recognition that the majority of the 

costs associated with providing the energy are fixed costs and to increase the stability of utility 

revenues given the uncertainty of energy use with new developments.”  This is in recognition that 

“a larger portion of the customer charge assigned to the variable portion of the customer rate will 

encourage more energy conservation.”  (Exhibit B‐3, BCUC 1.27.3)  CMUS submits that “forecast 

risks can be partially mitigated through higher fixed charges.”  (Exhibit B‐4, BCUC 2.34.3) 

 

CMUS proposes to bill each strata based on the overall buildable area of the strata’s building(s) and 

the consumption as metered within each building.  CMUS will not be responsible to allocate energy 

costs at the individual suite level within each strata.  (Exhibit B‐1, p. 28) 

 

4.7  Project Risk 

 

CMUS describes the business risks inherent in this project to include: 

 

• Real estate development risk ‐ due to the volatility of supply and demand for residential housing in Greater Vancouver; 

• Developer/customer connection risk ‐ connection by developers is not mandatory and therefore the NUS does not have exclusive rights to the sale of energy within its territory; 

• Small company size risk ‐ due to illiquidity of shares and limited geographic and customer base; 

• System performance risk ‐ related to new technology, weather, forecast error and other variables which are unknown at the time of planning and developing the system; 

• Construction cost risk; 

• Fuel supply and fuel cost risk; 

• Operating cost risk; and 

• Public acceptance risk. 

 

   

27  

 CMUS discusses several mitigating factors for each identified risk and also states that the equity‐to‐

debt ratio along with the proposed ROE discussed in Section 4.4 above are designed to provide the 

utility owner a fair return on investment in consideration of all these risk factors.  (Exhibit B‐1, 

pp. 24, 44‐46) 

 

4.8  Proposed Levelized Rate 

 

CMUS proposes to implement a levelized rate structure in order to reduce the cost to customers in 

the early stages of the project and to fairly distribute the costs to all customers over a 20‐year 

period.  Under these terms, the utility would agree to under‐recover its cost of service during the 

early stages of development, record these amounts in a deferral account, and recover the value of 

the deferral account by the end of the 20‐year period.  (Exhibit B‐1, pp. 27‐28). 

 

Under this proposal, the levelized rate over the entire 20‐year period is estimated to be 

$159.76/MWh (before escalation) in accordance with the Application.  CMUS subsequently 

adjusted this rate to $155.84/MWh (Exhibit B‐4, BCUC 2.35.4) and confirms it is seeking approval 

for this rate.  CMUS expects that the proposed levelized rate would be subject to change as the 

factors impacting the financial assumptions become known.  (Exhibit B‐3‐1, BCUC 1.25.1) 

 

 

   

28   

5.0  KEY ISSUES 

 

5.1  Introduction 

 

Having laid out the project description, the justification and the estimated costs, the financing, the 

risks, the revenue requirements and proposed rate structure for the CMUS UniverCity Project, we 

will now explore the issues related to the Application.  We will start by examining the Project in 

terms of the adequacy of consultation and then address issues related to alignment with the Clean 

Energy Act, Biomass fuel cost and availability, load analysis and energy forecast.  Additionally, our 

examination will include a review of the impact of our decision on potential agreements with BC 

Hydro and SFU Trust and the risk of stranded assets. 

 

Finally, the Commission Panel will discuss whether the project description and project cost 

estimates are sufficiently robust to justify moving forward with the Project before considering in 

section 6.1 the matter of whether approval is in the public interest.  We believe that the 

examination of these issues will support the Panel’s position that in spite of being positively 

disposed to the Application, there is insufficient evidence on the record to support approval for the 

Project in its entirety at this time. 

 

5.2  Adequacy of Public Consultation 

 

CMUS states that its public consultation process was designed to ensure interested individuals 

from the surrounding communities were notified and provided the opportunity to provide input 

into the decisions of the NUS as the Project has developed.  (Exhibit B‐4, BCUC 2.1.1)  CMUS reports 

that two open house sessions were held over the period of December 2008 to March 2009 and 

advertised in local newspapers with invitations for the first event sent to residents and businesses 

within a four kilometre radius.  The first of these had 16 attendees, almost all of whom were 

current UniverCity residents, and was designed to provide the public with an overview of the 

project and information about the NUS and its benefits.  The second, with 9 attendees (again 

primarily UniverCity residents), was focused on results of a screening analysis of a number of 

29  

 thermal energy technology concepts and a variety of energy sources which included Biomass.  A 

third Open House was planned during the CPCN Application process to present information related 

to the next steps of the NUS development and future oversight of its operation by the Commission.  

To date this has not taken place.  (Exhibit B‐1, pp. 34‐35) 

 

CMUS reports that the feedback from members of the community attending the open houses was 

very positive and individuals were strongly interested and expressed support for a DES with 

renewable technology.  It further reports that there were no concerns raised with respect to the 

technologies being considered or the proximity of the central energy plant to the residential 

community.  The only concern which arose related to the number of trucks which may be required 

to move the Biomass to the CEP.  CMUS notes these concerns were reduced when CMUS and SFU 

Community Trust, in presenting results of a preliminary fuel analysis, identified that two trucks a 

day would be sufficient to supply fuel to run the facility.  (Exhibit B‐4, BCUC 2.1.3) 

 

Commission Determination 

 

The Commission Panel finds that CMUS has taken steps to ensure that the public was adequately 

consulted with regard to the Project.  However, in spite of the steps taken, the open houses were 

sparsely attended and that attendance was primarily limited to an audience of existing Phase 1 and 

2 UniverCity development residents.  As a result, the consultation efforts can best be described as 

narrow in scope as there was little participation from the surrounding community.  Nonetheless, 

the Panel acknowledges that CMUS has made reasonable attempts to notify the public of planned 

open houses.  Accordingly, the Commission Panel has determined that the public consultation 

undertaken by CMUS to date has been satisfactory.  Further, the Panel directs CMUS to schedule 

the planned third open house once it has determined more clearly the form and technology to be 

employed by the NUS. 

 

   

30   

5.3  Alignment with Clean Energy Act and Provincial Government Policy 

 

Section 46(3.1) of the UCA requires the Commission in deciding to issue a CPCN to consider and be 

guided by British Columbia energy objectives, the most recent long‐term resource plan filed by the 

utility under section 44.1 of the Act and the extent to which application is consistent with 

requirements under sections 6 and 19 of the CEA.  A discussion of each of these follows. 

 

5.3.1  Alignment with British Columbia’s Energy Objectives 

 

Section 2 of the CEA sets out British Columbia’s energy objectives (listed in Appendix B).  Those 

most relevant to this proceeding include (d), (g), (h), (i) and (j). 

 

CMUS notes that the NUS project is in alignment with many of these objectives and within the 

Application presents details of the GHG reductions which will result once the Biomass plant is 

implemented.  (Exhibit B‐1, p. 52) 

 

The Commission Panel is in agreement with CMUS and notes that the project is in alignment with 

many of the most relevant objectives listed above.  First, the type of technology being proposed by 

CMUS for this project is very innovative and is designed to support energy conservation and 

efficiency through the use of clean, renewable resources.  As a consequence, the NUS, when fully 

operational will contribute to reaching BC GHG emission targets.  Moreover, by relying on biomass 

for fuel the project clearly aligns with objectives (h), (i) and (j) by reducing waste and promoting the 

switch from natural gas heating to one with decreased GHG emissions on a community wide basis. 

 

5.3.2  Approved Integrated Resource Plan 

 

CMUS has not yet filed a long‐term resource plan. 

 

31  

 5.3.3  Requirements under Sections 6 and 19 of the Clean Energy Act 

 

Section 6 of the CEA applies to electric utilities only and is not relevant to this Application.  

Section 19 of the CEA applies to BC Hydro and prescribed utilities.  CMUS is not one of the 

prescribed utilities. 

 

Commission Determination 

 

The Commission Panel finds that the Application is generally consistent with British Columbia’s 

energy objectives as outlined in the CEA.  The project provides for an interim natural gas based 

solution for the development followed by an environmentally friendly Biomass (or similar green 

heating alternative) once the development is sufficiently large enough to justify it.  Once in place, 

the permanent heating plant will result in significant reduction of GHGs and will contribute to the 

attainment of BC greenhouse gas emission reduction targets. 

 

However, the Panel would like to point out in making this finding that this alignment is contingent 

upon the fuel being Biomass and CMUS being able to source Biomass fuel that produces 

significantly less GHG than natural gas.  As outlined in the BC Energy Plan (p. 25), the amount of 

GHG produced from Biomass is very much dependent upon the source of fuel. 

 

5.4  Availability and Costs of Biomass 

 

Both the cost of Biomass fuel and its availability are important considerations in this Application.  

As noted in Section 4.5 of this Decision, fuel costs largely made up of Biomass represent a 

significant part of the overall cost of service for the permanent CEP.  The Commission Panel has 

concerns as to whether CMUS has performed sufficient due diligence at this point to ensure 

availability and support the cost projections for Biomass fuel. 

 

   

32   

The position taken by CMUS with respect to the cost and supply of suitable Biomass fuel relies very 

strongly upon preliminary discussions the Company has had with potential fuel suppliers rather 

than a comprehensive review of potential sources and expected costs both current and future.  It is 

the intention of the Company to perform a wood waste supply study later in 2011 and keep current 

on any changes thereafter.  In the interests of creating a higher level of certainty with this 

Application, the Panel observes that there would have been a significant benefit in performing the 

supply study and completing supply contract negotiations prior to this submission of this CPCN.  

This would allow the Applicant to firmly substantiate both supply and price for this key 

requirement.  However, given the time span before construction and the fact that no firm decision 

has been made on a Biomass solution for the permanent CEP (to be discussed further in 

Section 5.8), the lack of firm details is understandable.  Nonetheless, we remain concerned with the 

lack of certainty on this important element of the project and are reluctant to rely on what have 

been described as preliminary discussions. 

 

The Commission Panel is also concerned that given the time span between this CPCN and the 

timing of construction of the permanent CEP, the potential for variability with respect to both 

availability and the resultant price to be paid for suitable Biomass could be significant.  CMUS 

reports that a similar circumstance occurred with another Corix project, Dockside Green in the 

Victoria area.  In this instance the economic downturn resulted in the project construction slowing, 

reduced loads relative to forecast and a shortage of suitable wood waste.  Consequently, the 

project is still running on natural gas as it is not yet practical to run a central Biomass facility.  

(Exhibit B‐3, BCUC 1.40.1, 1.40.2)  The Panel notes that because of the long delay between the 

Application and construction it is questionable whether such unforeseen circumstances would not 

affect the current project. 

 

Commission Determination 

 

The Commission Panel finds that there has been inadequate rigor applied to date to investigate 

and secure sourcing and pricing for suitable fuel for the proposed Biomass permanent CEP.  We 

understand the circumstances behind CMUS not moving forward at this early date with more firm 

33  

 details.  However, because of their importance to future ratepayer costs and choice of alternative 

energy system, the Commission Panel remains concerned that this adds to the uncertainty related 

to this Application. 

 

5.5  Load Analysis and Energy Forecast 

 

The Panel is concerned that too much remains unknown to accurately estimate customer 

requirements and demand for NUS based energy.  We further note that CMUS acknowledges that 

the demand forecast is subject to a high level of uncertainty and that the volume based revenue 

may not fully offset the cost of the service and it could experience a revenue shortfall.  (Exhibit B‐1, 

p. 28) 

 

One unknown factor is the number of units that will be connected to the NUS, which CMUS has 

estimated based on the development schedule for Phase 3 and 4.  While presales of the first two 

buildings, as reported by CMUS, indicate that initial take‐up is good, there remains uncertainty 

about units that are scheduled for construction in the future.  CMUS notes that this development 

risk affects the utility’s ability to predict energy use from those buildings that attach to the NUS.  

(Exhibit B‐4, BCUC 2.31.2, 2.31.4) 

 

In IR 2.31.4, CMUS acknowledges that the development risk is significant in these types of 

developments and cites the example of Dockside Green, where development has stalled and the 

expected build‐out may take twice as long as initially predicted.  However, the Company states that 

this risk can be mitigated in part by its phased approach to development.  The Panel concurs that 

some of the development risk may be mitigated by a phased approach to the development of the 

CEP. 

 

As a further unknown factor, the Panel notes that developers may be incented to provide new and 

novel alternative heating technologies and energy efficiencies due to the requirement to meet 

energy efficiency targets provided by SFU Trust and to enhance the saleability of their units.  This 

could have the effect of reducing demand for energy from the NUS even further.  Adding to this 

34   

risk, the implementation of any supplementary energy sources at the building level is at the sole 

discretion of the developer.  Accordingly, there is a high level of uncertainty whether this energy 

can be included in the overall NUS system design because the NUS must be designed and built 

before CMUS could complete any negotiations with developers.  However, CMUS takes the position 

that solar thermal would be able to supply less than 10 percent of non‐peaking load.  (Exhibit B‐3, 

BCUC 1.29.1)  We recognize that it is difficult to predict how much, if any, of these enhancements 

will be implemented by the developers.  However, the demand forecast provided by the CMUS, to 

the extent that they do not include any contingency of this nature at all, may be overly optimistic. 

 

Commission Determination 

 

The Commission Panel finds that the energy forecast submitted by CMUS is not sufficiently 

credible at this stage to base firm decisions as to the size requirements for the permanent CEP or 

the customer rates which result. 

 

While CMUS has identified and described sources of uncertainty with respect to load and energy 

forecasts, we find that it has not provided sufficient analysis of the impact of those uncertainties on 

rates.  The Panel notes that if these uncertainties materialize, they may drive down demand for 

energy from the NUS, and consequently there is potential for higher rates than those predicted by 

CMUS. 

 

5.6  Consideration of Agreements with SFU Trust and BC Hydro 

 

The importance of financial incentives and related agreements has been raised by CMUS within the 

Application.  CMUS has stated that anything short of a full approval of permanent CEP in the CPCN 

“could impair or frustrate the development of the project, particularly if this limited approval 

resulted in the withdrawal of funding.”  (Exhibit B‐4, BCUC 2.12.1.1) 

 

CMUS states that the Biomass plant is the core of this project and the planning, design, funding and 

public consultation are based on it.  CMUS notes that under the terms of the Infrastructure 

35  

 Agreement in place with SFU Trust, developers are required to contribute $1.00 per square foot of 

buildable area to the NUS on each development parcel.  This, as outlined in Table 8, will offset 

$2.223 million in development capital costs.  (Exhibit B‐1, p. 21)  The Commission Panel 

acknowledges that the project is based on the development of an alternative energy plant but 

notes that CMUS, in answer to BCUC IR 2.12.1.2, confirms that the connection fees would not be 

affected by the natural gas temporary solution as they are paid when the lease closes.  Moreover, 

the Commission Panel in reviewing the Infrastructure Agreement (submitted confidentially in 

Exhibit B‐1, Appendix A) sees nothing which would put this agreement at risk if only the temporary 

CEP were approved at this time.  Because of this, the Commission Panel is not persuaded that a 

granting of a CPCN at this time is a requirement of the agreement with SFU Trust or will affect 

funding. 

 

With respect to BC Hydro’s interest in the project, CMUS reports that the agreement in place is not 

subject to BCUC’s approval of the entire project.  However, as noted earlier, the Company believes 

that BC Hydro would not start to negotiate an incentive agreement if only a temporary solution 

was approved.  As outlined in Section 4.2, the incentive agreement with BC Hydro would only be 

payable upon the implementation of an alternative energy system which is not scheduled until 

2016.  As the Commission Panel understands it, the Parties are currently in the process of 

developing an incentive program which may be completed prior to the timing of this Decision.  

CMUS has presented no evidence to suggest that an immediate granting of a CPCN for the 

permanent CEP will be a term of the agreement.  Therefore, the Panel is not persuaded that the 

granting of a temporary CEP only will nullify or even put at risk any incentive agreement which may 

be in place with BC Hydro. 

 

5.7  Risk of Stranded Assets 

 

The fact that the Application proposes to build a temporary CEP which will be replaced by a 

permanent CEP raises a concern with respect to stranded assets.  CMUS states that the temporary 

CEP will have up to three gas fired boilers which it anticipates moving to the permanent CEP once it 

is completed and use for peaking and backup.  CMUS further states that a portion of the temporary 

36   

plant cost will be stranded but this will be offset by the savings which will be realized by deferring 

the completion of the permanent plant before there is sufficient load build‐up.  (Exhibit B‐1, pp. 37‐

38) 

 

The potential for stranded assets was explored by the Commission in IR 1.36.1 which inquired as to 

the anticipated value of the stranded capital related to the temporary plant and details in table 

form outlining the breakout of facility assets, expected recovered costs and the remaining stranded 

value.  CMUS did not provide a response to this query.  This was again addressed in BCUC IR 2.19.3 

which again asked for similar information.  In its response CMUS indicates that “all costs associated 

with the equipment ($104,000) will be used in the permanent plant.”  It is understood that this 

represents boilers and speed pumps.  CMUS further notes that all other costs such as engineering, 

electrical and mechanical installation would be stranded costs.  CMUS did not provide details as to 

the residual value of the assets, nor any expected recovery costs in table form as requested.  

Further to this the Commission in IR 2.19.4 inquired as to whether CMUS had considered selling 

some of the stranded assets as a means of reducing the burden on the ratepayer.  CMUS 

responded by stating that it estimates that 40 percent of the $309,000 estimated cost of the 

temporary plant related to boilers, controls, metering equipment as well as the container housing 

the plant would have salvage value but did not indicate what that value would be.  CMUS 

continued by stating that the boilers could be used as back‐up capacity for the permanent CEP. 

 

Commission Determination 

 

The fact that CMUS has not provided complete information with respect to BCUC IRs indicates to 

the Commission Panel that the Company has made no firm decision as to the disposition of assets 

related to the temporary CEP at this time.  It appears, based on the information provided, that the 

use of the boilers as backup in the permanent CEP is a possibility but not a certainty.  This lack of 

certainty is underlined in the CMUS answer to BCUC IR 2.19.4 which states that it had considered 

the possibility of selling assets but “[t}he boilers may also be used as back‐up capacity in the 

permanent biomass plant” (emphasis added). 

 

37  

 The Commission Panel notes that the cost of the temporary CEP as outlined in Table 24 of the 

Application is $637,000.  Based on the information provided, the Commission Panel is unclear as to 

how much of this amount will result in stranded assets once a permanent CEP is constructed and 

what impact this may have on future rates.  It is this lack of certainty and lack of specific detail 

which cannot be reconciled that raises concerns with the Panel.  Accordingly, the Commission 

Panel finds that at this point the amount of rigor CMUS has put into analysis of the potential for 

stranded assets related to the temporary CEP has been inadequate. 

 

5.8  Adequacy of Project Description 

 

A key element in a review of a CPCN application is the level of detail provided by the applicant and 

the level of certainty which can be ascribed to the project components.  The Commission Panel has 

concerns as to whether this requirement has been adequately satisfied with this Application. 

 

As outlined in Section 3.0, the CMUS Application contemplates what is described as a phased in 

approach to the DES proposed for the UniverCity Project.  This involves the construction of a 

temporary CEP to serve the initial load and a permanent CEP projected to be constructed by 2016 

once the customer load has reached sufficient volume.  While CMUS has been very specific with 

respect to how it will build a temporary CEP, the same cannot be said for the permanent CEP 

proposed to be constructed in the future.  CMUS has repeatedly declined to commit to a firm 

solution for this installation throughout the evidentiary record.  The position taken by the Company 

is that a firm decision is not required until a date closer to actual construction.  However, from the 

evidence presented it is clear that a number of different options have and are still being 

considered. 

 

CMUS, in its Application, notes that both Biomass and the potential for Data Centre Heat Pumps 

were considered for further evaluation.  However, because of uncertainty with whether the Data 

Centre would proceed, only the Biomass solution was recommended for detailed technical and cost 

analysis.  In spite of this, CMUS states that because of the phased approach to the NUS and the fact 

that the alternate technology comes later there would be an opportunity to re‐evaluate the 

38   

potential of using waste heat recovery from the Data Centre if it were constructed prior to 

implementation of this alternative energy permanent solution.  (Exhibit B‐1, pp. 19‐20)  In response 

to BCUC 1.7.1 the Company reports it continues to work closely with SFU and holds this open as a 

possible option if and when a decision is made regarding the Data Centre.  Further, in response to 

BCUC 1.7.3, CMUS asserts that if it is developed and proves viable it “would implement this 

solution and adjust customer rates accordingly.”  Additionally, CMUS has been clear that it does 

not intend to file a new CPCN in the event the Data Centre were to go forward but would file 

“updates  to the CPCN at the points in time where decisions are required on selecting one or more 

of the alternative energy systems to develop”.  (Exhibit B‐2, FortisBC 1.1.1) 

 

In addition to the Data Centre option CMUS has also outlined the potential for a Combined Solution 

involving Corix, SFU and SFU Trust which would provide thermal energy to both UniverCity 

residents and the SFU campus utilizing a larger Biomass based solution.  There has been no firm 

resolution on this proposal but Corix and SFU Campus have applied for funding for this solution to 

various agencies and the applications are currently under review.  If this combined CEP were to 

move ahead, CMUS reports there would be less capital deployed than if two separate solutions 

were pursued and it would result in higher energy efficiency and cost savings due to operations and 

fuel supply logistical synergies.  When asked in BCUC 1.11.1 why it did not wait and submit a CPCN 

for the more desirable Combined Solution, CMUS responded that a ruling by the Commission was 

required to begin construction of the temporary CEP and a final decision on the combined solution 

would not likely be made prior to the required start date.  (Exhibit B‐1, pp. 21, 33) 

 

CMUS states that a decision on the final Biomass technology will come from an evaluation of the 

options available at the time the plant is being developed and notes that the permanent energy 

centre concept is flexible as it allows other types of supply models (e.g. waste‐heat recovery, fuel 

cells heat pumps etc.) to be easily implemented if they become feasible in the future (Exhibit B‐1, 

pp. 37‐38).  Further, when questioned as to whether the Biomass plant decision is firm, CMUS 

states that at this time no decision has been made to even proceed with a Biomass plant solution 

(Exhibit B‐3, BCUC 1.36.2).  In support of this, CMUS argues that ratepayers will benefit from not  

   

39  

 locking in on a permanent Biomass solution at this time as it leaves the Company the potential to 

adopt an optimal solution closer to the time of implementation (CMUS Final Submission, p. 7). 

 

Given the statements CMUS has made regarding the development of a permanent CEP it is clear 

there is a great deal of uncertainty surrounding the future energy source technology, the timing of 

such a facility, its related costs and impact on ratepayers.  As a result, it is difficult to determine 

with any confidence the permanent solution the Commission is being asked to approve.  In this 

vein, FortisBC Energy questioned CMUS with respect to whether projects that “evolve over time” fit 

into the existing CPCN Guidelines.  CMUS in response acknowledged that such projects may not be 

well served by the CPCN process as the CPCN Guidelines are designed to review discrete projects 

which are well defined in terms of costs and timelines (Exhibit B‐2, FortisBC 1.1.2). 

 

Commission Determination 

 

The Commission Panel is satisfied that the temporary CEP, the ETS and distribution piping as 

outlined in the Application have been laid out in sufficient detail to meet CPCN Guidelines.  This 

temporary solution, which will serve the NUS until 2016, relies on proven technology which will be 

installed over a reasonably tight timeframe thereby reducing the potential for unforeseen costs or 

technical challenges.  In addition, because the three boilers and related equipment proposed will 

be installed in phases, the risk associated with overbuilding if sales of the housing project fail to live 

up to expectations is minimized. 

 

However, the Panel is not persuaded that the detail in support of the permanent CEP has been 

sufficient to satisfy CPCN Guidelines or provide sufficient clarity as to what is being approved.  Of 

greatest concern is the fact that CMUS has yet to make a firm commitment to the technology it will 

employ or the shape or form of the final solution for the CEP.  Within the evidentiary record the 

Company has outlined several potential solutions in addition to the proposed Biomass solution.  

One of these involved a new Data Centre at SFU while the other was a joint solution with SFU and 

SFU Trust for a larger Biomass plant which would serve the needs of both the SFU campus and 

phases 3 and 4 of the UniverCity development.  Neither of these is far enough along to determine 

40   

with any degree of certainty that either will proceed.  However, neither can be realistically 

discounted because much might occur in the five year period before a permanent solution is 

required. 

 

CMUS has provided some detail with regard to a potential Biomass based solution but 

acknowledges that in addition to there being no certainty that the eventual solution employed will 

be Biomass, the actual technology for a Biomass solution if employed is also unknown.  Given the 

length of time before construction of a permanent CEP, the Commission Panel understands that 

prudence would dictate holding back on a decision until such time as the uncertainties are cleared 

up and the time to completion is such that analysis and recommendations are based on up to date 

technology and the most recent information.  However, this does not mean that that approval 

should be granted for this CPCN in the absence of a persuasive case and related description which 

can be relied upon.  While the Commission Panel is favourably disposed to the direction that CMUS 

is moving with this Application, the lack of firm details is very concerning.  Accordingly, the Panel 

finds that the level of firm detail and conciseness of the project description for the permanent 

CEP at this time is inadequate and fails to meet the CPCN requirements. 

 

5.9  Adequacy of Project Cost Estimates 

 

The Commission Panel has concern with respect to the adequacy of project cost estimates.  CMUS 

states that the total capital costs for both the temporary and permanent plant infrastructure to be 

$12.215 million over the build‐out period of 2011 to 2019.  As previously stated in Section 4.1 of 

this Decision, CMUS has confidence that the total capital cost, 9 times out of 10, will be within the 

estimated cost. 

 

CMUS included a 15 percent contingency for the permanent CEP due to the higher uncertainty with 

the cost of the biomass technology that would be ultimately selected as well as to account for any 

unknown temporary and permanent site conditions and site preparation requirements.  

(Exhibit B‐3, BCUC 1.45.2)  The overall contingency of 10 percent was used for DPS and ETS.  This 

was assumed at the time of the cost analysis process to be a prudent allowance for any potential 

41  

 material and construction costs as well as changes in design.  (Exhibit B‐3, BCUC 1.45.1)  

Additionally, a capital cost escalation of 2 percent per year is assumed throughout the build‐out 

period.  (Exhibit B‐1, p. 50) 

 

CMUS applied an optimization/reduction to the capital costs estimates to reflect current 

construction market conditions as compared to the market conditions in previous years during the 

“hot” construction market when demand and the prices were significantly higher.  (Exhibit B‐3, 

BCUC 1.44.1) 

 

Commission Determination 

 

The Commission Panel accepts CMUS’ estimate of a P90 probability confidence level and a Class 3 

level of accuracy as adequate in relation to the temporary energy center, given that the timing 

for construction is within the next 2 years.  The use of a 2 percent escalation rate and 10 percent 

contingency during the build‐out period is also acceptable.  However, the Panel does not accept 

that the same level of cost accuracy may be achieved for the permanent CEP since the technology 

and timing of this portion of the project cannot be finalized at this time. 

 

While the Commission Panel generally accepts CMUS’ reasoning that a reduction in capital costs 

from previous studies may be appropriate in the near future, there is no reassurance that this will 

continue into the long term.  Furthermore, if the permanent CEP is not constructed in the forecast 

project timeframe, there could be less certainty with forecasted construction costs due to 

prevailing market conditions at that time and the future costs of the alternative technology that 

will be selected. 

 

   

42   

6.0  COMMISSION DECISION AND DETERMINATIONS 

 

6.1  Commission Decision 

 

The Commission Panel has determined that pursuant to Section 46(3) of the UCA there is 

sufficient evidence to support partial acceptance of this CPCN Application.  Therefore, the Panel 

grants a CPCN for the natural gas fuelled temporary CEP and related Thermal Distribution System 

and Energy Transfer Stations to meet expected demand to 2016 as outlined in the Application.  

The Commission Panel does not approve construction of the permanent CEP at this time and 

suspends further consideration of this matter until CMUS is able to adequately meet the 

requirements outlined in this Decision. 

 

The Commission Panel finds that an evaluation and decision on this CPCN rests on determining 

whether the proposed project is required for the public convenience and necessity and properly 

conserves the public interest.  As outlined in Section 2.2, a public interest review must consider 

three different group perspectives.  These include the surrounding community, the general public 

and future Phase 3 and 4 ratepayers.  Issues related to the surrounding communities have been 

dealt with in the discussion of adequacy of consultation (Section 5.2).  In addition, the interests of 

the general public are captured by the Panel’s acknowledgement that the project is in alignment 

with the Clean Energy Act and Provincial Government Policy (Section 4.2). 

 

CMUS points out that the Commission is guided by the “green energy objectives” in the 2007 

BC Energy Plan and the Clean Energy Act and the NUS as an alternative energy district energy 

system aligns well with these objectives and serves the public interest as identified in both.  In 

summation CMUS states that the “Commission should take into account the important public 

interest that the NUS serves and exercise its discretion to adapt the regulatory approvals to reflect 

the special circumstances of this project”.  (CMUS Final Argument, p. 4) 

 

   

43  

 As noted previously, CMUS states the objective of the Trust is to provide thermal energy cost 

competitively and enhance the environmental performance of the community.  This would align 

with SFU’s commitment to becoming a carbon neutral institution as required by Bill 44 (Exhibit B‐1, 

p. 14).  Further, the Company states that SFU Trust has a stewardship role with respect to the lands 

being developed and has a long term commitment to the well‐being of the community.  

Accordingly, it argues that SFU Trust has a public interest mandate and a desire to both engage and 

understand local community interest and the general public throughout the project’s life.  In 

consideration of this, CMUS further argues that the Commission should give considerable weight to 

the support of the project from SFU and SFU Trust as well as what it describes as overwhelmingly 

positive feedback the project has received.  (CMUS Final Argument, pp. 4‐5) 

 

The Commission Panel does not take issue with many of the submissions of CMUS with respect to 

consideration of the public interest.  The Panel has previously acknowledged in Section 5.3 that the 

proposed NUS aligns well with both the British Columbia Energy Objectives and the Clean Energy 

Act.  While the Panel, given its comments in section 5.2, stops short of describing the public 

reaction to the project as “overwhelming positive feedback,” it is acknowledged that the project is 

unique and that the SFU Trust has a stewardship role with respect to the development and is 

committed to the well‐being of the community. 

 

The concern of the Panel is the lack of certainty with respect to the permanent CEP.  This is further 

exacerbated by the timing of the development of a permanent CEP which is not scheduled to be 

completed until 2016.  As is outlined in Section 5.4, 5.8 and 5.9 there are significant concerns with 

cost and availability of Biomass, the lack of an adequate project description made worse by the lack 

of a firm decision as to what form the permanent CEP will take and what it will cost to both 

construct and operate.  Moreover, as CMUS concedes in its Application “ [a]s the demand forecast 

is subject to a high level of uncertainty, actual operating experience will be required before the 

energy demand can be accurately forecasted”.  (Exhibit B‐1, p. 28)  This statement combined with 

the information in Section 5.5 raises considerable concern with respect to the credibility of the load 

forecast.  Collectively, these uncertainties with respect to the project serve to further support the 

view that the financial impact of the NUS on future ratepayers is anything but clear.  Given the 

44   

CMUS position that cost overruns which are prudently incurred should be recoverable from the 

ratepayer in response to BCUC IR 2.32.2, the Panel believes that greater certainty with respect to 

these costs prior to approval of the complete CPCN is in the public interest. 

 

The Commission Panel accepts there is a necessity for a temporary solution to serve the buildings 

going into service in the fall of 2011.  While having some reservations with respect to the potential 

for stranded assets, we are satisfied that there has been sufficient rigor in preparing the proposal 

for the temporary CEP.  Accordingly, the Panel believes the temporary CEP to be in the public 

interest and approves construction along with the related distribution DPS and ETS. 

 

The Commission Panel in reaching its decision would like to be clear that it is not rejecting the idea 

of the proposal for a Biomass based DES to provide thermal energy service to the UniverCity 

development but are rejecting the lack of certainty and detail related to it.  On the contrary, the 

Panel is supportive of the concept.  However, we believe that it is simply too premature to give 

approval to a largely undefined permanent solution which is not due to start until at least four 

years from now. 

 

6.2  Further Determinations 

 

In light of the Commission Determination approving only the temporary CEP and related 

Distribution System and Energy Transfer Stations in this Application, the Panel makes further 

determinations relating to the financial considerations of Rate Design, Capital Structure, Debt Cost, 

Return on Equity, and Levelized Rates.  CMUS’ positions on these issues were outlined in 

Section 4.0.  Finally, we also address the Terms and Conditions of Service.  These items are 

discussed in detail through the following sections. 

 

   

45  

 6.2.1  Rate Design 

 

The Commission Panel agrees with CMUS’ rationale for designing a rate structure that better match 

revenue streams with cost characteristics.  Therefore, the Commission Panel approves the rate 

design proposed by CMUS, which has a 40 percent variable charge and a 60 percent fixed 

monthly charge as outlined in the Application, but directs CMUS to recalculate the variable and 

fixed components of the rate, using the 20‐year levelized rate as directed in section 6.2.5. 

 

The Commission Panel also notes that the temporary CEP has a maximum capacity of 4.4 MW that 

is less than the 5.7 MW capacity of the permanent CEP.  In fact, the temporary CEP is not meant to 

service the same total square‐meter area and respond to the same energy demand as the 

permanent CEP.  Therefore, for the calculation of the fixed component, the Commission Panel 

further directs CMUS to use the forecast energy demand and total area in square meters that the 

4.4‐MW‐capacity temporary CEP will be able to service. 

 

6.2.2  Capital Structure 

 

The Commission Panel approves CMUS’ proposal to finance 60 percent of the rate base with 

deemed debt and the remaining 40 percent of the rate base with common equity.  The 

Commission Panel makes no determination at this time on the short‐term component of the total 

debt structure; however, the Panel notes that utilities operations usually require short‐term debt 

to fund short term obligations and provide an allowance for working capital requirements.  In BC, 

utilities generally have a short‐term debt portion in their capital structures (e.g., FortisBC Energy 

(formerly Terasen Gas) and FortisBC). 

 

6.2.3  Debt Cost 

 

The Commission Panel accepts the proposal that the interest rate will be based on the 10‐Year 

Government of Canada benchmark bond yield of 3.5 percent at the time of this Application and 

notes that this rate is still reasonable at the time of this Decision. 

46   

However, in light of many factors, we do not accept that a further credit spread of 300 basis points 

is warranted.  First, we note that yield curves normally slope upward and thus the credit yield 

spread for an entity with an AA (low) credit risk (10 year) should be lower than that for an A‐rated 

entity (30 year) because the former has a higher credit rating and shorter maturity than the latter.  

However, the 200 basis point credit spread for SFU is higher than the 153.9 basis point credit 

spread for Ontario’s A‐rated Utility Bond Yield, which is contradictory.  Second, we find that some 

risks, such as those related to technology and fuel costs, are being mitigated since the CPCN is only 

granted for the temporary CEP and related distribution and energy transfer facilities.  This lower 

risk in turn justifies a lower credit spread.  Third, we reiterate that utilities operations usually 

require short‐term debt to fund short term obligations and provide an allowance for working 

capital requirements, which would reduce borrowing costs below the long‐term rate. 

 

The Commission Panel nonetheless recognizes that the NUS will still face some risk related due to 

the small size of the utility.  Thus, we find that a credit spread of 250 basis points above the 

10‐year Government of Canada benchmark bond yield of 3.5 percent is reasonable and approve 

the resultant blended debt rate of 6 percent.  Furthermore, we request that CMUS provide the 

Commission with its recommendations for a robust formula delineating what might be described 

as the “riskless” rate plus a credit spread reflecting actual risk.  This would likely be in conjunction 

with a new CPCN application for the permanent CEP. 

 

6.2.4  Return on Equity 

 

The Commission Panel approves a risk premium of 50 basis points over the benchmark ROE.  The 

Commission will revisit this ROE determination in the event the risk profile of the NUS changes in 

the future. 

 

As outlined in Section 4.4.3, CMUS is requesting a risk premium of 200 basis points above the 

benchmark utility to develop, construct and operate an alternative energy‐based DES for UniverCity 

on Burnaby Mountain.  This level of risk premium was agreed upon with the client, SFU Trust, as a 

part of the overall negotiation package.  While the Commission Panel agrees with CMUS that SFU 

47  

 Trust and the NUS customers may share some common interest with regard to the long‐term 

sustainability of the community, it also notes the conflicting interest between SFU Trust as the 

master developer and the NUS customers.  Therefore, the Panel concludes that the conflicting 

nature of their interests is a more significant factor to consider than their shared interests.  

Accordingly, the Commission Panel rejects CMUS’s argument that the agreed ROE should be given 

considerable weight by the Commission.  Furthermore, the Panel finds that no evidence has been 

provided in this proceeding to justify the requested risk premium of 200 basis points. 

 

With regard to relevant benchmarks, the Commission Panel holds the view ‐ contrary to CMUS 

submissions outlined in Section 4.4.3 ‐ that a comparison between Dockside Green Energy and the 

NUS provides a good basis for assessing the additional risk premium requested by CMUS.  This is 

because both are small utilities with a limited geographic and customer base and subject to similar 

risks in the areas of real estate development, construction costs and company size.  Thus the Panel 

finds that the 100 basis points premium approved by the Commission for DGE offers a good basis 

for comparison.  As explained further below, the Panel further determines that the NUS will be 

subject to lower business risk than DGE. 

 

Specifically, in light of the Commission Panel’s determination to grant a CPCN for the construction 

of the temporary CEP and related Thermal Distribution System and Energy Transfer Stations, the 

Panel finds there should be no additional premium related to the biomass technology and fuel cost 

risks, which CMUS has assessed as “moderate”.  The Panel also notes that CMUS has proposed 

various strategies to mitigate some of the business risks inherent in the project.  For instance, in 

contrast to the DGE Biomass plant that was built at the outset, CMUS opted for a phased approach 

to capital deployment – through a temporary CEP – to mitigate real estate development risks.  

Although CMUS has assessed such development risks as “moderate to high” for both DGE and the 

NUS, the Commission Panel believes that the NUS’s phased approach decreases the risk level for 

this project as compared to DGE. 

 

   

48   

                                                      

Another risk mitigating strategy relates to the “high level of uncertainty” surrounding the demand 

forecast.  Given the Commission Panel’s approval of CMU’s proposed fixed/variable rate design 

that recovers 60 percent of forecast revenues through a fixed monthly charge per sq.mt, in contrast 

to only 50 percent for DGE, the Panel finds that the NUS’s rate design decreases the risk of utility 

revenue shortfalls as compared to DGE. 

 

Furthermore, the Commission Panel understands that the developer/customer connection risk, 

which was initially assessed by CMUS as “significant” and given a “high” risk level in contrast to the 

“low” risk level for DGE, is likely to be significantly reduced in the future.  Indeed, the Panel notes 

the CMUS’s report on the Trust’s intention to “amend future development agreements between 

the SFU Trust and third party developers to include the requirements that buildings developed on 

the lands leased from the SFU Trust and third‐party developers to include the requirements that 

buildings developed on the lands leased from Trust will be required to attach to the NUS.”  

(Exhibit B‐4, BCUC 2.30.0) 

 

While the Commission Panel recognizes that CMUS will still face some risk related to the small size 

of the utility, construction costs and public acceptance, the Panel finds that these risks are 

altogether less significant than those faced by DGE and, therefore, warrant a lower premium than 

the 100 basis points over the benchmark ROE the Commission approved for DGE in 2007. 

 

Finally, the Commission Panel notes that while the benchmark utility was once referred to as the 

“low‐risk” utility, this is no longer the case as determined in the Terasen 2009 ROE Decision, which 

simply refers to Terasen as the benchmark utility.1  In the 2009 Decision the allowed ROE was 

increased, in part to reflect the increased business risk Terasen is facing. 

 

For all the reasons stated, the Commission Panel approves a risk premium of 50 basis points over 

the benchmark ROE. 

 

 1 Terasen Utilities ROE and Capital Structure Decision, December 16, 2009 

49  

 6.2.5  Levelized Rates 

 

In accordance with Section 60 in the UCA, the Commission Panel must ensure that rates being 

charged to customers are just and reasonable while allowing the utility to earn a fair return.  

Commission Panel finds that while it is not uncommon to permit “Greenfield” start‐up utilities to 

charge levelized rates, it is imperative that rates being charged to customers fairly represent the 

type of service being offered, specifically, natural gas service as approved in Section 6.1 above. 

 

The Commission Panel directs CMUS to recalculate a 20‐year levelized rate, based solely on the 

capital costs of the temporary CEP and related distribution system, and adjusted for all the 

financial directives provided in Sections 6.2.2 to 6.2.4 above.  CMUS shall calculate and provide a 

Rate Schedule which incorporates the revised levelized rate to the Commission within 10 

business days of this Decision. 

 

This levelized rate will be charged to all customers initially taking service in the fall of 2011 and 

may be reviewed from time to time by the Commission. 

 

The Panel recognizes that the under a levelized rate approach, there will be over‐earning in the 

latter years that compensate for the under‐earnings in the early years of the project.  Approval for 

the establishment of a revenue deferral account is granted in order to capture the revenue 

requirement variances under the levelized rate approach.  The Commission Panel further directs 

CMUS to file a report showing the calculations and balance of the revenue deferral account by 

December 31 of every year. 

 

6.2.6  Terms and Conditions of Service 

 

The Commission Panel notes that CMUS has failed to provide the Terms and Conditions of Service 

in the original Application and even when requested in the first round of information requests.  

(Exhibit B‐3, BCUC 1.50.1)  CMUS finally produced the document following the second round of 

information requests in Exhibit B‐4, BCUC 2.43.1.  Due to the timing of CMUS’ filing of the Terms 

50   

and Conditions, the public was not granted an opportunity to clarify or challenge the evidence.  The 

Panel believes in the importance of maintaining a transparent process in assessing all information 

presented as evidence in all proceedings.  As a result, the Commission Panel is unable to make a 

determination on the Terms and Conditions of Service at this time.  CMUS is directed to submit a 

schedule of standard fees and charges reflecting the provision of a natural gas service to the 

Commission within 10 business days of this Decision.  This submission, along with the Terms and 

Conditions of Service will be subject to a further review process by the Commission before 

approval is granted. 

 

 

7.0  COMMISSION PANEL COMMENT 

 

The Province of British Columbia issued a news release on April 21, 2011, announcing its intention 

to provide $4.7 million to support the partnership between SFU, SFU Community Trust and CMUS 

for a thermal energy system for the SFU campus and UniverCity.  This announcement was made 

following the close of the evidentiary record.  Accordingly, it was not considered in this Decision.  

The Panel expects this announcement may result in many of the uncertainties related to this 

project to be laid to rest and a firm plan for the future to be developed. 

 

 

   

51  

 8.0  SUMMARY OF DIRECTIVES 

 This Summary is provided for the convenience of readers.  In the event of any difference between the Directions in this Summary and those in the body of the Decision, the wording in the Decision shall prevail.  

  Directive  Page 

1.   The Commission Panel finds that CMUS has taken steps to ensure that the public was adequately consulted with regard to the Project. 

29 

2.   The Commission Panel has determined that the public consultation undertaken by CMUS to date has been satisfactory.  Further, the Panel directs CMUS to schedule the planned third open house once it has determined more clearly the form and technology to be employed by the NUS. 

29 

3.   The Commission Panel finds that the Application is generally consistent with British Columbia’s energy objectives as outlined in the CEA. 

31 

4.   The Commission Panel finds that there has been inadequate rigor applied to date to investigate and secure sourcing and pricing for suitable fuel for the proposed Biomass permanent CEP. 

32 

5.   The Commission Panel finds that the energy forecast submitted by CMUS is not sufficiently credible at this stage to base firm decisions as to the size requirements for the permanent CEP or the customer rates which result. 

34 

6.   The Commission Panel finds that at this point the amount of rigor CMUS has put into analysis of the potential for stranded assets related to the temporary CEP has been inadequate. 

37 

7.   The Panel finds that the level of firm detail and conciseness of the project description for the permanent CEP at this time is inadequate and fails to meet the CPCN requirements. 

40 

8.   The Commission Panel accepts CMUS’ estimate of a P90 probability confidence level and a Class 3 level of accuracy as adequate in relation to the temporary energy center, given that the timing for construction is within the next 2 years.  The use of a 2 percent escalation rate and 10 percent contingency during the build‐out period is also acceptable.  However, the Panel does not accept that the same level of cost accuracy may be achieved for the permanent CEP since the technology and timing of this portion of the project cannot be finalized at this time. 

41 

52   

9.   The Commission Panel has determined that pursuant to Section 46(3) of the UCA there is sufficient evidence to support partial acceptance of this CPCN Application.  Therefore, the Panel grants a CPCN for the natural gas fuelled temporary CEP and related Thermal Distribution System and Energy Transfer Stations to meet expected demand to 2016 as outlined in the Application.  The Commission Panel does not approve construction of the permanent CEP at this time and suspends further consideration of this matter until CMUS is able to adequately meet the requirements outlined in this Decision. 

42 

10.   The Commission Panel approves the rate design proposed by CMUS, which has a 40 percent variable charge and a 60 percent fixed monthly charge as outlined in the Application, but directs CMUS to recalculate the variable and fixed components of the rate, using the 20‐year levelized rate as directed in section 6.2.5. 

45 

11.   For the calculation of the fixed component, the Commission Panel further directs CMUS to use the forecast energy demand and total area in square meters that the 4.4‐MW‐capacity temporary CEP will be able to service. 

45 

12.   The Commission Panel approves CMUS’ proposal to finance 60 percent of the rate base with deemed debt and the remaining 40 percent of the rate base with common equity. 

45 

13.   The Commission Panel accepts the proposal that the interest rate will be based on the 10‐Year Government of Canada benchmark bond yield of 3.5 percent at the time of this Application and notes that this rate is still reasonable at the time of this Decision. 

45 

14.   Thus, we find that a credit spread of 250 basis points above the 10‐year Government of Canada benchmark bond yield of 3.5 percent is reasonable and approve the resultant blended debt rate of 6 percent.  Furthermore, we request that CMUS provide the Commission with its recommendations for a robust formula delineating what might be described as the “riskless” rate plus a credit spread reflecting actual risk. 

46 

15.   the Commission Panel approves a risk premium of 50 basis points over the benchmark ROE. 

46 

16.   The Commission Panel directs CMUS to recalculate a 20‐year levelized rate, based solely on the capital costs of the temporary CEP and related distribution system, and adjusted for all the financial directives provided in Sections 6.2.2 to 6.2.4 above.  CMUS shall calculate and provide a Rate Schedule which incorporates the revised levelized rate to the Commission within 10 business days of this Decision. 

This levelized rate will be charged to all customers initially taking service in the fall of 2011 and may be reviewed from time to time by the Commission. 

47 

53  

 17.   Approval for the establishment of a revenue deferral account is granted in order to 

capture the revenue requirement variances under the levelized rate approach.  The Commission Panel further directs CMUS to file a report showing the calculations and balance of the revenue deferral account by December 31 of every year. 

47 

18.   The Commission Panel is unable to make a determination on the Terms and Conditions of Service at this time.  CMUS is directed to submit a schedule of standard fees and charges reflecting the provision of a natural gas service to the Commission within 10 business days of this Decision.  This submission, along with the Terms and Conditions of Service will be subject to a further review process by the Commission before approval is granted. 

50 

 

   

54   

 DATED at the City of Vancouver, in the Province of British Columbia, this     6th       day of May 2011.       _____Original signed by:_________________ 

  D. A. (DENNIS) COTE   COMMISSIONER       _____Original signed by:_________________ 

  L.A. (LIISA) O’HARA   COMMISSIONER       _____Original signed by:_________________ 

  DAVE MORTON   COMMISSIONER    

                  

SIXTH FLOOR, 900 HOWE STREET, BOX 250 VANCOUVER, BC  V6Z 2N3   CANADA web site: http://www.bcuc.com 

    

   

 BRIT I SH  COLUMBIA  

UTIL IT I ES  COMMISS ION      ORDER    NUMBER   C‐7‐11  

 TELEPHONE:  (604)  660‐4700 BC TOLL FREE:  1‐800‐663‐1385 FACSIMILE:  (604)  660‐1102 

 

. . . /2 

IN THE MATTER OF the Utilities Commission Act, R.S.B.C. 1996, Chapter 473 

 and  

An Application by Corix Multi‐Utility Services Inc. for a Certificate of Public Convenience and Necessity to Construct and Operate a District Energy System for the 

UniverCity Neighbourhood Utility Service Project in Burnaby, BC  

and  

Approval of the proposed Revenue Requirement, Rate Design, Levelized Rates, and Service Agreement   

BEFORE:   D.A. Cote, Panel Chair/Commissioner   L.A. O’Hara, Commissioner  May 6, 2011   D. Morton, Commissioner 

 O  R  D  E  R 

 WHEREAS:  A. On November 26, 2010, Corix Multi‐Utility Services Inc. (CMUS) applied to the British Columbia Utilities Commission 

(Commission) for a Certificate of Public Convenience and Necessity (CPCN) under sections 45 and 46 of the Utilities Commission Act (Act) for the construction and operation of a district energy system (DES) for the UniverCity Neighbourhood Utility Service (NUS) in Burnaby, BC, and for approval under sections 59, 60 and 61 of the Act for the proposed revenue requirement, rate design, Service Agreements, and levelized rates (the Application);   

B. The UniverCity is a sustainable residential community, being developed by Simon Fraser University (SFU) Community Trust, being built adjacent to the main SFU campus.  The development is being constructed in 4 phases.  Phase 1 and 2 have already been constructed and will not be connected to the proposed DES.  The first three buildings of Phase 3 are under development and scheduled for completion in the fall of 2011, which will be served by the proposed NUS. When completed in 2019 the development will total 296,572 square meters; 

 C. CMUS will be responsible for development and ownership of the NUS, a community‐based utility.  The primary 

responsibility will be to develop, implement, operate and maintain the DES, which will provide thermal energy to residents of Phase 3 and 4 of the UniverCity developments; 

 D. CMUS proposes that the DES will be initially served by a temporary Central Energy Plant (CEP) using natural gas boilers 

and a distribution system which is expected to serve the needs of the NUS until 2016.  A transition to a permanent CEP using an alternative energy fuel source (such as biomass) will replace the temporary Central Energy Plant as the primary source of thermal energy when sufficient load requirements are reached; 

 

         

2   

 

ORDERS/C‐7‐11_Corix University NUS CPCN Decision 

 BRIT I SH  COLUMBIA  

UTIL IT I ES  COMMISS ION      ORDER    NUMBER   C‐7‐11  

E. By Order G‐193‐10, dated December 10, 2010, the Commission established a written public hearing process and regulatory timetable to review this Application; 

 F. The Commission has reviewed the Application and has determined that it is in the public interest to grant a partial 

approval of this CPCN Application.   NOW THEREFORE the Commission orders as follows:  1. Approval for Corix Multi‐Utility Services to construct and operate a natural gas fuelled temporary Central Energy Plant 

and related Thermal Distribution System and Energy Transfer Stations as outlined in the Application.   

2. Further consideration of the permanent Central Energy Plant is suspended until CMUS is able to meet the requirements outlined in the Decision. 

 3. The approved temporary Central Energy Plant will operate on the basis of the following terms:  

a. A ROE which is 50 basis points over the benchmark ROE; 

b. A rate base with 60 percent deemed debt and the remaining 40 percent with common equity; 

c. A rate design with a 60 percent fixed monthly charge and a 40 percent variable charge which are to be recalculated using a 20‐year levelized rate, based solely on the capital cost of the temporary Central Energy Plant plus the related distribution system. This is to be adjusted for all financial directives provided in Sections 6.2.2 to 6.2.4 of the Decision. 

d. A blended debt rate of 6.0 percent based on the 10‐year Government of Canada benchmark bond yield of 3.5 percent and a credit spread of 250 basis points. 

e. The establishment of a revenue deferral account to capture the revenue requirement variances under the levelized rate approach.  

4. Corix Multi‐Utility Services must file a report showing the calculation and balance of the revenue deferral account by December 31 of each year. 

 5. Corix Multi‐Utility Services must submit a schedule of standard fees and charges reflecting the provision of natural gas 

service to the Commission within 10 business days of this Decision.  

 DATED at the City of Vancouver, in the Province of British Columbia, this                   6th               day of May 2011.    BY ORDER    Original signed by:    D.A. Cote   Panel Chair/Commissioner  

APPENDIX A Page 1 of 1 

  

 

 

REGULATORY TIMETABLE 

 

 

ACTION   DATE (2011)

Commission Information Request No. 1   Thursday, January 6 

Intervener Information Request No.1   Thursday, January 13 

Intervener/Interested Party Registration  Thursday, January 13 

Response to Commission and Intervener Information Request No. 1 Thursday, January 27 

Commission and Intervener Information Requests No. 2 Thursday, February 10 

Response to Commission and Intervener Information Requests No. 2 Thursday, February 24 

CMUS Final Submission   Thursday, March 10 

Intervener Final Submission   Thursday, March 17 

CMUS Reply Submission   Thursday, March 24  

 

 

This timetable was amended by Order Amended G‐18‐11 dated March 3, 2011 as follows: 

 

ACTION   DATE (2011)

CMUS Final Submission  Friday, March 4, 2011 

Intervener Final Submission  Monday, March 7, 2011 

CMUS Reply Submission  Wednesday, March 9, 2011  

 

 

APPENDIX B Page 1 of 2 

  

CLEAN ENERGY ACT 

 

British Columbia's energy objectives 

2  The following comprise British Columbia's energy objectives: 

(a) to achieve electricity self‐sufficiency; 

(b) to take demand‐side measures and to conserve energy, including the objective of the 

authority reducing its expected increase in demand for electricity by the year 2020 by at 

least 66%; 

(c) to generate at least 93% of the electricity in British Columbia from clean or renewable 

resources and to build the infrastructure necessary to transmit that electricity; 

(d) to use and foster the development in British Columbia of innovative technologies that 

support energy conservation and efficiency and the use of clean or renewable 

resources; 

(e) to ensure the authority's ratepayers receive the benefits of the heritage assets and to 

ensure the benefits of the heritage contract under the BC Hydro Public Power Legacy 

and Heritage Contract Act continue to accrue to the authority's ratepayers; 

(f) to ensure the authority's rates remain among the most competitive of rates charged by 

public utilities in North America; 

(g) to reduce BC greenhouse gas emissions 

(i)  by 2012 and for each subsequent calendar year to at least 6% less than the level 

of those emissions in 2007, 

(ii)  by 2016 and for each subsequent calendar year to at least 18% less than the 

level of those emissions in 2007, 

(iii)  by 2020 and for each subsequent calendar year to at least 33% less than the 

level of those emissions in 2007, 

(iv)  by 2050 and for each subsequent calendar year to at least 80% less than the 

level of those emissions in 2007, and 

(v)  by such other amounts as determined under the Greenhouse Gas Reduction 

Targets Act; 

APPENDIX B Page 2 of 2 

  

(h) to encourage the switching from one kind of energy source or use to another that 

decreases greenhouse gas emissions in British Columbia; 

(i) to encourage communities to reduce greenhouse gas emissions and use energy 

efficiently; 

(j) to reduce waste by encouraging the use of waste heat, biogas and biomass; 

(k) to encourage economic development and the creation and retention of jobs; 

(l) to foster the development of first nation and rural communities through the use and 

development of clean or renewable resources; 

(m) to maximize the value, including the incremental value of the resources being clean or 

renewable resources, of British Columbia's generation and transmission assets for the 

benefit of British Columbia; 

(n) to be a net exporter of electricity from clean or renewable resources with the intention 

of benefiting all British Columbians and reducing greenhouse gas emissions in regions in 

which British Columbia trades electricity while protecting the interests of persons who 

receive or may receive service in British Columbia; 

(o) to achieve British Columbia's energy objectives without the use of nuclear power; 

(p) to ensure the commission, under the Utilities Commission Act, continues to regulate the 

authority with respect to domestic rates but not with respect to expenditures for 

export, except as provided by this Act.  

APPENDIX C Page 1 of 2 

  

IN THE MATTER OF the Utilities Commission Act, R.S.B.C. 1996, Chapter 473 

 and  

Corix Multi Utility Services Inc.  Certificate of Public Convenience and Necessity 

for the Neighbourhood Utility Service at UniverCity, Burnaby 

EXHIBIT LIST 

 Exhibit No.  Description  COMMISSION DOCUMENTS  A‐1  Letter dated December 6, 2010 ‐ Appointment of Panel 

A‐2  Letter and Order G‐193‐10 dated December 10, 2010 ‐ Establishing a Written Hearing Process and Regulatory Timetable 

A‐3  Letter dated January 6, 2011 – Information Request No. 1 to Corix 

A‐4  Letter dated February 10, 2011 – Order G‐18‐11 and Amended Regulatory Timetable 

A‐5  Letter dated February 17, 2011 – Commission Information Request No. 2 

A‐6  Letter dated March 3, 2011 – Amended Regulatory Timetable 

A2‐1  Letter dated February 17, 2011 – Commission Staff filing Ontario Energy Board ‐ Report of the Board on Cost of Capital and 2nd Generation Incentive Regulation for Ontario's Electricity Distributors 

A2‐2  Letter dated February 17, 2011 – Commission Staff filing Ontario Energy Board ‐ Cost of Capital Parameter Updates for 2011 Cost of Service Applications for Rates  

A2‐3  Letter dated February 17, 2011 – Commission Staff filing UniverCity on Burnaby Mountain – UniverCity East Neighbourhood Plan Development Guidelines and Requirements  

A2‐4  Letter dated February 17, 2011 – Commission Staff filing City of Burnaby – Bylaw No. 12760 a BYLAW to amend Bylaw No. 4742, being Burnaby Zoning Bylaw 1965  

  

APPENDIX C Page 2 of 2 

  Exhibit No.  Description  APPLICANT DOCUMENTS CORIX  B‐1  CORIX MULTI‐UTILITY SERVICES INC. (CORIX) ‐ Letter dated November 26, 2010 – Application 

for a Certificate of Public Convenience and Necessity for the Neighbourhood Utility Service at UniverCity, Burnaby  

B‐1‐1  CONFIDENTIAL – Application Appendices A, D, G 

B‐1‐2  Letter Dated December 10, 2010 – Errata No. 1 to page 11 of the application  

B‐2  Letter Dated January 28, 2011 – Corix Response to Terasen IR No. 1 

B‐3  Letter Dated January 28, 2011 – Corix Response to BCUC IR No. 1 

B‐3‐1  Letter Dated February 8, 2011 – Corix Additional Responses to BCUC IR 1 

B‐3‐2  Letter Dated February 10, 2011 – Corix Additional Evidence 

B‐4  Letter Dated February 25, 2011 – Corix Submitting Responses to BCUC IR No. 2 

B‐5  Letter Dated March 1, 2011 – Corix Request for filing extension 

  INTERVENOR DOCUMENTS  C1‐1  TERASEN GAS INC., TERASEN GAS (VANCOUVER ISLAND) AND TERASEN GAS (WHISTLER) 

COLLECTIVELY TERASEN UTILITIES (TUS)   Letter Dated January 5, 2011 ‐ Request for Intervener Status by Dianne Roy  

C1‐2  Letter Dated January 13 2011 – TUS Information Request No. 1 

  

SIXTH FLOOR, 900 HOWE STREET, BOX 250 VANCOUVER, B.C. V6Z 2N3 CANADA

web site: http://www.bcuc.com

TELEPHONE: (604) 660-4700 BC TOLL FREE: 1-800-663-1385

FACSIMILE: (604) 660-1102

BRITISH COLUMBIA

UTILITIES COMMISSION ORDER NUMBER C-1-08

IN THE MATTER OF the Utilities Commission Act, R.S.B.C. 1996, Chapter 473

Application by Dockside Green Energy LLP

for Approval of a Certificate of Public Convenience and Necessity to construct and operate a District Energy System for the Dockside Green Project in Victoria, B.C.

and

Approval of the proposed Revenue Requirement, Rate Design and Levelized Rates

BEFORE: L.F. Kelsey, Panel Chair and Commissioner P.E Vivian, Commissioner April 17, 2008 A.A. Rhodes, Commissioner

O R D E R

WHEREAS: A. By letter dated December 21, 2007, Dockside Green Energy LLP (“DGE”) applied to the Commission for a

Certificate of Public Convenience and Necessity (“CPCN”) to construct and operate a district energy system (“DES”) to provide energy service to the Dockside Green development (“Dockside Green”) currently being built on the Inner Harbour in Victoria, B.C. and for approval of Service Agreements, Terms and Conditions of Service and levelized rates (the “Application”); and

B. Dockside Green is being constructed on fifteen acres of former industrial land adjacent to the Upper

Harbour and downtown Victoria, between the Johnson and Bay Street bridges. The total planned development is approximately 1.4 million square feet of mixed residential, office, retail and industrial space; and

C. Dockside Green is being developed by Dockside Green Limited Partners (“DGLP” or the “developer”),

which is jointly owned by Vancity Capital Corporation (Vancity”) and Windmill West Properties LLP (“Windmill”); and

D. DGE, the proposed utility, was established to serve the Dockside Green community in Victoria harbor and

provide space heating and domestic water service through a DES; and E. DGE is jointly owned by Vancity, Windmill, Corix Utilities Inc. (“Corix”) and Terasen Energy Services

Inc. (“TES”) and has selected Corix and TES to develop the DES; and F. The DES comprises a central heating plant containing a wood-waste gasification system and back-up

natural gas boilers, a distribution system comprised of insulated pipe to deliver energy in the form of heated water to customers, heat exchangers which transfer heat from the distribution system to customer

2

BRITISH COLUMBIA

UTILITIES COMMISSION ORDER NUMBER C-1-08

buildings, and energy meters that measure the energy transferred to customers. DGE will install revenue-grade meters at the building and use these readings to issue bulk energy bills to each strata customer within the development. Each strata will then allocate the total energy costs to residents based on a pro-rata allocation of common and in-suite energy usage; and

G. DGE will be seeking to reduce the cost of serving the Dockside Green customers by serving off-site

properties in close proximity to the Dockside Green development to earn incremental revenues; and H. Dockside Green has secured federal funding to offset some of the capital costs of the DES through the

Technology Early Action Measures (“TEAM”) federal funding program; and I. During the first several years of the build-out period, it is expected that operating cashflows will be less

than the interest and principal payments on the utility’s debt. In these instances, the developer has agreed to provide funding to make up the shortfall by way of non-interest bearing refundable customer contributions. These contributions are repayable to the developer on a straight-line basis over a six year period beginning in year 15 of the project; and

J. Corix has been contracted by DGE to provide operation and maintenance and administration services under

a ten year agreement called the Energy Services Agreement. The Energy Services Agreement requires DGE and Corix to meet annually for the initial three years of the DES operations to review costs and determine operating budgets for the following year. Beginning in year four of the agreement, DGE and Corix will agree upon a fixed price, subject to the Consumers Price Index and changes in regulatory requirements, for the remaining seven years of the agreement; and

K. At the time of the Application there is a 20-year draft supply agreement between DGE and Three Point

Properties to supply wood-waste at a fixed price of $25 per bone dry tonne (“BDT”) for the first ten years and $30 per BDT escalating with inflation of 3 percent for the remaining ten years; and

L. DGE is proposing a 20-year levelized rate mechanism in order to provide a reasonable rate to strata

customers in the early years of the project with a deemed capital structure of 60 percent debt and 40 percent equity and long-term debt financing at 6.5 percent; and

M. The proposed levelized rates are based on an annualized rate of return over the 20 years equal to the low

risk benchmark utility return plus 100 basis points or 9.62 percent. Should it be necessary for rate changes during the initial ten year period due to changes in forecast revenue requirements, a revised schedule of levelized rates will be filed for approval with the Commission that allows DGE the opportunity to earn its target return over the 20-year period taking into account achieved return on equity from start-up to the current year; and

N. DGE proposes the deferral of depreciation of plant assets for the initial seven years of the operation and

depreciation over 50 years starting in the eighth year of operation; and

3

BRITISH COLUMBIA

UTILITIES COMMISSION ORDER NUMBER C-1-08

O. DGE is proposing a fixed/variable rate structure that recovers 50 percent of forecast revenue through a fixed monthly charge per square meter and 50 percent through a volume based rate; and

P. The levelized rate term is for 20 years commencing January 1, 2009, with a rate structure that is based on a

fixed charge of $2.57 per square metre per annum escalated at 3.0 percent per annum and a variable charge of $14.01 per GJ escalated at 3.0 percent per annum. The gas cost recovery charge is based on the actual cost of natural gas and allocated based on square meters to each strata on a pro rata basis; and

Q. Natural gas usage is not expected to be significant except during planned shut down periods and during

peak periods at full build out. DGE is proposing a separate natural gas recovery charge applied to peak usage periods to recover actual gas costs from strata customers; and

R. There are cost risks associated with forecast customer additions and corresponding energy demand as well

as construction costs. The first risk has been mitigated through the proposed rate structures and service agreements whereby DGLP has entered into a contract for the use and payment to DGE whereby DGLP will pay DGE the monthly fees until such time as a unit is sold. DGE will attempt to mitigate construction cost risk with fixed price contracts; and

S. By Order No. G-8-08 dated January 11, 2008, the Commission established a Written Public Hearing and

Regulatory Timetable; and T. By letter dated January 11, 2008, the Commission issued Information Request No.1 to DGE; and U. By letter dated January 21, 2008 DGE filed a response to Information Request No.1; and V. By e-mail dated January 23, 2008 SunGen Sustainable Developments Inc. filed a request for Intervenor

status; and W. By letter dated February 15, 2008, the Commission issued Information Request No. 2 to DGE; and X. By letter dated March 6, 2008 DGE filed a response to Information Request No.2; and Y. By letter dated March 11, 2008 DGE filed its final submission; and Z. By letter dated March 20, 2008 DGE filed responses to outstanding questions from Information Request

No. 1; and AA. By letter dated March 20, 2008 DGE requested Commission approval for Interim Rates pending a final

Decision; and

4

BRITISH COLUMBIA

UTILITIES COMMISSION ORDER NUMBER C-1-08

BB. By letter dated March 28, 2008 the Commission denied DGE’s request for approval of interim rates prior to the issuance of a CPCN to DGE. The Commission stated that it is unlikely to object to DGE charging for such service and views the arrangements for service prior to granting a CPCN as a private matter between the parties; and

CC. The Commission has reviewed the information and finds that the Application is in the public interest

subject to conditions. NOW THEREFORE pursuant to Sections 45, 46, 59, 60 and 61 of the Utilities Commission Act (the “Act”), the Commission orders as follows: 1. The Commission grants a CPCN to DGE for the construction and operation of a DES to provide hydronic

energy service at Dockside Green as set out in the Application, subject to the following conditions: 1.1 Any extraordinary capital expenditures or operating and maintenance expenses, natural gas and/or

any other fuel commodity costs that are incremental to the costs included in the revenue requirements estimate presented in the Application and are required in order that the thermal energy generation system referred to as the Nexterra Plant fulfills the role described for it in the Application and supporting material, will not be included in DGE rate base and revenue requirements and will not be recovered in DGE customer rates.

1.2 Any extraordinary capital expenditures or operating and maintenance expenses, natural gas and/or

any other fuel commodity costs that are incremental to the costs included in the revenue requirements estimate presented in the Application and are required in order to obtain, process, handle or replace the fuel source for the district energy system, including the cost of gas that is used because wood supply is not available or the cost of wood supply to the extent it exceeds the price set out in the Binding Letter of Intent with Three Point Properties LLP that is Attachment 7.1 in Exhibit B-2, will not be included in the DGE rate base and revenue requirements and will not be recovered in DGE customer rates.

1.3 DGE has provided written confirmation to the Commission that it accepts the conditions to the

CPCN, within 60 calendar days of the date of this Order. 2. If any of the conditions in the CPCN for the district energy system are not met, the CPCN is cancelled

immediately. 3. DGE is responsible for obtaining all other necessary licences, permits and agency approvals. 4. DGE will file with the Commission annual reports on the construction of the district energy system that

provide explanations for any material variances from the schedule and cost estimate in the Application.

5

Order/C-1-08_Dockside Green Energy CPCN_Reasons for Decision

BRITISH COLUMBIA

UTILITIES COMMISSION ORDER NUMBER C-1-08

5. Subject to DGE holding a CPCN for the DES, the Commission approves the revenue requirements methodology as set out in the Application and supporting materials, including that the revenue requirements will be calculated using a capital structure that has 40 percent equity, a return on equity (“ROE”) that is 100 basis points higher than the benchmark ROE that the Commission establishes for a low-risk benchmark utility, and DGE’s actual interest rate. This methodology will apply for subsequent years unless and until it is changed by future Commission Order.

6. The Commission approves the rate design proposed by DGE, which has a 50 percent variable component and

a 50 percent monthly charge based on area in square metres, unless and until it is changed by a future Commission Order.

7. Subject to DGE holding a CPCN for the district energy system, the Commission approves the revised

Hydronic Energy Service Terms and Conditions (the “Tariff”) for Dockside Green as set out in Exhibit B-4, Attachment 19.1, subject to DGE filing by June 1, 2008 a Tariff that incorporates the revision to Section 23 that is directed in the Reasons for Decision in Appendix A.

8. DGE will maintain separate accounts for the district energy system at Dockside Green and will file Annual

Reports and financial statements that summarize the results of utility operations within four months of its fiscal year-end, and which address the directions on Annual Reports that are set out in the Reasons for Decision in Appendix A. The Annual Reports will be in a form to be developed in consultation with Commission staff.

9. DGE will provide a copy of this Order and the 24-hour emergency contact number to each current and new

customer, and will maintain a copy of its approved Tariff and current customer rates for inspection by customers on its web site and, in the event it maintains an office in Victoria, at the Victoria office.

10. DGE will submit all service agreements with off-site customers to the Commission in a timely fashion, for

approval as Rate Schedules or Tariff Supplements. 11. DGE will comply with all directions in the Reasons for Decision attached as Appendix A to this Order. DATED at the City of Vancouver, in the Province of British Columbia, this 18th day of April 2008.

BY ORDER Original signed by: L.F. Kelsey Commissioner Attachment

APPENDIX A to Order No. C-1-08

Page 1 of 13

Dockside Green Energy LLP Application for a Certificate of Public Convenience and Necessity

To Construct and Operate the Dockside Green District Energy System

REASONS FOR DECISION

___________________________________________________________________________________________ 1.0 BACKGROUND

1.1 Application

On December 21, 2007 Dockside Green Energy LLP (“DGE”) applied (“the Application”) to the British

Columbia Utilities Commission (“BCUC”, “Commission”) for:

(a) a Certificate of Public Convenience and Necessity (“CPCN”) to construct and operate a district

energy system (“DES”) to provide energy service to the Dockside Green development currently being built on the Inner Harbour in Victoria;

(b) approval of:

• a levelized rate base • forecast revenue requirements, including:

• a deemed capital structure of 40% equity, 60% debt • an allowed return on equity of 9.62% • long term debt financing at 6.5% • forecast operating costs

• accounting treatment of:

• depreciation of plant assets • a 20 year levelized rate structure

• rate design • Service Agreement Terms & Conditions [Tariff]

The Dockside Green development is, if not unique, at least rare in its commitment to environmental and energy

sustainability relative to current standards of development. These characteristics are described in the following

section. The extent to which these factors have a bearing on the Commission’s review of the Application is

described elsewhere in this Decision.

APPENDIX A to Order No. C-1-08

Page 2 of 13

1.2 The Dockside Green Project

Dockside Green is a mixed residential, office, retail and industrial development with a planned total floor space of

129,658 square meters (approximately 1.4 million square feet) on fifteen acres of formerly contaminated

industrial land in Victoria. The project is to be developed in nine phases over seven years and the first phase of

residential condominiums is now complete.

The developer of the project is the Dockside Green Limited Partnership (“Dockside Green LP” or “Developer”),

which is owned by Vancity Capital Corporation (“Vancity”) and Windmill West Properties LLP (“Windmill”).

The Disclosure Statement filed with the Superintendent of Real Estate (“Disclosure Statement”) and with the

Commission in response to Commission Information Request No. 1 (Exhibit B-2) states that the Developer

intends to construct a biomass facility to provide hot water heating to Dockside Green and will establish a private

utility company to operate a wood-waste gasification system (the “Waste Wood Facility”). Further to that

commitment, Dockside Green LP has established DGE as the district energy system utility.

The Dockside Green project will be a sustainable development certified by the Canada Green Building Council’s

Leadership in Energy and Environmental Design (“LEED”TM) green building rating system (Exhibit B-1, p. 30).

LEED certification involves certification and credits in five principal LEED categories: sustainable sites, water

efficiency, energy and atmosphere, materials and resources, and indoor environmental quality. LEED-Platinum is

the highest of the four possible levels of LEED certification (Exhibit B-1, p. 7; Exhibit B-2, p. 1). The

Application states that the Developer’s commitment to the LEED-Platinum certification is reinforced by a

developer covenant with the City of Victoria that requires the Developer to pay the city a penalty for every square

foot of every building that does not achieve the LEED-Platinum rating (Exhibit B-1, p. 30).

Further to the LEED-Platinum certification of the project, DGE will use a wood-waste fired gasification system

provided by Nexterra Energy Corp. (“Nexterra”) capable of delivering 2 MW thermal heat (“MWth”) for

residential/commercial district heating. Nexterra also has plants operating at the University of South Carolina and

the Tolko Industries Ltd. plywood mill near Kamloops (Exhibit B-1, pp. 52-53). The energy derived from the

system is intended to reduce the greenhouse gas emissions that would otherwise be produced from energy use at

the development (Exhibit B-1, p. 7; Exhibit B-2, Attachment 9.3, p. 4). Technology Early Action Measures

(“TEAM”) funding from the federal Department of Natural Resources will provide partially repayable assistance

of $1.5 million. TEAM funding supports projects that are designed to demonstrate technologies that mitigate gas

emissions and sustain economic and social development (Exhibit B-1, pp. 52-53).

APPENDIX A to Order No. C-1-08

Page 3 of 13

Also as part of the project’s LEED-Platinum certification, the Developer intends to construct on-site sewage

treatment systems and will establish a separate private utility company to operate the sewage systems to provide

sewage service to Dockside Green, and to provide irrigation service and water for toilet facilities. DGE states that

Dockside Green, with future growth, will also include sewer waste heat recovery technology to provide energy to

customers through the DES (Exhibit B-2, Attachment 1.1, p. 28).

In addition, the Developer has agreed to implement certain transportation strategies including: a mini-transit

service offering shuttle service from Dockside Green to various downtown Victoria locations; a car-share program

offering residents the use of electric and high fuel-efficiency vehicles to be provided by the developer; and

installation of bicycle racks throughout Dockside Green (Exhibit B-2, Attachment 1.1, p. 28).

The Application states that all of the buildings in the development will be designed to outperform the Model

National Energy Code for Buildings by at least 40 percent which “…will translate into savings for occupants as

well as peak electricity demand reductions that will benefit the Province of BC” (Exhibit B-1, p. 31).

1.3 Dockside Green Energy LLP

DGE is jointly owned by Corix Utilities Inc. (“Corix”), Terasen Energy Services Inc. (“TES”), Vancity and

Windmill. Corix, Windmill, and TES each own a 17 percent interest in DGE and Vancity owns the remaining

49 percent. Corix is experienced in the ownership and operation of utility and district energy systems, and DGE

has contracted with Corix to provide utility operations (Exhibit B-1, pp. 2-8).

In addition to serving the customers within the Dockside Green development, DGE will be seeking to serve

customers in close proximity to, but outside of, the project (“Off-site” customers) in order to earn incremental

revenues and reduce the cost of serving the Dockside Green customers. Although DGE states that it has received

expressions of interest from other nearby developments and is engaged in other nearby prospects, the only Off-

site customer currently forecast to be served by DGE is a Delta Hotel. DGE currently has a Memorandum of

Understanding (“MOU”) with the Delta Hotel and DGE assumes that the Delta Hotel MOU will be converted into

a sales agreement with no material changes (Exhibit B-1, pp. 20-21).

DGE will meter energy use at the building level and will bill each strata as a separate customer. Each strata will

sub-meter energy use for the purpose of allocating energy costs within the strata (Exhibit B-1, p. 8).

APPENDIX A to Order No. C-1-08

Page 4 of 13

1.4 Regulatory Process for Review of the Application

DGE filed its Application on December 21, 2007. By Commission Order No. G-8-08 dated January 11, 2008, the

Commission determined that a written public hearing process was necessary to review the Application and a

public notice and Regulatory Timetable were prepared. On February 28, 2008 DGE’s letter to the Commission

requested that the Regulatory Timetable be revised, and by letter dated February 29, 2008, the Commission

accepted DGE’s proposal.

The Commission issued Information Requests No. 1 and 2 to DGE on January 11, 2008 and February 15, 2008,

respectively and DGE filed its responses on January 21, 2008 and March 6, 2008 respectively. On March 11,

2008 DGE filed some outstanding responses to Information Request No. 1 and its Final Submission.

The only party to intervene in the written hearing process was SunGen Sustainable Developments Inc., which did

not file information requests, evidence or final submissions with respect to the Application.

On March 20, 2008 DGE filed a request for approval to charge the rates proposed in the Application on an interim

basis in order to supply hydronic energy service to the initial strata complex at Dockside Green based on the

applied-for rates and terms and conditions pending a final Commission Decision. The Commission, by letter

dated March 28, 2008, concluded that it would not be appropriate to approve rates for Dockside Green prior to the

issuance of a CPCN to DGE and denied DGE’s request for approval to charge rates on an interim basis. The

Commission noted that the lack of a CPCN and approved rates should not of itself prevent DGE from providing

service to customers at Dockside Green, and the Commission would be unlikely to object to DGE charging for

such service, as it views the arrangements for service prior to granting a CPCN as a private matter between the

parties.

2.0 CERTIFICATE OF PUBLIC CONVENIENCE AND NECESSITY

DGE applied pursuant to Sections 45 and 46 of the Utilities Commission Act (“UCA” or “Act”) for a CPCN to

construct and operate a DES to provide energy service to the Dockside Green development.

Section 45 of the UCA states, in part:

APPENDIX A to Order No. C-1-08

Page 5 of 13

“45 (1) Except as otherwise provided, after September 11, 1980, a person must not begin the construction or operation of a public utility plant or system, or an extension of either, without first obtaining from the commission a certificate that public convenience and necessity require or will require the construction or operation.”

Section 46 of the UCA states, in part:

“(1) An applicant for a certificate of public convenience and necessity must file with the commission information, material, evidence and documents that the commission prescribes.

(2) The commission has a discretion whether or not to hold any hearing on the application.

(3) The commission may issue or refuse to issue the certificate, or may issue a certificate of public convenience and necessity for the construction or operation of a part only of the proposed facility, line, plant, system or extension, or for the partial exercise only of a right or privilege, and may attach to the exercise of the right or privilege granted by the certificate, terms, including conditions about the duration of the right or privilege under this Act as, in its judgment, the public convenience or necessity may require.”

The Commission reviewed the Application through a written hearing process as described above and notes that

there was no opposition to the Application. The Commission understands the nature of both the DES and the

Dockside Green project to be unique in many respects. The thermal energy generation system technology

proposed for the DES will be provided under contract as a “turn key” installation (Exhibit B-1, p. 12). A multi-

year draft contract for the supply of biomass for the DES is in place (Exhibit B-1, p. 39). The Commission

considers the unique nature of the development, the emerging technology of the thermal energy generation system

and the security of supply and quality of biomass to be risks unique to this project and, to properly conserve the

public interest, should be shareholder risks. These issues are addressed elsewhere in this Decision.

Commission Determination

The Commission Panel approves the CPCN Application for the DES as described in the Application

subject to the conditions made elsewhere in this Decision. DGE will provide written confirmation to the

Commission accepting the conditions of the CPCN within 60 calendar days of this Order. Should such

confirmation not be received the CPCN is cancelled immediately.

APPENDIX A to Order No. C-1-08

Page 6 of 13

3.0 RATES

3.1 Adjustment of Rates

DGE states that because it has proposed offering levelized rates, it will be forgoing a portion of its allowed return

during the build-out period in order to offer customers lower initial rates, and that the opportunity for generating

additional revenue (from off-site customers) reduces the under-earning in the early years of the project

(Exhibit B-2, p. 7). DGE is proposing that additional revenues from other off-site customers be credited to the

utility in order to allow a potential equity return over the 20-year period that is equal to or in excess of the target

ROE (Exhibit B-1, p. 49).

DGE also states that it “…would adjust the levelized rates provided that DGE has earned a cumulative average

rate of return since the inception of rates exceeding its allowed rate of return or if such rate adjustment would not

otherwise impair DGE’s ability to earn a reasonable rate of return on its investment over the term of the levelized

rate period” (Exhibit B-2, p. 7).

Commission Determination

The Commission Panel notes that the allowed rate of return is not a guarantee that the utility will achieve that

return, and also that a levelized tariff rate over time implies a recognition that there may be over-earnings in some

years that compensate for under-earnings in the early years of a project. The Commission Panel determines

that given the nature of the Dockside Green project the levelized rate proposed, including the proposed

deferral of depreciation of plant assets for the Dockside Green project, is appropriate.

The Commission Panel determines that in its Annual Reports, DGE should include a calculation of the

cumulative average rate of return since the inception of rates. The Commission will consider that

cumulative average rate of return along with any other factors it considers appropriate to determine at that

time whether a revision to the tariff rate is required.

APPENDIX A to Order No. C-1-08

Page 7 of 13

4.0 REVENUE REQUIREMENTS

4.1 Capital Structure and Return on Equity

DGE states that it expects to capitalize 60 percent of the net rate base with long term debt, with the interest rate on

the debt expected to be 6.5 percent and amortized over 258 months. DGE expects to capitalize the remaining

40 percent of the rate base with common equity “…at a target return on equity (ROE) of 9.7 percent, which is

based on the current allowed ROE for a low-risk benchmark utility plus 100 basis points” (Exhibit B-1, p. 39).

DGE subsequently revised its financial model to incorporate an ROE of 9.62 percent, which is 100 basis points

greater than the 2008 allowed ROE for a low-risk benchmark utility of 8.62 percent (Exhibit B-4, p. 7).

DGE states that the capital structure and target ROE provide the utility owner an opportunity to earn a fair return

on invested equity taking into consideration various risks associated with the enterprise (Exhibit B-1, pp. 48-49).

DGE provides a table showing the capital structures and risk premiums for some other British Columbia utilities

and submits that DGE’s business risk is directionally higher than established utilities because “…DGE is a new

business venture employing emerging technology, in which the exact nature of future customer needs is difficult

to estimate with precision” (Exhibit B-4, p. 6).

DGE highlights the energy demand risk arising from the long lead time required for the Dockside Green project

and the consequent uncertainty in forecasting the composition of future housing and timing of customer additions.

DGE notes that the assumed energy use volumes for Dockside Green are based on engineering estimates that

consider the expected energy requirements associated with LEED-Platinum standards, and that the volume risk

arises from occupancy, energy intensity, weather and other forecast errors (Exhibit B-4, p. 4). DGE notes that it

has mitigated the demand forecast risk in large part through the proposed rate structures (a 50 percent

fixed/50 percent variable rate structure) and through Service Agreements with DGLP (Exhibit B-1, p. 48).

The other significant risk claimed by DGE is that of construction cost escalation, which it submits has also been

mitigated through the Service Agreement with DGLP. DGE also states that it will attempt to further mitigate the

risk through fixed price contracts (Exhibit B-1, p. 48). DGE confirms that Nexterra has offered a fixed price turn

key contract for the gasification plant, back-up boiler and building, and that DGLP will provide the site

preparation, road access, landscaping and all required utilities to the central heating plant. DGE further confirms

that the only areas of uncertainty arise from changes to the specifications or scope of the project required by DGE

(Exhibit B-2, p. 9).

APPENDIX A to Order No. C-1-08

Page 8 of 13

Other risks cited by DGE include:

• Operating cost inputs and inflation rates; • Uncertainty of Off-site sales volumes; • Unknown escalation rates of competing fuels; and • Small size company and limited customer base.

DGE is proposing that changes in non-controllable costs be flowed through in future onsite rates, such changes to

include changes in plant operating costs during the initial three years, changes in biomass, natural gas, and

electricity costs, and changes in legal and regulatory requirements. The achieved return on capital over the 20-

year levelization period would be subject to future reviews for reasonableness by the Commission (Exhibit B-1,

p. 49).

The risk of cost changes related to the primary fuel (wood-waste) for the Wood Waste Facility, is limited by the

binding letter of intent between DGE and the supplier, Three Point Properties LLP (“Three Point”), which

provides for a 20-year supply of fuel at a fixed price of $20 per BDT for the first ten year period and $30 per BDT

for the subsequent ten year period. DGE notes that the arrangement with Three Point provides the utility with a

reliable supply of biomass that meets the Nexterra specifications at a stable predictable cost, but that the

arrangement does not restrict the utility from pursuing other supply sources, which may enhance price-

competitiveness (Exhibit B-2, p. 5).

Commission Determination

The Commission has reviewed the evidence provided by DGE and concurs that there are risks associated with the

project, but also notes that DGE has taken measures to mitigate those risks. Such measures include the levelized

rate structure that includes a higher fixed rate component than typical utility rates, the use of cost or risk sharing

agreements, and the use of fixed price long-term contracts.

DGE provided a list of some other B.C. utilities and the capital structures and risk premiums allowed for those

utilities (Exhibit B-4, p. 6) and the Commission has also considered those comparables.

Finally, the Commission has considered the LEED-Platinum design of the Dockside Green development and that

all of the buildings in the development will be designed to outperform the Model National Energy Code for

Buildings by at least 40 percent, which will translate into savings for occupants. Vancity and Windmill make up

DGLP and own 49 percent and 17 percent of DGE respectively. In the Commission’s view, the allowed capital

structure and ROE should not penalize green developments that incorporate DES.

APPENDIX A to Order No. C-1-08

Page 9 of 13

The Commission determines that given the unique nature of this project, its small size, and the fact that it

is an entirely greenfield project, the applied-for capital structure and risk premium of 100 basis points

should be approved. The Commission also determines that even though the levelized rate is based on an

ROE of 9.62 percent, DGE should use the ROE for a low-risk benchmark utility as determined by the

Commission plus the additional 100 basis points allowed as a basis for calculating its allowed earnings for

each year for service to Dockside Green.

The Commission conditionally approves the long-term debt financing rate of 6.5 percent but requires that

any debt instrument be filed with the Commission and such instrument will be subject to acceptance at that

time.

5.0 TARIFF TERMS AND CONDITIONS

5.1 Sections 22 and 23

Section 22: Term of Service Agreement states that the initial term of the service agreement, when a Main

Extension is required, will be for a period of time fixed by the utility not exceeding the number of years used to

calculate the revenue in the Main Extension test. The Main Extension test is an economic test described in

Section 10 of the Tariff Terms and Conditions, and establishes that if the economic test results indicate a negative

net present value for a proposed extension, the extension may proceed if the customers to be served by the

extension provide a contribution in aid of construction so that any projected revenue shortfall is eliminated.

Section 23: Termination of Service states, among other things, that termination of service may result in the

customer being charged the full cost of all infrastructure associated with the provision of service to the customer

as determined by the utility to ensure other customers are not adversely impacted by the termination.

The Commission Panel is not persuaded that the requirement in Section 23 indicating that a customer terminating

service may be charged the full cost of all infrastructure associated with the provision of service to the customer

“…as determined by the utility…” is necessary or in the public interest. The Commission Panel also notes that

the “…full cost of all infrastructure…” is not a defined term. While the Commission Panel can speculate or

assume that the “full cost” refers to the depreciated book value of the infrastructure in question, and that the use of

the depreciated book value might be sufficient to ensure that other customers are not adversely impacted, it is not

clear that such is the case. The Tariff provision as currently worded would not preclude an argument that full cost

refers to the original, undepreciated cost of the infrastructure.

APPENDIX A to Order No. C-1-08

Page 10 of 13

Commission Determination

Provisions concerning recovery of infrastructure costs may be appropriate and may be included in contracts

between the DGE and the Developer, and ultimately stratas within the Dockside Green development. That

appears to be within the control of DGE and the Developer. For new Off-site attachments, to the extent that they

require new infrastructure, the Commission Panel is of the view that DGE has the ability under Section 22 to set a

term of service equal to the number of years used to calculate the revenue in the Main Extension test. Therefore,

the Commission determines that contractual provisions between the customers and DGE, the Main Extension test,

and the ability of DGE under Section 22 to establish for any new customer on a main extension a term of service

that is equal to the number of years used to calculate the revenue in the Main Extension test, in combination,

provide adequate protection to DGE, without the need for the noted provision in Section 23. Consequently, the

Commission directs DGE to remove the sentence that reads as follows from Section 23:

“Termination of Service may result in the Customer being charged the full cost of all infrastructure associated with the provision of Service to the Customer as determined by the Utility to ensure other Customers on the Hydronic Energy system are not adversely impacted by the termination.”

The Commission also requires that any rate changes, which may be required either for new or existing customers,

be included in a tariff and submitted to the Commission for approval prior to such rates coming into effect.

6.0 RESPONSIBILITY FOR RISKS

DGE identifies a number of risks and notes the actions it has taken to mitigate many of the risks. The

Commission, in approving the requested capital structure and ROE, is recognizing the risks associated with the

unique nature of the project, in every respect.

For greater clarity and certainty the Commission addresses the following risks and clarifies responsibility for

each.

6.1 Thermal Energy Generation System

DGE states that Nexterra has been contracted to provide a turn key gasification system that will supply 2 MWth

of hot water to the Dockside Green DES and that the gasification system will be housed to ensure that there is no

disturbance to the local community from the gasification system operations (Exhibit B-1, p. 12). Nexterra will

APPENDIX A to Order No. C-1-08

Page 11 of 13

guarantee the heat generation capacity and emissions for the gasification system (Exhibit B-1, p.18). The system

will have a 3.4 MWth natural gas back-up system that will provide peaking capacity and back-up heat when the

gasification plant is not in operation. The Application states that as a requirement of the LEED-Platinum

designation, any credits or monetary value assigned to greenhouse gas emissions at Dockside Green will be

owned by the developer (Exhibit B-1, p. 33).

DGE, in its justification for requested equity ratio and risk premium, describes the operation as a “new business

venture employing emerging technology” (BCUC IR 2.23.1). The Commission is of the view that in allowing the

requested equity ratio and risk premium, customers should not be exposed to risks from uncertainties related to

the “emerging technology”. Furthermore, the inability of customers to share in any monetary benefits related to

the greenhouse gas impact of this technology indicates that it would not be reasonable for them to be responsible

for any extraordinary costs that may be required in order to realize such benefits.

Commission Determination

Any extraordinary capital expenditures or operating and maintenance expenses, natural gas and/or any

other commodity costs that are incremental to the costs included in the revenue requirements estimate

presented in the Application and are required in order that the thermal energy generation system referred

to as the Nexterra Plant fulfills the role described for it in the Application and supporting material, will not

be included in DGE rate base and revenue requirements, and will not be recovered in DGE customer rates.

6.2 Biomass Plant Fuel and Operating Costs

DGE states that biomass for the gasification plant will be supplied from local sources and, at the time of the

Application, there is a draft 20-year fixed price agreement between DGE and a local supplier to supply wood-

waste (Exhibit B-1, p. 38). DGE states that in addition to this draft agreement it has identified several alternate

sources of supply should these be required. DGE proposes that changes in non-controllable costs be flowed

through in future onsite rates, and includes in those costs, changes in plant operating costs and changes in biomass

costs. In view of the costs stated in the draft 20-year fixed price agreement, which underpin the economics of the

DES and the assurance of alternate sources of supply, and consideration of the risks associated with emerging

technology in the ROE, the Commission Panel will not permit the customer to be exposed to the risk of higher

costs for biomass fuel.

APPENDIX A to Order No. C-1-08

Page 12 of 13

Commission Determination

Any extraordinary capital expenditures or operating and maintenance expenses, natural gas and/or any

other commodity costs that are incremental to the costs included in the revenue requirements estimate

presented in the Application and are required in order to obtain, process, handle or replace the fuel source

for the district energy system, including the cost of gas that is used because wood supply is not available or

the cost of wood supply to the extent it exceeds the price set out in the Binding Letter of Intent with Three

Point Properties LLP that is Attachment 7.1 in Exhibit B-2, will not be included in the DGE rate base and

revenue requirements, and will not be recovered in DGE customer rates.

7.0 ANNUAL REPORTING REQUIREMENTS

Section 24 of the Act requires that:

“In its supervision of public utilities, the commission must make examinations and conduct inquiries necessary to keep itself informed about

(a) the conduct of public utility business, (b) compliance by public utilities with this Act, regulations or any other law, and (c) any other matter in the commission’s jurisdiction.”

In compliance with Section 24, the Commission has directed the utilities under its jurisdiction to file Annual

Reports within four months after the end of the financial year. The Commission is empowered to require the

Annual Report filing pursuant to Section 49 of the Act which states that:

“The commission may, by order, require every public utility to do one or more of the following:

(a) keep the records and accounts of the conduct of the utility's business that the commission may specify, and for public utilities of the same class, adopt a uniform system of accounting specified by the commission; (b) provide, at the times and in the form and manner the commission specifies, a detailed report of finances and operations, verified as specified; (c) file with the commission, at the times and in the form and manner the commission specifies, a report of every accident occurring to or on the plant, equipment or other property of the utility, if the accident is of such nature as to endanger the safety, health or property of any person; (d) obtain from a board, tribunal, municipal or other body or official having jurisdiction or authority, permission, if necessary, to undertake or carry on a work or service ordered by the commission to be undertaken or carried on that is contingent on the permission.”

APPENDIX A to Order No. C-1-08

Page 13 of 13

The Commission direction to utilities regarding the annual report requirements were updated in Commission

Letter No. L-36-94.

The Commission has established an Annual Report form for steam/hot water utilities that are applicable to DGE. DGE can obtain a copy of the Annual Report forms for steam/hot water utilities from the Commission.

DGE’s Annual Report to the Commission is also to contain an updated CPCN Summary section of the Financial Model that was submitted in Exhibit B-4 (“Updated CPCN Summary”). The Updated CPCN Summary in DGE’s Annual Report to the Commission is to show the forecast and actual results by year from 2009 to 2018 with an explanation of the variances in the current year from forecast.

ERICA M. HAMILTON COMMISSION SECRETARY

Commission.Secretary@bcuc.com web site: http://www.bcuc.com

SIXTH FLOOR, 900 HOWE STREET, BOX 250 VANCOUVER, B.C. CANADA V6Z 2N3

TELEPHONE: (604) 660-4700 BC TOLL FREE: 1-800-663-1385

FACSIMILE: (604) 660-1102

Log No. 25530

PF/Dockside Green Reconsider C-1-08/Vary Conditions Determination

VIA E-MAIL dwb@bht.com June 30, 2008 Mr. David Bursey Bull, Housser & Tupper LLP Barristers & Solicitors 3000 Royal Centre P.O. Box 11130 1055 West Georgia Street Vancouver, B.C. V6E 3R3

Re: Dockside Green Energy LLP (“DGE”) Certificate of Public Convenience and Necessity for the District Energy System

Application for Reconsideration of BCUC Order No. C-1-08 dated April 17, 2008 (“Order”)

Further to DGE’s May 30, 2008 application for reconsideration of Commission Order No. C-1-08, enclosed is Order No. C-3-08 and Reasons for Decision. Yours truly, Original signed by: Erica M. Hamilton cms Enclosure

SIXTH FLOOR, 900 HOWE STREET, BOX 250 VANCOUVER, B.C. V6Z 2N3 CANADA

web site: http://www.bcuc.com

TELEPHONE: (604) 660-4700 BC TOLL FREE: 1-800-663-1385

FACSIMILE: (604) 660-1102

…/2

BR I T I S H COL U M BI A

UTI LI TI E S COMM I SSI ON OR D E R NUM B E R C-3-08

IN THE MATTER OF the Utilities Commission Act, R.S.B.C. 1996, Chapter 473

and

an Application by Dockside Green Energy LLP for Reconsideration of Certain Provisions of

Commission Order No. C-1-08 and Reasons for Decision BEFORE: L.F. Kelsey, Panel Chair and Commissioner P.E. Vivian, Commissioner June 30, 2008 A.A. Rhodes, Commissioner

O R D E R

WHEREAS: A. By letter dated December 21, 2007, Dockside Green Energy LLP (“DGE”) applied to the Commission for a

Certificate of Public Convenience and Necessity (“CPCN”) to construct and operate a district energy system (“DES”) to provide energy service to the Dockside Green development (“Dockside Green”) currently being built on the Inner Harbour in Victoria, B.C. and for approval of Service Agreements, Terms and Conditions of Service and levelized rates (the “Application”); and

B. By Order No. G-8-08 dated January 11, 2008, the Commission established a Written Public Hearing and

Regulatory Timetable; and C. By letters dated January 11 and February 15, 2008, the Commission issued Information Requests No.1 and

No. 2 to DGE; and D. By letters dated January 21 and March 6, 2008, DGE filed responses to Information Requests No. 1 and

No. 2; and E. By e-mail dated January 23, 2008 SunGen Sustainable Developments Inc. filed a request for Intervenor

status; and F. By letter dated March 11, 2008 DGE filed its final submission; and G. By letter dated March 20, 2008, DGE filed responses to outstanding questions from Information Request

No. 1; and H. By Order No. C-1-08 (the “Order”) the Commission granted a CPCN to DGE for the construction and

operation of a DES to provide hydronic energy service at Dockside Green as set out in the Application, subject to the following conditions (“Conditions”):

2

…/3

BR I T I S H COL U M BI A

UTI LI TI E S COMM I SSI ON OR D E R NUM B E R C-3-08

1.1 Any extraordinary capital expenditures or operating and maintenance expenses, natural gas and/or any

other fuel commodity costs that are incremental to the costs included in the revenue requirements estimate presented in the Application and are required in order that the thermal energy generation system referred to as the Nexterra Plant fulfills the role described for it in the Application and supporting material, will not be included in DGE rate base and revenue requirements and will not be recovered in DGE customer rates.

1.2 Any extraordinary capital expenditures or operating and maintenance expenses, natural gas and/or any

other fuel commodity costs that are incremental to the costs included in the revenue requirements estimate presented in the Application and are required in order to obtain, process, handle or replace the fuel source for the district energy system, including the cost of gas that is used because wood supply is not available or the cost of wood supply to the extent it exceeds the price set out in the Binding Letter of Intent with Three Point Properties LLP that is Attachment 7.1 in Exhibit B-2, will not be included in the DGE rate base and revenue requirements and will not be recovered in DGE customer rates.

1.3 DGE has provided written confirmation to the Commission that it accepts the conditions to the CPCN,

within 60 calendar days of the date of this Order; and I. By letter dated May 30, 2008 DGE requested, pursuant to section 99 of the Utilities Commission Act (the

“Act”) that the Commission reconsider and vary its Order to remove the Conditions (the “Reconsideration Application”); and

J. By letter dated June 4, 2008, the Commission accepted the position of DGE that the matter should proceed

directly to a reconsideration and the Commission established a reconsideration of the Conditions, by way of a Written Public Hearing, based on the merits of the matter as set out in the Reconsideration Application; and

K. By copy of its letter dated June 4, 2008, the Commission provided an opportunity for the Intervenor of record

to comment on DGE’s request for reconsideration of Conditions in the Order; and L. The Intervenor did not file comments; and M. By letter dated June 6, 2008, DGE confirmed that was is content to rely on its submission dated 30 May 2008

for the purpose of the Commission’s reconsideration of the Conditions in the Order; and N. The Commission has considered the matter and determined that Commission Order No. C-1-08 should be

varied.

3

Orders/C-3-08_Dockside Green Reconsider C-1-08 Reasons

BR I T I S H COL U M BI A

UTI LI TI E S COMM I SSI ON OR D E R NUM B E R C-3-08

NOW THEREFORE pursuant to Section 99 of the Act, the Commission orders that Commission Order No. C-1-08 is varied as follows: 1. Sections 1.1, 1.2, 1.3 and 2 are removed. 2. Section 11 should be read so as to reflect the removal of the Commission determinations and directions set

out in Sections 1.1, 1.2, 1.3 and 2 only and should include all other directions in the Reasons for Decision attached as Appendix A to Commission Order No. C-1-08 and Appendix A to this Order.

DATED at the City of Vancouver, in the Province of British Columbia, this 30th day of June 2008. BY ORDER Original signed by: L.F. Kelsey Commissioner Attachment

APPENDIX A to Order No. C-3-08

Page 1 of 11

Application by Dockside Green Energy LLP for Reconsideration of Certain Provisions of

Commission Order No. C-1-08 and Reasons for Decision

REASONS FOR DECISION

1.0. BACKGROUND

1.1 Brief Summary of the CPCN Application

On December 21, 2007 Dockside Green Energy LLP (“DGE”) applied (“the Application”) to the British

Columbia Utilities Commission (“BCUC”, “Commission”) for:

(a) a Certificate of Public Convenience and Necessity (“CPCN”) to construct and operate a district energy system (“DES”) to provide energy service to the Dockside Green development currently being built on the Inner Harbour in Victoria, and

(b) approval of:

• a levelized rate base • forecast revenue requirements, including:

o a deemed capital structure of 40% equity, 60% debt o an allowed return on equity of 9.62% o long term debt financing at 6.5% o forecast operating costs

• accounting treatment of: o depreciation of plant assets o a 20 year levelized rate structure o rate design

• Service Agreement Terms & Conditions [Tariff]

The Dockside Green development is, if not unique, at least rare in its commitment to environmental and energy

sustainability relative to current standards of development.

Dockside Green is a mixed residential, office, retail and industrial development with a planned total floor space of

129,658 square meters (approximately 1.4 million square feet) on fifteen acres of formerly contaminated

industrial land in Victoria. The project is to be developed in nine phases over seven years and the first phase of

residential condominiums is now complete.

APPENDIX A to Order No. C-3-08

Page 2 of 11

The developer of the project is the Dockside Green Limited Partnership (“Dockside Green LP” or “Developer”),

which is owned by Vancity Capital Corporation (“Vancity”) and Windmill West Properties LLP (“Windmill”).

The Developer intends to construct a biomass facility to provide hot water heating to Dockside Green and has

established a private utility company, DGE, as the district energy system utility to operate a wood-waste

gasification system (the “Waste Wood Facility”). DGE is jointly owned by Corix Utilities Inc. (“Corix”),

Terasen Energy Services Inc. (“TES”), Vancity and Windmill. Corix, Windmill, and TES each own a 17 percent

interest in DGE and Vancity owns the remaining 49 percent. Corix is experienced in the ownership and operation

of utility and district energy systems, and DGE has contracted with Corix to provide utility operations (Exhibit B-

1, pp. 2-8).

The Dockside Green project will be a sustainable development certified by the Canada Green Building Council’s

Leadership in Energy and Environmental Design (“LEED”™) green building rating system (Exhibit B-1, p. 30).

LEED certification involves certification and credits in five principal LEED categories: sustainable sites, water

efficiency, energy and atmosphere, materials and resources, and indoor environmental quality. LEED-Platinum is

the highest of the four possible levels of LEED certification (Exhibit B-1, p. 7; Exhibit B-2, p. 1), and is the

expected rating for the Dockside Green development.

Further to the LEED-Platinum certification of the project, DGE will use a wood-waste fired gasification system

provided by Nexterra Energy Corp. (“Nexterra”) capable of delivering 2 MW thermal heat (“MWth”) for

residential/commercial district heating. The energy derived from the system is intended to reduce the greenhouse

gas emissions that would otherwise be produced from energy used at the development (Exhibit B-1, p. 7;

Exhibit B-2, Attachment 9.3, p. 4). DGE confirms that Nexterra has offered a fixed price turn key contract for

the gasification plant, back-up boiler and building, and that Dockside Green LP will provide the site preparation,

road access, landscaping and all required utilities to the central heating plant. DGE further confirms that, with

respect to the Nexterra plant, the only areas of uncertainty arise from changes to the specifications or scope of the

project required by DGE (Exhibit B-2, p. 9).

APPENDIX A to Order No. C-3-08

Page 3 of 11

Nexterra will guarantee the heat generation capacity and emissions for the gasification system and will provide a

one year warranty covering the system and its components (Exhibit B-1, p. 18). DGE states that biomass for the

gasification plant will be supplied from local sources and, at the time of the Application, there is a draft 20-year

fixed price agreement between DGE and a local supplier to supply wood waste (Exhibit B-1, p. 38). DGE states

that in addition to this draft agreement it has identified several alternate sources of supply should these be

required. The system will have a 3.4 MWth natural gas back-up system that will provide peaking capacity and

back-up heat when the gasification plant is not in operation. The Application states that, as a requirement of the

LEED-Platinum designation, any credits or monetary value assigned to greenhouse gas emissions at Dockside

Green will be owned by the Developer (Exhibit B-1, p. 33). DGE will meter energy use at the building level and

will bill each strata as a separate customer. Each strata will sub-meter energy use for the purpose of allocating

energy costs within the strata (Exhibit B-1, p. 8).

Technology Early Action Measures (“TEAM”) funding from the federal Department of Natural Resources will

provide partially repayable assistance of $1.5 million. TEAM funding supports projects that are designed to

demonstrate technologies that mitigate gas emissions and sustain economic and social development (Exhibit B-1,

pp. 52-53).

In addition to serving the customers within the Dockside Green development, DGE will be seeking to serve

customers in close proximity to, but outside of, the project (“Off-site” customers) in order to earn incremental

revenues and reduce the cost of serving the Dockside Green customers. Although DGE states that it has received

expressions of interest from other nearby developments and is engaged in other nearby prospects, the only Off-

site customer currently forecast to be served by DGE is a Delta Hotel. DGE currently has a Memorandum of

Understanding (“MOU”) with the Delta Hotel and DGE assumes that the Delta Hotel MOU will be converted into

a sales agreement with no material changes (Exhibit B-1, pp. 20-21).

DGE states that the requested capital structure of 40 percent equity and 60 percent debt and target ROE of 9.62

percent provide the utility owner an opportunity to earn a fair return on invested equity taking into consideration

various risks associated with the enterprise (Exhibit B-1, pp. 48-49). DGE provides a table showing the capital

structures and risk premiums for some other British Columbia utilities and submits that DGE’s business risk is

directionally higher than established utilities because “…DGE is a new business venture employing emerging

technology, in which the exact nature of future customer needs is difficult to estimate with precision”

(Exhibit B-4, p. 6).

APPENDIX A to Order No. C-3-08

Page 4 of 11

1.2 Highlights of the Decision

By Commission Order No. C-1-08 dated April 17, 2008 (the “Order”) the Commission granted a CPCN to DGE,

subject to the following conditions:

1.1 Any extraordinary capital expenditures or operating and maintenance expenses, natural gas and/or any other fuel commodity costs that are incremental to the costs included in the revenue requirements estimate presented in the Application and are required in order that the thermal energy generation system referred to as the Nexterra Plant fulfills the role described for it in the Application and supporting material, will not be included in DGE rate base and revenue requirements and will not be recovered in DGE customer rates.

1.2 Any extraordinary capital expenditures or operating and maintenance expenses, natural gas and/or

any other fuel commodity costs that are incremental to the costs included in the revenue requirements estimate presented in the Application and are required in order to obtain, process, handle or replace the fuel source for the district energy system, including the cost of gas that is used because wood supply is not available or the cost of wood supply to the extent it exceeds the price set out in the Binding Letter of Intent with Three Point Properties LLP that is Attachment 7.1 in Exhibit B-2, will not be included in the DGE rate base and revenue requirements and will not be recovered in DGE customer rates.

1.3 DGE has provided written confirmation to the Commission that it accepts the conditions to the

CPCN, within 60 calendar days of the date of this Order.

2. If any of the conditions in the CPCN for the district energy system are not met, the CPCN is cancelled immediately.

The Commission generally granted approval of other matters requested in the Application, subject to DGE

holding a CPCN for the DES, and with the exception of a small change to the Tariff as proposed.

2.0 APPLICATION FOR RECONSIDERATION

By Letter dated May 30, 2008 DGE advised the Commission that it has reviewed the Order and finds it acceptable

except for the conditions set out in sections 1.1 and 1.2 of the Order (“Conditions”). “Therefore, DGE requests,

pursuant to section 99 of the Utilities Commission Act (“Act”), that the Commission reconsider and Vary its Order

to remove the Conditions” (the “Reconsideration Application”). DGE cites the following grounds in support of

this request for reconsideration:

1. The Commission erred in law by including the Conditions in the Order without giving DGE an opportunity to comment on them.

APPENDIX A to Order No. C-3-08

Page 5 of 11

2. Changed circumstances – recent amendments to the Act require the Commission to consider the British Columbia Energy Objectives.

DGE requested that the Commission consider the request for reconsideration expeditiously as the Dockside Green

project is advancing.

3.0 THE RECONSIDERATION PROCESS

In considering a request for reconsideration, the Commission follows the practice outlined in the Commission’s

Reconsideration Criteria, which is outlined in the Commission’s document, “Understanding Utility Regulation, A

Participants’ Guide to the BC Utilities Commission”. Although a request for reconsideration usually proceeds

through a two phase process, in the situation at hand the Commission accepted the position of DGE that the

matter should proceed directly to a reconsideration and by letter dated June 4, 2008 (Reconsideration Exhibit A-1)

established a reconsideration of Order No. C-1-08 according to a written submission process. In considering the

DGE request the Commission was of the understanding that DGE did not wish to file any further submissions on

this matter, other than a reply to a submission from the Intervenor in the proceeding that considered the CPCN

Application, should a submission be filed in this proceeding. The Commission requested that DGE confirm this

understanding. By letter dated Friday, June 6, 2008 DGE confirmed that it is “content to rely on its submission

dated 30 May 2008 for the purpose of the Commission’s reconsideration of the Conditions of the Order”

(Reconsideration Exhibit B-2).

One Intervenor registered in the proceeding to consider the CPCN Application for the DES, however, the

Commission notes that the Intervenor did not participate actively in the proceeding. The Commission, by copy of

its letter of June 4, 2008, provided an opportunity for the Intervenor of record to comment on DGE’s request for

reconsideration of Conditions of the Order. No comments from the Intervenor were received by the Commission

by the June 10, 2008 deadline.

4.0 RECONSIDERATION

4.1 DGE Position

DGE states that there are two reasons which support its request for reconsideration. The Commission considers

that these “reasons” address the question of “grounds” that must be met in order for a reconsideration to be

warranted.

APPENDIX A to Order No. C-3-08

Page 6 of 11

“(a) The Commission erred in law The Commission erred in law by including the Conditions in the Order without giving DGE an opportunity to comment on them. Doing so contravenes basic principles of administrative fairness. Specifically, DGE was not given a fair opportunity to know the case it had to meet and was denied a right to be heard on the issues raised by the Conditions” (Reconsideration Exhibit B-1, p. 1). (b) Changed circumstances - recent amendments to the Act require the Commission to consider the British Columbia Energy Objectives Recent amendments to the Act require the Commission to consider the “government’s energy objectives” in making certain decisions whether to issue a CPCN” (Exhibit B-1, p. 2). DGE acknowledges that the Commission’s decision to impose the Conditions was made before these amendments to the Act came into force, but states “the Commission must now have regard to them during this reconsideration” (Reconsideration Exhibit B-1, p. 3).

DGE requests that the Commission delete Section 1 from the Order and identifies the following reasons why the

Conditions should be deleted from the Order. The Commission considers that the following reasons are

additional grounds, which go to the merits of the Reconsideration Application.

“ (a) The Conditions are ambiguous The meaning of “extraordinary” and “incremental” in the Conditions is unclear in the context in which those terms are used in each condition. The following text is similar in each condition: Any extraordinary capital expenditures or operating and maintenance expenses ... that are incremental to the costs included in the revenue requirements estimate presented in the Application . . . DGE does not know how the Commission intends to identify and measure “extraordinary incremental” costs in relation to the thermal energy generation system and the fuel supply. Consequently, DGE does not know how it would implement the Conditions. The uncertain scope of the Conditions makes it difficult for DGE to assess the associated financial risk.

(b) Unfair allocation of risk to DGE Extraordinary expenditures would normally include expenditures that by their inherent nature are difficult to forecast. If that is the intent in the Conditions, then the justification for requiring DGE to bear this forecast risk is not explained. The evidentiary record before the Commission does not justify allocating extraordinary financial risk to DGE.

APPENDIX A to Order No. C-3-08

Page 7 of 11

DGE’s allowed return on equity (“ROE”) is not extraordinary - only 100 basis points higher than the ROE the Commission sets for a low-risk benchmark utility. In absolute dollars, 100 basis points at full build-out of the DGE system would equate to approximately $24,000 per year. The 100 basis point risk premium is modest and reasonable for a small utility like DGE, but certainly not adequate to compensate for the extraordinary financial risk imposed by the Conditions. As explained in DGE’s response to BCUC Information Request #2, Question 23.1, DGE’s equity ratio and level of ROE are comparable to other Commission-regulated utilities that have less risk.

For the setting of rates and service, the law is clear that the BCUC mandate under section 59 of the Act is to balance the interests of the utility as owner and the interests of the ratepayers as service users. The public utility’s interest is to receive a fair return on its prudently invested capital, which includes a fair return of the capital through reasonable depreciation and a fair return on the capital through a reasonable return on capital invested. The ratepayers’ interest is to receive safe and reliable service under terms and rates that are just and reasonable . . .

The Conditions upset the required balance by imposing unfair financial risk on DGE without a commensurate return on investment. In effect, the Commission is deciding in advance that any “extraordinary incremental” expense identified in the Conditions will not be prudent. DGE will be denied a fair opportunity to recover any such investment even if it is prudent and in the interests of the customers. DGE will not even have the opportunity to demonstrate the prudence of its actions.

(c) The Conditions are unnecessary to protect any public interest DGE presumes the Conditions are intended to protect the DGE ratepayers from extraordinary costs that DGE may encounter. DGE submits that it is unnecessary and, in fact, punitive for the Commission to prejudge future circumstances by deciding now that DGE must bear those extraordinary costs whatever the circumstances may be. The ambiguity in the Conditions will require DGE to return to the Commission in any event to verify that it is applying the Conditions correctly. The public interest would be better served by reviewing the relevant circumstances at the time the event occurs before making a judgment about how extraordinary incremental costs should be recovered. DGE is a regulated public utility under the Act. The Commission has comprehensive regulatory powers over DGE to protect customers and the public interest. If DGE incurs extraordinary incremental costs, then the Commission has the authority to review the prudence of those costs before DGE may include them in the rates it will charge its customers. DGE should be allowed a fair opportunity to recover those costs if they are prudent and reasonable. The Commission’s authority to review DGE’s costs is more than adequate to protect the customers and the public interest. The Commission has not explained why the additional measures in the Conditions are necessary to serve the public interest. The unique and innovative “green” nature of the Dockside Green development is a prominent feature of the development and will be well known to those who buy property in the development. In fact, the LEED Platinum aspect of the development is likely to be an attraction for many buyers. All buyers will receive extensive disclosure statements outlining the features of the development, including the DGE system. The disclosure statements are governed by the Real Estate Development Marketing Act. DGE will be also distributing information through a website and other means to explain its system. These circumstances do not warrant extraordinary “up front” measures to eliminate all equipment and energy supply risk at the expense of DGE.

APPENDIX A to Order No. C-3-08

Page 8 of 11

(d) Inequitable treatment among utilities The Commission has not explained why DGE should bear financial risk that other utilities do not bear. Specifically, other utilities are typically permitted an opportunity to justify the prudence of any extraordinary incremental costs for equipment and energy supply, if and when those costs occur. If the Commission decides the costs are prudent, then the utility is allowed to include them in the rates. DGE filed a comprehensive application explaining the DGE system, the operation, the service, the forecast costs and the measures that DGE has taken to manage the risk in the contracts with Nexterra and Three Point Properties. DGE has also responded to numerous information requests that elaborate on the information in the application. DGE believes it has done as much or more than other established utilities have done in similar situations to demonstrate the prudence of its actions to date. Treating DGE in a different manner is inequitable and puts DGE at a competitive disadvantage. There is no basis in economic theory or law to do so in this case. Nor is there a need to do so.

(e) Contrary to the Act, British Columbia Energy Plan, and Energy Objectives The Conditions impose an unnecessary and unfair burden on DGE that frustrates the attempt to develop an innovative and environmentally-desirable approach to energy supply in an urban setting. This outcome is contrary to the objectives of the recent British Columbia Energy Plan and related policy initiatives. More importantly, the Conditions are contrary to the Government energy objectives as set out in the recently-amended Act. The DGE system is a district energy system that uses biomass as the fuel. These two elements both have significant environmental benefits compared to a conventional energy system by using fuel and infrastructure efficiently to reduce the environmental footprint. In supplying energy to the Dockside Green development and potentially other customers in the surrounding area, DGE’s objective is to make the Dockside Green development greenhouse gas neutral. The Dockside Green project is targeting a LEED Platinum standard. The project is already recognized as one of the world’s leading examples of sustainable development. In British Columbia, the Province’s energy policy objectives are designed to promote energy efficient and greenhouse gas neutral energy projects of this very type. Distributed energy systems have an important role to play in reducing the environmental impact of energy consumption. The Conditions create an entry barrier for innovative technology. This decision will send a signal to the market place that will discourage investment in innovative energy distribution systems. The default to conventional energy distribution systems will be compelling since the financial risk will be less. This outcome is contrary to the clear intent of the recent amendments to the Act” (Reconsideration Exhibit, pp. 3-8).

APPENDIX A to Order No. C-3-08

Page 9 of 11

4.2 Commission Determination on Grounds for Reconsideration

The Commission will first respond to DGE’s grounds in support of the request for reconsideration.

1. The Commission erred in law by including the Conditions in the Order without giving DGE an opportunity to comment on them.

The Commission disagrees with DGE that there was an error in law. The Commission is of the view that the

Conditions to the granting of a CPCN for the construction and operation of the DES were not “new ground”, as

referenced in the Reconsideration Application. The Conditions related to assurances of performance of the

“Nexterra Plant” and the wood supply made in the Application and subsequent responses to Information

Requests. The Commission, in issuing Order No. C-1-08 was simply imbedding the commitments, contractual

arrangements and assurances made by DGE into the CPCN.

2. Changed circumstances – recent amendments to the Act require the Commission to consider the British Columbia Energy Objectives

The Commission agrees with this statement; however, the Commission reminds DGE that it did consider the

unique nature of this project, its LEEDS target designation and the project’s alignment with the British Columbia

Energy Objectives and specifically noted in granting the applied-for capital structure and ROE, “in the

Commission’s view, the allowed capital structure and ROE should not penalize developments that incorporate

DES” (Decision, Appendix A, p. 8). DGE is also reminded that the Commission did grant a CPCN, as requested,

albeit with Conditions that are related to undertakings and commitments detailed in the Application.

Nevertheless, the Commission acknowledges that the Conditions may, to some extent, create an entry barrier for

innovative technology by increasing the financial risk to DGE employing such technology relative to

conventional energy systems. As this outcome would appear to be inconsistent with the BC Energy Objectives,

the Commission concludes that it needs to reconsider the Conditions in the Order.

The Commission will, therefore, consider DGE’s reasons with respect to why the Conditions should be deleted

from the Order.

APPENDIX A to Order No. C-3-08

Page 10 of 11

4.3 Commission Reconsideration of Conditions

With respect to DGE’s comment above that “[t]he Conditions impose an unnecessary and unfair burden on DGE

that frustrates the attempt to develop an innovative and environmentally-desirable approach to energy supply in an

urban setting”, the Commission reminds DGE of its own assertion that “the BCUC mandate under section 59 of

the Act is to balance the interests of the utility as owner and the interests of the ratepayers as service users”

(Reconsideration Exhibit B-1, p. 4). DGE states further “[t]he ratepayers interest is to receive safe and reliable

service under terms and rates that are just and reasonable” (Reconsideration Exhibit B-1, p. 4). That is, although

the Commission must consider the BC Energy Objectives when reviewing a CPCN Application, it is not clear that

the Commission is expected to approve an alternative that put at risk the provision of safe, reliable service under

terms and rates that are just and reasonable.

In explaining why the Conditions should be deleted from the Order, DGE states that the meaning of

“extraordinary” and “incremental” in the Conditions is unclear in the context in which those terms are used in

each condition (Reconsideration Exhibit B-1, p. 3). DGE also states that it “presumes the Conditions are

intended to protect the DGE ratepayers from extraordinary costs that DGE may encounter. DGE submits that it is

unnecessary and, in fact, punitive for the Commission to prejudge future circumstances by deciding now that

DGE must bear those extraordinary costs whatever the circumstances may be. The ambiguity in the Conditions

will require DGE to return to the Commission in any event to verify that it is applying the Conditions correctly.

The public interest would be better served by reviewing the relevant circumstances at the time the event occurs

before making a judgment about how extraordinary incremental costs should be recovered” (Reconsideration

Exhibit B-1, p. 6). The Commission accepts that the wording of the Conditions does not provide an explicit

formula and that a Commission review would likely be needed to determine an amount to be disallowed under the

Conditions.

DGE further states “DGE is a regulated public utility under the Act. The Commission has comprehensive

regulatory powers over DGE to protect customers and the public interest. If DGE incurs extraordinary

incremental costs, then the Commission has the authority to review the prudence of those costs before DGE may

include them in rates it will charge its customers” (Reconsideration Exhibit B-1, p. 6).

The Commission is persuaded by the argument that the interests of both the ratepayers and the utility will be

properly served by removing the Conditions and instead, as DGE suggests, “reviewing the relevant circumstances

at the time the event occurs before making a judgement about how extraordinary incremental costs should be

recovered” (Reconsideration Exhibit B-1, p. 6). As noted above, DGE states it “is a regulated public utility under

APPENDIX A to Order No. C-3-08

Page 11 of 11

the Act. The Commission has comprehensive regulatory powers over DGE to protect customers and the public

interest. If DGE incurs extraordinary incremental costs, then the Commission has the authority to review the

prudence of those costs before DGE may include them in the rates it will charge its customers.” The CPCN

Application and evidence is very specific about the commitments, contractual arrangements, and assurances made

by DGE to mitigate risk and this should prove to be a useful reference for both DGE and the Commission when

assessing the prudency of costs before including them in rates. The extent to which the Dockside Green

disclosure statement explicitly discusses responsibility for incremental costs related to the thermal energy

generation system and fuel supply may also provide a useful reference when considering incremental costs. The

Commission is satisfied that this approach will afford DGE the opportunity to demonstrate the prudence of its

actions and at the same time address the interests of the ratepayers as service users. Furthermore, the Commission

expects that the levelized rate methodology approved for Dockside Green should have the effect of muting the

impact of incremental costs on ratepayers. That is, extraordinary incremental costs may result in the rates

established under the levelized rate methodology continuing in effect for a longer period of time.

4.4 Commission Determination

The Commission grants a CPCN to DGE for the construction and operation of a DES to provide hydronic

energy service at Dockside Green as set out in the Decision, with conditions removed.

The Commission has reviewed Sections 2 through 11 in the Order in the context of the above Determination and

finds no reason to change those Sections with the exception that Section 2 is not required and Section 11 must be

changed as it relates to the above Commission Determination.

  

  

IN THE MATTER OF    

TERASEN GAS INC.  

 BIOMETHANE APPLICATION 

       

DECISION      

December 14, 2010      

BEFORE:  

D.A. Cote, Panel Chair/Commissioner A.A. Rhodes, Commissioner L.A. O’Hara, Commissioner 

 

 TABLE OF CONTENTS 

Page No. 

1.0  EXECUTIVE SUMMARY ............................................................................................................. 1 

2.0  INTRODUCTION ....................................................................................................................... 4 

2.1  Application .......................................................................................................................... 4 

2.2  Orders Sought ..................................................................................................................... 5 

2.3  Regulatory Process .............................................................................................................. 6 

3.0  PROJECT DESCRIPTION ............................................................................................................. 9 

3.1  Overview ............................................................................................................................. 9 

3.1.1  Supply of Biomethane ........................................................................................... 10 

3.1.2  Sale of Biomethane to Customers ........................................................................ 10 

3.1.3  Cost Allocation and Recovery ............................................................................... 11 

3.1.4  Notional Delivery .................................................................................................. 13 

3.2  Outline of Projects ............................................................................................................ 13 

3.2.1  Catalyst Project ..................................................................................................... 13 

3.2.2  CSRD Project ......................................................................................................... 15 

3.3  Criteria for Future Projects ............................................................................................... 17 

3.3.1  Guiding Principles for Development of Biomethane Supply ................................ 17 

3.3.2  Maximum Biomethane Cost ................................................................................. 18 

3.3.2.1  BC Hydro’s RIB Tier 2 Rate ...................................................................... 19 

3.3.2.2  Alternatives Considered for Economic Test ........................................... 20 

3.3.3  Regulatory Review of New Supply Projects and Contracts .................................. 21 

3.3.4  Post Implementation Review ................................................................................ 22 

3.4  Pricing Methodology ......................................................................................................... 22 

4.0  KEY ISSUES AND DETERMINATIONS ....................................................................................... 24 

4.1  Introduction ...................................................................................................................... 24 

4.2  Alignment with British Columbia’s Energy Objectives         and Provincial Government Policy ............................................................................. 24 

4.4  Product Demand ............................................................................................................... 30 

4.5  Commission Determination on the Projects ..................................................................... 34 

TABLE OF CONTENTS 

Page No. 

 4.6  Terasen’s Role in Biogas Upgrading Process .................................................................... 35 

4.7  Criteria for Future Projects ............................................................................................... 39 

4.8  Risk of Stranded Assets ..................................................................................................... 43 

4.9  Principles for Cost Recovery ............................................................................................. 45 

4.9.1  Rate Setting ........................................................................................................... 45 

4.9.2  General Cost Recovery Principles ......................................................................... 46 

4.9.3  Determination of Costs Related to System Changes ............................................ 48 

4.9.4  Costs to be Allocated to all Customers ................................................................. 48 

4.9.5  Costs to be Allocated to Biomethane Program Customers .................................. 49 

4.9.6  Intervener Submissions......................................................................................... 50 

4.10  Other Project Risks ............................................................................................................ 52 

4.10.1  Risk to Gas Supply Portfolio .................................................................................. 52 

4.10.2  Risk of Failure to Supply Biomethane ................................................................... 53 

4.10.3  Operational and System Risk ................................................................................ 54 

4.10.4  Facilities Cost Risk ................................................................................................. 54 

4.11  Post Implementation Review and Reporting .................................................................... 55 

5.0  OTHER APPROVALS REQUESTED ............................................................................................ 58 

5.1  Biomethane Variance Account ......................................................................................... 58 

5.2  Rate Schedules .................................................................................................................. 59 

6.0  OTHER COMMISSION PANEL CONSIDERATIONS ..................................................................... 62 

7.0  SUMMARY OF DIRECTIVES ..................................................................................................... 64 

 COMMISSION ORDER G‐194‐10 

APPENDICES APPENDIX A  Orders Sought APPENDIX B  The Regulatory Process APPENDIX C  List of Exhibits APPENDIX D  List of Acronyms Appendix E  Sections of Utilities Commission Act 

1   

 

1.0 EXECUTIVE SUMMARY 

 

On June 8, 2010 Terasen Gas Inc. filed an Application for approval of what it describes as an end‐to‐

end business model encompassing the purchase of biogas and/or Biomethane for sale to its 

customers.  The Application was filed against the backdrop of the continued evolution of British 

Columbia’s energy policy.  The most recent addition, The Clean Energy Act, received Royal Assent 

on June 3, 2010 and, in the view of the Applicant, has given renewed and heightened importance 

to its role in the development of renewable resources, the reduction of GHG emissions, the 

reduction of waste through the use of biogas and biomass as well as its role in promoting energy 

efficiency.  Further, Terasen has noted that federal, provincial, regional and municipal governments 

have all become increasingly focused on climate change and the impact of pollution and have 

adopted policies to favor renewable energy forms as key to solving environmental challenges. 

 

Terasen Gas is developing a number of initiatives which it believes are aligned with BC Government 

Policy and the Clean Energy Act.  These are outlined in its 2010 Long Term Resource Plan that is 

currently before the British Columbia Utilities Commission.  The Biomethane Service Offering 

Application is the first of these initiatives that has come before the Commission.  This Application is 

made up of three components: 

 

• The Biomethane Supply Model which addresses the acquisition of a reliable supply of 

biogas. 

• The Biomethane product offering which consists primarily of a rate offering allowing for 

the notional sale of Biomethane to Terasen customers on a voluntary basis. 

• The cost allocation and recovery model addressing the recovery of costs for the product 

offering from the various customer groups. 

 

This Biomethane Service Offering which includes all elements of the biomass model has been 

referred to as the Biomethane Program or Program within this Decision.  Terasen’s Application 

seeks approval of a number of Orders encompassing rates, cost recovery, supply and post 

implementation review which are related to the Program.  Key among these are the following: 

2   

 

approval of two projects, the Catalyst Project in Abbotsford, BC and the Columbia Shuswap 

Regional District Project in Salmon Arm, BC; the allocation of costs between all non by‐pass 

customers and voluntary Biomethane gas purchasing customers and a set of criteria allowing for 

the filing of future supply contracts. 

 In its review of the Application, the Commission Panel raised and examined a number of issues in 

reaching the determinations made in this Decision.  The first group of these includes the following: 

the alignment with British Columbia’s energy objectives and Provincial Government policy, the 

adequacy of supply for these and future Projects and the level of customer demand for this type of 

program.  On the basis of this examination, the Panel is satisfied the Program is in alignment with 

both British Columbia’s energy objectives and Provincial Government policy and there is sufficient 

demand and supply to justify moving forward.  Accordingly, the Panel has determined the two 

Projects are in the public interest and has approved both of them as well as the related capital 

costs.  However, the Panel in reaching this determination has noted that it would be prudent for 

TGI to thoroughly test the proposed model in the marketplace before reaching a conclusion as to 

its full market potential. 

 The second group of issues is related to how the Biomethane Program will work and includes the 

following: 

 

• Terasen’s proposed role in the biogas upgrading process; 

• The criteria for future projects; 

• The risk of stranded assets and other project risks; 

• Principles for cost allocation and recovery; and 

• Post implementation review and reporting. 

 With respect to Terasen’s proposed role in the upgrading process, the Panel has made no finding 

on the acceptability of this and directs that the upgrading business be sufficiently distinct so as to 

be severable if the Commission were to determine that this function should be conducted through 

a separate entity in the future.  Concerning the criteria for future projects to be approved on a 

3   

 

streamlined basis, the Panel has added criteria limiting the total production of Biomethane for all 

projects to 250,000 GJ per year during the test period and set a maximum commodity price at 

$15.28 per GJ.  In addition, the Panel has approved the cost allocation methodology as proposed by 

Terasen as reasonable and in the public interest.  Finally, the Commission Panel directed the post 

implementation review and reporting period be reduced from the requested five years to two 

years.  

 

In this Decision, the Commission Panel has allowed Terasen Gas to move forward with a 

Biomethane Program on a test basis for a two year period.  In introducing limitations on scope and 

a term for the test, the Panel believes that Terasen will learn valuable lessons which can be applied 

to the development of a model which will sustain the Program over the long term.  It believes that 

taking this approach is prudent and in the best interests of TGI ratepayers. 

 

4   

 

2.0  INTRODUCTION 

 

This Application is submitted by Terasen Gas Inc. (Terasen, Terasen Gas, TGI or the Company) for 

approval to introduce an end‐to‐end business model for the acquisition of a Biomethane gas supply 

and the sale of this renewable energy to its customers. 

 

2.1  Application 

 

TGI and its affiliated companies sell and deliver natural gas to residential, commercial and industrial 

customers throughout British Columbia (BC).  They provide service to 940,000 customers and which 

represents over 95 percent of gas users in the Province.  Their operations are subject to regulation 

by the British Columbia Utilities Commission (Commission, BCUC). 

 

By Application dated June 8, 2010 Terasen applied for approval of a Biomethane Service Offering 

and Supporting Business Model, for approval of a Salmon Arm Biomethane Project and for one in 

the Abbotsford area (the Application).  Terasen Gas proposes to develop an initial supply of 

Biomethane from two projects: 

 

• a farm in Abbotsford, BC where a project partner will collect agricultural waste and use anaerobic digestion and upgrading technology to develop Biomethane which will be delivered to Terasen for injection into the distribution system (the Catalyst Project); and 

• a landfill project in Salmon Arm, BC where raw biogas will be produced in a landfill by a project partner and then upgraded to pipeline quality Biomethane by Terasen (the CSRD Project, or the Salmon Arm Project). 

 

Biogas is a gas substantially composed of methane that is produced by the breakdown of organic 

matter (biomass) in the absence of oxygen.  Biomethane is renewable energy and refers to biogas 

that has been upgraded to primarily methane by the removal of other constituents, so that it is 

safely interchangeable with natural gas in the distribution and transmission system. (Exhibit B‐1, 

p. 7) 

 

5   

 

The end‐to‐end business model for a Biomethane program proposed by Terasen in the Application 

has three parts encompassing models for the acquisition of a supply of biogas, the sale of 

Biomethane to its customers and the allocation and recovery of costs. 

 

Terasen states that market research suggests there is a strong desire on the part of customers to 

purchase renewable clean energy.  It further states that the data presented in the Application 

supports the position that demand for the product will exceed the capability of the initial projects 

to supply it.  This has resulted in Terasen proposing a phased approach which it states is both 

flexible and scalable allowing supply and demand to be balanced. (Exhibit B‐1, pp. 1‐3)  Worthy of 

note is a letter from the Assistant Deputy Minister of Energy, Mines and Petroleum Resources, 

expressing the government’s support for the Biomethane Service Offering.  In it he states that: 

 

“[t]he objectives of this proposal align with the policy actions of the BC Energy Plan, the BC Bioenergy Strategy and the British Columbia energy objectives of the Clean Energy Act (the Act), particularly the objectives in section 2(g) “to reduce greenhouse gas emissions” and section 2(j) “to reduce waste by encouraging the use of waste heat, biogas and biomass.” (Exhibit E‐1) 

 

2.2  Orders Sought 

 

TGI seeks Commission approval of a number of orders pursuant to the Utilities Commission Act 

R.S.B.C. 1996 c. 473 (the Act, UCA).  Listed in their entirety in Appendix A to this Decision, they 

include the approval of rate related orders, cost recovery related orders for both voluntary 

participant customers and all non‐bypass customers, supply project related orders and post 

implementation review orders. 

 

6   

 

2.3  Regulatory Process 

 

The Regulatory Process is described in detail in Appendix B.  Nine organizations registered as 

Interveners for the Application.  They are as follows: 

 

• Catalyst Power Inc. 

• BC ARD Corporation 

• BC Bioenergy Network 

• British Columbia Power and Hydro Authority (BC Hydro) 

• British Columbia Old Age Pensioners’ Organization et al (BCOAPO) 

• Elemental Energy Inc. 

• Commercial Energy Consumers Association of British Columbia (CEC) 

• BC Sustainable Energy Association (BCSEA) 

• BP Canada Energy Company 

 

Among these the BCOAPO, CEC, BC Hydro and BCSEA actively participated in some or all of the 

Processes. 

 

2.4  Context and Key Issues 

 

TGI is seeking approval for the introduction of an end‐to‐end business model encompassing the 

acquisition of a supply of Biomethane and the sale of this renewable energy to its customers.  As a 

starting point, Terasen has proposed that the supply of Biomethane be developed from two initial 

projects which were broadly described earlier in Section 2.1.  These projects represent two 

different approaches to securing raw biogas and then upgrading it to allow it to be injected into the 

natural gas pipeline system.  The first of these projects, the Catalyst Project, represents the 

traditional supply side management process for Terasen where the product has been purchased in 

its final form.  The second, the CSRD Project, represents a significant departure from this as Terasen 

7   

 

moves up the supply chain to provide the biogas upgrading service role.  The Catalyst Project and 

the CSRD Project will be collectively referred to as “the Projects”, in this Decision.  The Biomethane 

Service Offering including all elements of the business model will be referred to as the Biomethane 

Program or Program. 

 

A significant part of the Application is centered upon an examination and justification of the 

Projects and the resale of Biomethane from them.  However, the Application goes much further in 

that it proposes a model which the Company will use as a basis for development of a broader 

Biomethane product offering in the future.  Included in the model are the following: 

 

• A set of future project selection criteria which, when satisfied, will allow for a streamlined regulatory process. 

• A departure from the traditional supply side management processes utilized by Terasen. 

• A set of principles governing the allocation of costs and their recovery from ratepayers. 

 

It is further proposed that this model be reviewed through a post implementation report and 

workshop, which is contemplated to occur five years following the launch of the initial project. 

 

Given the potential size and scope of the initiative being proposed by Terasen, the Commission 

Panel needs to consider issues far beyond those needed to reach a determination on the Projects.  

In reaching its Decision, the Panel also needs to consider the impact of the alternative positions it 

may take on the issues arising and assess the suitability of the model and whether changes are 

necessary to protect the public interest in the period which lies ahead.  In what follows, the Panel 

will provide an outline of the Program before examining each of the key issues it believes to be 

important in reaching a determination as to whether the Application is to be accepted and whether 

changes to the proposed model are required.  Accordingly, following a description of the key 

elements of the Program, the Panel will initially examine the following issues: 

 

• How the Program aligns with British Columbia energy objectives and Policy; 

8   

 

• The adequacy of supply of biogas; 

• The level of customer demand for the Projects and others like them. 

 

The Panel will then examine some of the broader issues related to the model including: 

 

• Terasen’s proposed role in the biogas upgrading process; 

• The criteria for future projects; 

• The risk of stranded assets and other project risks; 

• Principles for cost allocation and recovery; and 

• Post implementation review and reporting. 

 

9   

 

3.0  PROJECT DESCRIPTION 

 

3.1  Overview 

 

The Clean Energy Act, S.B.C. 2010 c. 22 (CEA) received Royal Assent on June 3, 2010.  In Terasen’s 

view it has given a renewed and heightened importance to its role in developing renewable 

resources, reducing GHG emissions, reducing waste by using biogas and biomass as well as 

promoting energy efficiency.  The Commission Panel considers the following British Columbia 

energy objectives included in section 2 of the CEA are germane to the Application: 

 

(d)  to use and foster the development in British Columbia of innovative technologies that support energy conservation and efficiency and the use of clean or renewable resources; 

 (g)  to reduce BC greenhouse gas emissions 

(i)  by 2010 and for each subsequent calendar year to at least 6 percent less than the level of those emissions in 2007….; 

(h)  to encourage the switching from one kind of energy source or use to another that decreases greenhouse gas emissions in British Columbia; 

(j)  to reduce waste by encouraging the use of waste heat, biogas and biomass. 

 

In addition, federal, provincial, regional, and municipal governments are increasingly focused on 

climate change and pollution, adopting policies in favour of renewable forms of energy as a key 

part of the solution to environmental challenges.  The Provincial Government has also explicitly 

stated its support for biogas project development in the 2008 Bioenergy Strategy document. 

(Exhibit B‐1, Appendix B‐7, p. 8)  Moreover, Terasen notes that many of the logical partners in the 

development of Biomethane projects are municipalities or regional districts because landfills and 

sewage treatment facilities owned and/or operated by them are often excellent sources of raw 

biogas.  Terasen Gas submits the capture of biogas, and its upgrading to pipeline quality 

Biomethane, can help local governments generate revenue and meet the municipal GHG emission 

targets by way of the beneficial use of waste methane rather than flaring it. (Exhibit B‐1, p. 27) 

10   

 

 

The end‐to‐end business model proposed by the Company is made up of the three components 

listed below and described subsequently in more detail: 

 

• The Biomethane supply model ‐ which addresses the logistics of acquiring a reliable supply of biogas, safely and reliably upgrading it to Biomethane and injecting it into  TGI’s distribution system; 

• The model for offering Biomethane product to customers ‐ which consists primarily of the formulation of a rate offering to allow the notional sale of Biomethane to those Terasen customers who are willing to pay a premium price for this product; and 

• The cost allocation and recovery model ‐ which addresses the related cost recovery of this product offering from various customer groups. (Exhibit B‐1, p. 2) 

 

3.1.1  Supply of Biomethane 

 

Terasen states that its partners will be responsible for the collection of raw material and the 

facilities required for production of biogas.  However, for the process to upgrade biogas into 

Biomethane TGI has introduced two models.  In the first model, Terasen will negotiate a 

contractual relationship to purchase upgraded Biomethane from project partners, providing these 

independent operators can meet Terasen’s financial and technical standards.  In the second, 

Terasen’s preferred model, it will own and operate the upgrading facilities “to ensure reliability, 

safety and the continuous flow of product from the Biomethane supply project to the customer.”  

In all cases, Terasen proposes to retain control of the interconnection facilities to control the 

injection of Biomethane into the distribution system. (Exhibit B‐1, p. 2) 

 

3.1.2  Sale of Biomethane to Customers 

 

Based on its market research, Terasen believes its customers have a “significant interest in 

purchasing Biomethane from Terasen Gas as an environmentally superior option to conventional 

natural gas.” 

 

11   

 

Terasen proposes to take a phased approach to launch this program in recognition of the limited 

availability of Biomethane at this time.  The first phase of the Biomethane product offering (the 

Offering) will involve making a blended Biomethane product available to residential customers 

starting with a blend of 10 percent Biomethane and 90 percent conventional natural gas.  Phase 

two will involve launching the same 10 percent blend for small and large commercial customers on 

January 1, 2012.  Terasen also plans to sell Biomethane to on‐system transport customers and off‐

system wholesale customers.  Eventually, Terasen’s goal is to expand its offerings as the Program 

matures and new supply sources are developed. (Exhibit B‐1, p. 3) 

 

3.1.3  Cost Allocation and Recovery 

 

Terasen Gas states that the Offering will be a premium product and accordingly customers 

choosing to participate will have to pay a higher price to reflect the actual higher cost of the 

Biomethane.  Terasen proposes the following cost allocation and pricing principles for its new end‐

to‐end business model: 

 

• Customers should bear the cost of the energy they choose to consume.  Therefore, Terasen intends to aggregate the biogas acquisition and upgrading costs and proposes to recover them as a commodity cost for Biomethane from those customers who opt for the Program.  In those cases where Terasen buys the upgraded Biomethane from an independent operator that cost would be included as a commodity cost. 

• Costs associated with making the Biomethane service offering available to all customers should be borne by all non‐bypass customers.  Terasen envisages these costs to include quality monitoring, IT upgrades, program management and customer education with some marketing involved. 

(Exhibit B‐1, p. 3) 

12   

 

The Biomethane Service Offering Model is depicted for the reader’s benefit in the diagram below.1 

 

 

 

                                                       1 Diagram was created from information in Exhibit B‐1 

13   

 

3.1.4  Notional Delivery 

 

Terasen Gas proposes what it describes as a “notional delivery” of Biomethane.  The Company 

explains that “notional delivery” is a concept used in the trading of commodities, where delivery is 

notional rather than real.  Terasen is of the view that the interchangeability of Biomethane with 

conventional natural gas allows for this concept to be used in the Application, as the end user will 

not be able to differentiate between the products.  Terasen draws the analogy between the 

residential Customer Choice Program where gas marketers are responsible for delivery of natural 

gas to the system, but their particular customers may not actually receive those molecules of 

natural gas, as individual molecules are not tracked. (Exhibit B‐1, p. 15) 

 

The Commission Panel has some concern about the applicability of notional delivery to the 

Offering.  The Application is premised on the fact that Biomethane is a different product than 

natural gas with different carbon properties.  Terasen is asking customers to agree to pay a 

premium for a different and arguably superior product which the customer may or may not 

receive.  It is important that Terasen be able to communicate this distinction as part of its 

marketing program so there is no misunderstanding on the part of the consumer. 

 3.2  Outline of Projects 

 

TGI has included two supply projects in the Application for the Commission’s consideration.  They 

represent concrete examples of the two supply models described earlier.  The Projects are 

described in more detail below. 

 

3.2.1  Catalyst Project 

 

The first project brought forward by Terasen is an agricultural waste to Biomethane project located 

in Abbotsford, BC.  The project partner is Catalyst Power Incorporated (Catalyst).  In this project, 

which represents the first supply model, Terasen is purchasing upgraded Biomethane with a 

relatively small capital investment required only in distribution main and interconnection facilities.  

14   

 

Highlights of this Project and key provisions of the supply agreement are summarized as follows: 

 

Highlights of the Project: 

 • Catalyst investment in the digestion, gas collection and upgrade technology: 

$ 5 Million; and 

• Terasen investment as shown below: 

 

Table 3‐1: Capital Cost Summary 

   Source: Exhibit B‐1, p. 100  The injected Biomethane is forecast to displace the quantity of natural gas required to serve more 

than 875 households annually, based on Lower Mainland typical household demand of 95 GJ per 

year, and thus reduce GHG emissions by at least 4,000 tonnes annually based on the minimum 

projected supply.  Assuming a 10 percent blend, this converts to 8,750 customers.  The range of 

expected annual GHG emissions associated with the Catalyst Agreement is shown below. 

 

Table 3-2: Annual CO2e reduction 

 Source: Exhibit B‐1, p. 101 

15   

 

Key provisions of the Catalyst supply agreement: 

 

• Quantity: Minimum annual delivery of 84,000 GJ; 

• Term: 10 years; 

• Price: As negotiated with Catalyst, falls within the range of expectations; 

• Quality: Terasen Gas quality specifications; and 

• Other: The non‐performance definition and excuse from non‐performance for maintenance in the agreement strike a balance between committing both Catalyst and Terasen to deliver and accept pipeline quality Biomethane and allow both companies sufficient flexibility to solve minor operational issues which may arise. 

 

A number of measures have been incorporated into both the agreement and the facilities 

themselves to mitigate a range of potential risks.  These risks are further addressed in Sections 4.7 

and 4.9. 

 

Terasen states that Catalyst has conducted significant public consultation in its efforts to get the 

necessary agriculture and land use approvals in place to allow the construction and operation of an 

anaerobic digester and biogas upgrading system on the site. (Exhibit B‐1, pp. 94‐105) 

 

3.2.2  CSRD Project 

 

This biogas project will be located at the regional landfill within the city limits of Salmon Arm, BC. 

The project partner is the Columbia Shuswap Regional District.  Terasen states that in this case it 

will be purchasing raw biogas and investing in upgrading equipment along with the distribution 

main and interconnection facilities, which include gas quality monitoring, pressure regulation and 

odorizing.  Highlights of the proposed project and key provisions of the supply agreement are 

summarized as follows: 

16   

 

Highlights of the Project: 

 

• CSRD investment in the landfill gas capture, collection and flare system: $ 4.8 Million 

• Terasen Gas investment in upgrading and interconnection facilities as shown below. 

 

Table 3‐3: Capital Cost Summary 

   Source:  Exhibit B‐1, p. 89  It should also be noted that in this Project funding from the provincial government’s Innovative 

Clean Energy (ICE) fund and the BC Bioenergy Network (BCBN) of some $500,000 will reduce the 

Terasen capital expenditure to $ 1.8 Million. 

The injected Biomethane will displace the quantity of natural gas required to serve more than 300 

households annually, based on North Okanagan typical annual household demand of 100 GJ, and 

thus reduce GHGs by approximately 1,500 tonnes per annum as shown in the Table below. 

 

Table 3-4: Annual CO2e reduction 

 Source: Exhibit B‐1, p. 91 

 

17   

 

Key provisions of the supply agreement: 

• Quantity: 30,000 GJ per annum; 

• Term: 15 years, with a yearly automatic renewal after the first 15 years; 

• Price: As negotiated with CSRD, falls within the range proposed as an economic test for future projects; 

• Quality: a raw gas quality specification; and 

• Other: CSRD is required to make commercially reasonable efforts to maintain equipment and supply the best quality gas possible. 

 

Again, a number of measures have been incorporated into both the agreement and the facilities to 

mitigate a potential supply risk, operational risks and risk of stranded assets.  These are addressed 

in further detail in Sections 4.7 and 4.9. 

Finally, Terasen states the CSRD has indicated that there are no outstanding claims or concerns in 

the planned project area. (Exhibit B‐1, pp. 83‐94) 

 

3.3  Criteria for Future Projects 

 

One of the numerous approvals Terasen is seeking is an order that future supply contracts for the 

purchase of biogas or Biomethane which meet the criteria described in the Application meet the 

filing requirements in sections 71(1)(a) and 71(1)(b) of the UCA.  It states that an early adoption of 

this framework will facilitate growth of the supply industry “by establishing clear and achievable 

parameters for our potential supply partners.”  This Section addresses the criteria which have been 

proposed. 

 

3.3.1  Guiding Principles for Development of Biomethane Supply 

 

TGI intends to apply the following guiding principles to the development of future Biomethane 

supply: 

 

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a) Project Economics: A cost of service (COS) model will be used to evaluate the attractiveness of projects, with the estimated capital and operating costs borne by Terasen and the estimated production costs of Biomethane as key inputs.  Each project will be evaluated against a COS threshold that will represent the maximum cost of Biomethane delivered to the Terasen system. 

b) Gas‐Processing Technology: Terasen will use proven technology to ensure reliability and safety with technology being evaluated on the basis of cost, output gas purity and gas recovery. 

c) Working with biogas Project Proponents: Terasen will work with project proponents to mitigate project risks. 

d) Cost Recovery: Terasen will capture all capital and operating costs associated with the supply projects, including regulated return on capital investments in an aggregated Biomethane cost of gas calculation that will be recovered from customers participating in the Biomethane Program. 

e) Gas Quality: Biomethane that is injected into the system must meet minimum Terasen gas quality specifications. 

f) Injection Location: Terasen will evaluate all projects on a case‐by‐case basis to ensure that the injection location has sufficient local demand to utilize Biomethane. 

g) Contract Length: Long term contracts, preferably ten years or more to allow for a stable supply and a reasonable capital depreciation period. 

h) Project Design for Mobility: Terasen will engineer facilities in order to minimize the risk of stranded assets. 

i) Investment Arrangement: Terasen’s preferred model is to invest in upgrading equipment to retain maximum control of gas quality and safety.  It will invest in sufficient equipment to ensure that quality and safety specifications are met and that there is a means of stopping Biomethane supply on short notice.  In all cases, Terasen will reserve the right to refuse gas if customer safety or asset integrity is at stake. 

(Exhibit B‐1, pp. 74‐76) 

 

3.3.2  Maximum Biomethane Cost 

 

Terasen proposes to apply a maximum cost as a screen for the supply of Biomethane.  This will 

ensure it has adequate flexibility in developing new sources of supply while protecting Biomethane 

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customers from undue rate increases.  Further, Terasen notes BC Hydro’s entrance into the biogas 

market by way of the Call for Community Biomass Energy projects.  TGI states that “a given 

maximum rate for Biomethane helps create a better understanding for potential biogas producers 

of the relative economic benefits of using their biogas for upgrading to Biomethane vs. combustion 

to create electricity to sell to BC Hydro.” (Exhibit B‐1, p. 76) 

 

TGI approach to determining the maximum Biomethane cost is addressed below. 

 

3.3.2.1  BC Hydro’s RIB Tier 2 Rate  

 

Terasen Gas states that because there are no available external benchmarks specific to Biomethane 

the price of new British Columbia based electricity supply, a competing clean energy source, 

provides an appropriate initial reference point or proxy for Biomethane pricing until the market is 

better developed.  By Order G‐124‐08 the Commission directed BC Hydro to establish the 

Residential Inclining Block (RIB) Tier 2 rate at BC Hydro’s cost of new supply at the plant gate, 

grossed up for losses.  Terasen states that because this rate is linked to the cost of new clean 

electricity supply, it is an appropriate price cap for Biomethane after adjusting for thermal 

efficiency and allowances for its distribution costs.  Accordingly, Terasen proposes that, until such 

time as an alternative market‐based mechanism becomes known, it will seek to develop 

Biomethane projects at a maximum unit cost based on the following calculation: 

 

Table 3‐5: Proposed maximum Unit Cost 

   Source:  Exhibit B‐1, p. 77 

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Should this formula be accepted, Terasen plans to use a maximum unit cost of $15.280 per GJ as 

“the default financial litmus test for the time being.”  In Terasen’s rate structure this price would be 

comparable to the commodity price for conventional natural gas.  Finally, Terasen proposes to 

adjust the maximum forecast rate to reflect the unit cost changes in the various components 

included in the calculation. (Exhibit B‐1, pp. 76‐77) 

 

3.3.2.2  Alternatives Considered for Economic Test 

 

In developing its proposed economic test, TGI considered and rejected five alternative 

methodologies as follows: 

 

• BC Hydro Clean Energy Rate: 

• $0.13 per kWh (Clean Energy call) which, using the above conversion formula, translates into a comparative price for Biomethane of $25.83 per GJ.  Terasen notes that while Biomethane costs will be streamed directly to Terasen customers, the higher clean electricity costs will be mixed into a large pool of lower‐cost electricity to BC Hydro customers to form the RIB Tier 2 rate.  As a result, the Clean Energy Rate would be too expensive and not comparable to the blended electricity rates actually charged to customers.  Accordingly, Terasen states that “it must protect its competitive standing” and that due to its transparency, the RIB Tier 2 rate is the superior solution. 

• $150 per MWh (Bioenergy Phase 2 Call RFP) which, using the same multiplier of 277.778 kWh per GJ is equivalent to BC Hydro offering $41.667 per GJ of electricity made from raw biogas.  Applying again the above conversion formula results in a competitive alternative proxy of $30.83 per GJ of Biomethane delivered to a Terasen customer.  For the same reasons stated above, Terasen rejected this alternative.  However, Terasen states it “may need to review this rationale as the market for Biomethane develops so as to remain competitive in sourcing biogas and Biomethane in British Columbia.” 

• South East False Creek District Energy System (SEFCDES): This option was not pursued because it might be less relevant as the SEFCDES only serves a small, high‐end showcase development neighbourhood in Vancouver.  Further, Terasen states that the rate structure is not truly comparable to those of large scale utilities because District Energy System rates could include more services and product offerings than the typical price for services provided by electricity or natural gas utilities. 

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• Dockside Green Energy (DGE): Terasen states that the DGE rate structure, serving one high‐end neighbourhood in Victoria, encompasses a mix of a fixed amount for floor space and a variable amount for energy which is first charged to strata corporations, which then allocate the costs to individual strata unit owners.  This in turn makes a direct translation between energy consumption and cost more complex.  Accordingly, Terasen also rejected this option. 

• Gas Commodity Rate Cap (a multiple of the existing natural gas commodity rate to set a fixed percentage premium): Terasen also eliminated this methodology because there is no apparent relationship between factors driving natural gas market prices and the cost of producing Biomethane.  Further, Terasen notes as GHG neutral Biomethane is a fundamentally different product than conventional natural gas, therefore “imposing a pricing relationship between the two would be difficult to justify.” 

• No Cap: Terasen states that because the Biomethane service offering is fully optional for customers who may leave it at any time, setting no price cap “would be consistent with market‐based economic principles of determining the price and therefore the availability of a product as being whatever the market may bear.”  Ultimately, however, Terasen decided that, given the lack of customer experience with this type of offering, and given that this is only the first phase of a multi‐phase product roll‐out, there should be a price ceiling for the product to build up both the level of customer comfort and education until the market is more mature. 

(Exhibit B‐1, pp. 76‐80) 

 

3.3.3  Regulatory Review of New Supply Projects and Contracts 

 

For future biogas or Biomethane supply contracts TGI proposes a streamlined process in which it 

will only file the supply contract for acceptance under section 71 of the UCA, with no additional 

information.  Terasen would choose not to apply for approval of expenditures pursuant to section 

44.2 of the UCA.  Terasen proposes the following criteria for this streamlined process: 

 

1. The projected supply meets the proposed economic test with the maximum price for delivered Biomethane re‐calculated from time to time based on updates to the BC Hydro RIB Tier 2 rate; 

2. The supply contract is at least ten years in length; 

3. Terasen has, by agreement, retained final control over the injection location; 

4. Terasen is satisfied that the upgrade technology is sufficiently proven; 

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5. Terasen has, by agreement, reserved the right to refuse gas if customer safety or asset integrity is at stake; and 

6. The partner is a municipality, regional district or other public authority, or is a private party with a track record in dealings with Terasen or that posts security to reduce the risk of stranding. 

(Exhibit B‐1, p. 80) 

 

3.3.4  Post Implementation Review 

 

Terasen states that in requesting approval for streamlining the development of future Supply and 

Tariff Offerings, it acknowledges a requirement for a thorough review of the Biomethane Program’s 

success in the future.  Terasen proposes that the review be conducted through a Post 

Implementation report and workshop, both occurring five years after the launch date of the 

residential Biomethane Program. 

 

Terasen further states that this timeline should allow it adequate time to validate its research into 

residential and commercial markets, and to develop additional supply projects to help this industry 

to mature.  In the meantime, Terasen proposes to report on the developments of this new program 

through its revenue requirement applications related to the end‐to‐end business model and report 

the Biomethane gas cost as a part of the quarterly gas cost reporting established with the 

Commission. (Exhibit B‐1, p. 81) 

 

3.4  Pricing Methodology   

Terasen notes that the Biomethane gas which is sold to customers is expected to be more 

expensive than conventional natural gas for the foreseeable future.  As outlined in Section 3.1.3 of 

this Decision, Terasen has, based upon a set of principles, developed a methodology for allocating 

certain costs to all TGI customers and others specifically to Biomethane Program customers who 

have voluntarily signed up for the offering. 

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For all non‐bypass customers Terasen is proposing setting up non‐rate base deferral accounts to 

capture costs incurred which are applicable to this group for the period prior to January 1, 2012 

(encompassing the remainder of the 2010‐2011 revenue requirements period).  Following this it 

proposes to recover the costs from the non‐bypass customer group through their amortization 

over the ensuing three year period.  Based on projections, the impact on non‐bypass customers 

from 2012 to 2019 varies from $0.004 to $0.006 per GJ with a levelized rate impact of $0.004 per 

GJ.  Terasen calculates the incremental revenue requirements over this period to be $4,084,100 

resulting in an annual incremental cost of 38 cents for a customer using 95 GJ per year. (Exhibit B‐1, 

pp. 107‐111) 

 

TGI states that the Biomethane costs will be recovered from the voluntary group of Biomethane 

Program customers through a Biomethane Energy Recovery Charge (BERC).  To capture any 

variance between forecasted BERC and actual costs, TGI seeks Commission approval for a further 

deferral account.  The Company has calculated the initial BERC to be $9.904 GJ and has requested 

this amount be effective October 1, 2010.  This will apply to 10 percent of the total gas used (the 

Biomethane portion) and will be adjusted annually based on deferral account balances.  Customers 

choosing this option will do so under Rate Schedule 1B which has been applied for in this 

Application. (Exhibit B‐1, pp. 112 ‐118) 

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4.0  KEY ISSUES AND DETERMINATIONS 

 

4.1  Introduction 

 

Having laid out the key attributes and a framework for the Program in Section 3.0, we will now 

examine the issues related to the Application.  We will begin by examining the key elements of the 

Application in terms of its alignment with British Columbia’s energy objectives and Provincial 

Government policy and continue with a discussion of the adequacy of supply and related demand 

issues.  This will demonstrate that in the Panel’s view there is justification for proceeding, at a 

minimum, with the Projects.  Additionally, our examination will provide a basis upon which to 

discuss issues related to how to most effectively roll out the Program and protect the public 

interest.  These include the criteria for future projects, the risk of stranded assets, principles for 

cost recovery, other project risks and post implementation review and reporting. 

 

4.2  Alignment with British Columbia’s Energy Objectives and Provincial Government Policy 

 

The Panel finds that the Application is consistent with government policy as outlined in the CEA and 

elsewhere. 

 

As noted earlier, section 2 of the CEA, sets out British Columbia’s energy objectives.  Relevant 

objectives include: 

 

(d)  to use and foster the development in British Columbia of innovative technologies that support energy conservation and efficiency and the use of clean or renewable resources; 

 (g)  to reduce BC greenhouse gas emissions;  

(i) by 2012 and for each subsequent calendar year to at least 6 percent less than the level of those emissions in 2007; 

 (h)  to encourage the switching from one kind of energy source or use to another that 

decreases greenhouse gas emissions in British Columbia; 

25   

 

(j)  to reduce waste by encouraging the use of waste heat, biogas and biomass.  

“Greenhouse gas” is a defined term which means: “any or all of carbon dioxide, methane, nitrous 

oxide, hydrofluorocarbons, perfluorcarbons, sulphur hexafluoride and any other substance 

prescribed by regulation.” (Greenhouse Gas Reduction Targets Act S.B.C. 2007, c. 42 s. 1)  

However, Terasen’s evidence is that Biomethane is greenhouse gas neutral with zero carbon 

intensity, making it, in a pure form, greener than the electricity which is consumed in the province. 

(Exhibit B‐10, BCUC IR 2.4.1) 

 

The Carbon Tax Act, S.B.C. 2008, c. 40 (CTA) is also relevant.  Schedule 1 to the CTA contains a Table 

which sets out the rate of tax applicable to various types of fuel, including natural gas.  However, by 

section 1 of the CTA, neither methanol produced from biomass nor methane produced by waste in 

a landfill is considered to be a “fuel” for the purposes of the Table and is therefore arguably not 

subject to a carbon tax. 

 

TGI states that it has received confirmation from the British Columbia Ministry of Finance that 

Biomethane itself is exempt from the carbon tax but that there is some uncertainty surrounding 

the tax treatment of Biomethane blended with natural gas.  Terasen is seeking to obtain clarity 

from the Ministry on this issue. (Exhibit B‐12, BCSEA IR 2.21.1) 

 

The publication of the British Columbia government entitled “BC Bioenergy Strategy – Growing our 

Natural Energy Advantage” provides insight into the process, government policy and the resultant 

carbon footprint.  Essentially, as noted above, bioenergy is energy which is derived from organic 

biomass; biomass being waste material which is often produced from normal daily activities and 

includes renewable sources such as manure, municipal waste, sewage and wood debris.  When this 

biomass is converted to energy, it is considered to be a clean source of energy.  This is because gas 

which would simply be released into the atmosphere naturally is used to produce energy, in place 

of non‐renewable sources, thus reducing the greenhouse gases which would otherwise be released 

into the atmosphere. 

 

26   

 

The publication states: “[b]ioenergy is absolutely critical to achieving B.C.’s climate goals and 

economic objectives” and the government indicated that its bioenergy strategy would create new 

economic opportunities and “establish British Columbia as the hub of a global supply network of 

bioenergy resources, technologies and services.” 

 

The Application includes letters of support, including a letter dated April 5, 2010 from the BC 

Sustainable Energy Association which states: “[a]ppropriately carried out and regulated, the use of 

renewable biogas would cause net reductions in greenhouse gas emissions in BC relative to 

business as usual.”  As noted previously, the Ministry of Energy, Mines and Petroleum Resources 

also supports the Biomethane Program as being in alignment with Provincial policy actions and 

objectives. 

 

Section 44.2 (5) of the UCA, requires the Commission to consider a number of matters prior to 

accepting an expenditure schedule filed by a public utility under section 44.2.  Relevant to this 

application are: the applicable of British Columbia’s energy objectives, Terasen’s most recent long 

term resource plan filed under section 44.1, if any, and the interests of persons in British Columbia 

who receive or may receive service from the public utility. 

 

Applicable British Columbia Energy Objectives 

 

The applicable objectives were set out in detail in Sections 3.1 and 4.2 above. 

 

The Commission Panel is of the view that the process of converting biomass to biogas to usable 

Biomethane uses innovative technology, as evidenced by the government’s commitment to its 

bioenergy strategy.  Biomethane is also considered to be clean and is a renewable resource.  

Further, the use of Biomethane in place of natural gas will reduce greenhouse gas emissions, as 

explained above, and the Biomethane Program entails the use of biomass and biogas. 

 

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The Commission Panel also considers the carbon tax to be another clear expression of government 

policy aimed at reducing carbon and the fact that Biomethane is not considered subject to the tax 

(albeit in a pure form) provides additional support for the Program. 

 

The Commission Panel therefore finds that the Application is consistent with British Columbia’s 

energy objectives and Provincial Government energy policy. 

 

  TGI’s Most Recent Long Term Resource Plan 

 

Terasen filed a long term resource plan under section 44.1 on June 27, 2008.  The long term 

resource plan included five year capital plans and statements of facilities expansion, although no 

specific approval was requested.  The only issues of any contention were carved off and made the 

subject of a separate proceeding, being Terasen’s Energy Efficiency and Conservation Application.  

The long term resource plan was accepted in its modified form by Commission Order G‐194‐08 

dated December 15, 2008. 

 

The Commission Panel sees nothing in Terasen’s long term resource plan which is inconsistent with 

the Biomethane Program. 

 

  The Interests of Persons in British Columbia who  Receive or May Receive Service from Terasen Gas 

 

The Commission Panel considers that allowing customers to opt to select the more expensive 

Biomethane product is in the interests of Terasen’s customers at this time, as it will provide 

maximum customer choice.  In the future, it may be unnecessary to allow for this choice, as the 

carbon tax increases and prices of natural gas and Biomethane adjust in accordance with market 

forces.  A portion of the expenditure will be recovered from all non‐bypass customers and, 

considering the relatively small cost of making the Program available, the Commission believes that 

it is in the interest of Terasen customers whether or not they choose to participate. 

 

28   

 

                                                      

4.3  Biogas Supply 

 

To evaluate the merits of the Application, the Commission must determine if there is enough 

evidence in this proceeding to forecast that the potential Biomethane supply in TGI’s service area 

can support the planned offering.  Within the Application, Terasen performs an evaluation and 

concludes that the potential Biomethane supply is sufficient. (Exhibit B‐1, p. 66) 

 

In order to estimate the future potential of Biomethane, TGI undertook a four step process that 

included:  i) quantifying the total amount of bioenergy in BC; ii) identifying and excluding bioenergy 

resources not suitable for Biomethane; iii) estimating the range of supply, and iv) developing a 

short term supply estimate.  This process involved collecting data from sources who have studied 

BC’s bioenergy, making reasonable estimates of future events, and engaging potential partners 

who have an interest in Biomethane production. (Exhibit B‐1, pp. 62‐65) 

 

Supported by this preliminary estimation, TGI believes there is sufficient raw biogas to produce 

enough Biomethane to support its planned offering and estimates Biomethane supply in 10 years 

could be in the range of 2.24 to 5.6 Petajoules ( PJ).2  Terasen also noted that there is strong 

interest from various potential partners to work with it to develop Biomethane projects within its 

service territory. (Exhibit B‐1, p. 66, as amended by Exhibit B‐1‐1) 

 

However, Terasen notes that the sources of the energy and estimated supply of Biomethane are 

not well established.  It is Terasen Gas’ position that the first four years of the estimate are more 

accurate than the long‐term forecast, but both long‐term and short‐term estimates are subject to 

some uncertainty. (Exhibit B‐1, p. 65) 

 

A graphic demonstration of Terasen’s estimated availability of Biomethane until 2020 has been 

included below: 

 

 2 One Petajoule is 106 Gigajoules and Terasen’s total forecast energy consumption for 2011 was 161.8 PJ in the 2010‐2011 Revenue Requirements Application made to the Commission on June 15, 2009. 

29   

 

Figure 4‐1: Terasen Gas Forecast for Annual Biomethane Supply (PJ) 

 

Source:  Exhibit B‐1, p. 65 as amended by Exhibit B‐1‐1 

TGI’s projection of Biomethane supply indicates that initial supplies will be much lower than the 

potential supplies reached in 2020.  It forecasts Biomethane supplies in 2010 to be 0.05 PJ and to 

be in the range of 0.18‐0.23 PJ in 2011. (Exhibit B‐1, p. 65 as amended by Exhibit B‐1‐1)  Given that 

Biomethane supplies are not yet well established (Exhibit B‐1, p. 65), the Company has proposed 

risk‐management techniques to address potential Biomethane supply shortfalls.  Terasen suggests 

that these techniques, which include limiting program enrollment and reserving the right to 

purchase carbon offset credits or remove customers from the program provide the Company with 

an additional safety net if needed. (Terasen Final Submission, p. 44) 

 

No Intervener raised concerns regarding matters of Terasen’s Biomethane supply. 

 

30   

 

Commission Determination 

 

The Commission Panel believes that Terasen has reasonably identified potential sources of biogas 

in its service area and evaluated the likelihood of Biomethane production.  However, this is a new 

type of venture and there is little independent evidence to corroborate these estimates.  The 

Commission Panel is satisfied that Terasen understands this difficulty and related impacts, and has 

made reasonable attempts to formulate an estimate given these constraints.  The Commission 

Panel accepts TGI’s estimate of its potential Biomethane supply and finds this supply to be 

sufficient to justify moving forward with the Biomethane Program but the Panel also 

acknowledges the limited data available to support this estimate. 

 

As noted, the Commission Panel accepts that there is a risk that the Biomethane supply estimates 

may be inaccurate.  The Commission Panel further notes that TGI has attempted to mitigate this 

risk by proposing policies that allow it to purchase carbon offset credits or limit service in certain 

circumstances.   The Commission Panel finds that TGI has proposed reasonable techniques to 

address the risk of Biomethane shortfalls if short‐term supply estimates are overstated.  Further, 

the Commission Panel approves TGI’s proposal to purchase carbon offsets and to recover costs 

through the Biomethane Variance Account in the event of under‐supply of Biomethane, at a per 

gigajoule unit price not to exceed the difference between the Biomethane Energy Recovery 

Charge and the Commodity Cost Recovery Charge in effect at that time. 

 

4.4  Product Demand 

 

A fundamental consideration is determining whether there is sufficient demand from the BC 

consumer to justify the implementation of a comprehensive Biomethane gas offering program 

within the province.  Terasen, as a means of providing background in its Application, provides an 

overview of the types of green business models or programs deployed in North America and their 

participation rates. (Exhibit B‐1, pp. 28‐29)  In addition, Terasen commissioned TNS Canadian Facts 

(TNS) to conduct primary research as a means of evaluating and validating potential BC residential 

and commercial markets for a biogas program as well as the market drivers and factors affecting 

31   

 

different price points. (Exhibit B‐1, p. 35) 

 

In its review of voluntary renewable energy market programs in North America, Terasen notes that 

there are three primary types of programs: 

 

• Contribution programs – those designed to allow customers to contribute to a utility managed fund for renewable energy project development. 

• Energy‐based programs – those allowing customers for a premium to purchase a certain amount of energy from sources which are renewable. 

• Carbon offset programs – those which provide the customer the option of offsetting their GHG emissions through the purchase of carbon offsets. 

 

Of these, Terasen notes that energy‐based programs had the highest level of success.  Further, the 

Company reports that according to National Renewable Energy Laboratory (NREL) the top ten 

green programs in the US in 2008 had participation rates ranging from 5 percent to 21 percent and 

all ten were some type of energy‐based scheme.  Overall, the participation rate for all programs 

reported on had a mean of 2.2 percent and a median of 1.2 percent, numbers which have 

increased steadily over the previous six years. (Exhibit B‐1, pp. 28‐30)  Terasen reports that if the 

average were relied upon, the uptake in this jurisdiction would result in over 16,000 signups for the 

Biomethane Program.  This exceeds anticipated production at the two current supply projects in 

the Application. (Exhibit B‐1, p. 46) 

 

Terasen commissioned a survey of residential and commercial customers.  Key findings of the 

survey as reported are as follows: 

 

1. Both residential and commercial customers strongly support Terasen’s investment in and the offering of biogas programs (67 percent support investing in biogas projects and 65 percent support offering programs). 

2. Both customer markets also show preference for an energy‐based program.  When presented with a choice between biogas and carbon offsets, customers favoured the former by a three to one margin.  Further, 56 percent of residential and 47 percent of commercial  customers indicated they would sign up for a biogas program as opposed to 24 percent of 

32   

 

residential and 35 percent of commercial who would do so with a carbon offset based program. 

3. When given a choice as to whether customers would prefer a program that was paid for by customers who signed up for a biogas offering and paid a premium as opposed to all customers bearing the cost 47 percent of residential and 60 percent of commercial customers preferred a universal price increase (to all customers) while 26 percent supported a premium price increase.  However, a large number (27 percent) did not state a preference or did not know how to answer the question.  When questioned further about the level of increased costs customers would be willing to pay if all customers had to pay (amounts between 0.5 and 3 percent were explored), there was a strong support for a modest percentage increase in cost (between 0.5 and 1 percent).  This support lessened as the cost premium approached 3 percent. 

4. With respect to price premiums and blends with a voluntary program, there was a strong preference for a 10 percent price premium on the commodity and for a 10 percent blend of biogas and corresponding GHG reductions (46 percent for both residential and commercial).  The preference dropped significantly for higher prices and blends of biogas and GHG reductions. 

5. Assuming the program was offered on a voluntary basis, 16 percent of residential and 10 percent of commercial customers indicated a disposition to enroll.  These numbers drop as the price level is raised.  Terasen reports that this equates to an estimated 120,000 residential customers and 9,200 commercial customers. 

 

On the basis of this research Terasen has concluded that a renewable energy program where 

customers enroll to have a portion of their natural gas come from biogas will be most effective.  

Terasen further concludes that the number of customers who would support a universal cost 

increase if it were moderate, is supportive of its proposed hybrid model where some costs 

associated with the Program are borne by all customers.  Finally, it has concluded that the research 

supports rolling out the Program first to residential customers due to their higher participation 

potential and their preference for an initial offering of a 10 percent cost increase for a 10 percent 

blend to maximize household involvement. (Exhibit B‐1, pp. 35‐47) 

 

In response to BCOAPO IR 1.4.3, Terasen indicated that it undertook to reflect some of the 

characteristics of the top ten green programs in its proposal.  Included among these are the 

following:  the choice of a renewable energy program, the consideration of marketing strategies 

such as those identified in Chartwell’s “Helping Customers Live a Sustainable Lifestyle 2007” 

33   

 

(Exhibit B‐1, Appendix C‐2), and the use of a lower price option in the introductory phase of the 

program. 

 

None of the Interveners expressed concern with respect to Terasen’s estimate of customer 

demand and how this was integrated into Program development.  However, the BCOAPO did 

express some concern with respect to the use of the mean rather than the median as related to the 

level of “take up” rates in the secondary research.  In spite of these concerns, it stated it did not 

“believe that TGI’s estimated total demands for green offerings are a cause for concern in this 

proceeding.” (BCOAPO Final Submission, p. 3, emphasis in original) 

 

Commission Determination 

 

The body of research presented by Terasen demonstrates that there is a willingness among 

customers to actively support what has been described as “green pricing” programs.  The 

information provided by NREL indicates that there is significant variance among the US jurisdictions 

reviewed with respect to the level of participation. Ignoring for a moment the results and attributes 

of the ten most successful programs, the fact that the mean participation rate for all programs was 

2.2 percent, which would result in an uptake rate of 16,000 households in BC, provides some 

comfort notwithstanding the concerns raised by BCOAPO that the median of 1.2 percent was a 

more appropriate measure.  By contrast, the TNS survey indicates there may be a potential 

participation rate as high as 120,000 households if customer actual participation rates match 

customer intentions measures. 

 

The Commission Panel notes that the TNS survey undertaken by Terasen was with BC residents 

only and is more representative and better reflects the customer views and intentions as well as 

the unique market conditions within the province of British Columbia.  Accordingly, we put more 

weight on this survey in spite of the fact that it measures intentions rather than actual results as 

was the case with the NREL Report.  However, in doing so the Panel acknowledges there is a 

potential for a relatively high participation rate (perhaps as many as 120,000 households) but is not 

persuaded that the case for this has been adequately made.  In our view, the most appropriate way 

34   

 

to determine the actual market potential as differentiated from customer intentions is to test it 

within the BC market. 

 

Terasen, in the view of the Panel has chosen a model which has been designed to reflect much of 

what has been learned from successful programs in other jurisdictions as well as from the primary 

research conducted within BC.  Firstly, the choice of an energy‐based program is very much in 

keeping with the success stories from other jurisdictions.  Moreover, it is an appropriate response 

to what was learned through research in the BC market where both residential and commercial 

customers indicated a strong preference for this type of model.  We also consider the choice of a 

10 percent premium for a 10 percent blend of biogas to be a good choice given the fact that the 

TNS survey indicates a strong preference for these percentage levels. 

 

The Commission Panel finds that the research presented by Terasen supports the position that 

there is likely to be sufficient demand to justify moving forward with a Biomethane Program. 

 

4.5  Commission Determination on the Projects 

 

As noted in the above, the Commission Panel is satisfied there is sufficient demand for and supply 

of Biomethane to move forward with the Projects. Further, the Panel is satisfied the Program is in 

alignment with British Columbia’s energy objectives and government policy. Accordingly, we 

approve the Purchase Agreements with the CSRD and Catalyst, and expenditures related to the 

facilities for both of these Projects. 

 

However, the Panel remains concerned that the model proposed by Terasen Gas has yet to be 

tested in the British Columbia marketplace.  In our view it would be prudent for TGI to gain 

knowledge and experience by a thorough testing of the Program before any firm determination can 

be made as to the full market potential.  The two Projects will provide a reference case which will 

serve as a basis for future projects.   Therefore, we have determined the scope of the Biomethane 

Program should be limited until such time as actual results can be analyzed and more definitive 

conclusions drawn.  This will be discussed further in Section 4.6, Criteria for Future Projects. 

35   

 

4.6  Terasen’s Role in Biogas Upgrading Process 

 

TGI takes the position that its ownership and operation of the upgrading facilities will promote the 

efficient development of Biomethane supply projects and ensure that the Biomethane, which is to 

be injected into the distribution system, will arrive “safely and economically” with dependable 

flow. (Exhibit B‐1, p. 6)  As discussed earlier, the upgrading process purifies raw biogas to remove 

contaminants, producing Biomethane, which is directly substitutable for natural gas. 

 

As discussed previously, Terasen Gas proposes two business supply models.  In one, CSRD, Terasen 

will purchase raw biogas from a supplier and upgrade that gas to Biomethane.  This model will 

therefore entail Terasen’s investment in the facilities required to upgrade the biogas to 

Biomethane.  This is above and beyond its investment in the facilities necessary to measure the 

flow of gas, connect to the TGI distribution system and test the gas to ensure its compatibility with 

natural gas, which is a requirement under both business models. 

 

Terasen notes that its proposed investment in the upgrading facilities is minor in comparison with 

the significant capital investment involved in the development and collection of raw biogas, a field 

which it does not intend to enter, as this is currently outside its area of expertise.  Nonetheless, its 

capital investment is acknowledged to be “material.” (Exhibit B‐1, pp. 6, 76) 

 

Terasen states that the upgrading of biogas to Biomethane “is purely a gas processing and gas 

management step” falling within its core expertise and that TGI “is best positioned in most cases to 

ensure that the biogas is upgraded in a manner that will best ensure a consistent and reliable 

supply of Biomethane.... .” (Exhibit B‐1, p. 71) 

 

TGI describes the advantages of its ownership of the upgrading facilities as follows:  

• Terasen is able to best ensure the safe, reliable and economic delivery of Biomethane to the distribution system; 

• Terasen’s retention of control over the upgrading process allows it to optimize operations and balance final gas quality with total volume of Biomethane; and 

36   

 

• Terasen’s point of control being further upstream of the measuring and monitoring point gives Terasen greater control of gas quality and customer and equipment safety. 

(Exhibit B‐1, p. 71) 

Terasen summarizes its position: “Terasen Gas must own and operate equipment to upgrade raw 

biogas to Biomethane in order to ensure safe and reliable operation of Biomethane supply 

projects.”  However, Terasen Gas does concede that when appropriate project partners can be 

found, there will be an opportunity for the development of “an independent Biomethane 

upgrading industry in British Columbia.” (Exhibit B‐1, p. 72) 

 

Terasen advises that in the natural gas industry, raw gas producers may own and operate the 

upgrading facilities, or the raw gas may be upgraded in third party facilities. (Exhibit B‐1, p. 73) 

 

Terasen also notes that at the time it filed its Application there were “no operating biogas 

upgrading plants in the province and therefore no experienced operators.” (Exhibit B‐3, BCUC 

IR 1.2.2) 

 

Terasen Gas suggests that, as its ownership of the upgrading equipment as utility assets best 

ensures the reliability of supply, this should be the preferred ownership model, absent other 

commercial reasons favouring third party ownership.  Terasen submits that this supports a flexible 

approach to the issue. (Terasen Final Submission, p. 29)  Terasen further suggests that “commercial 

realities” will favour TGI’s ownership and operation of the upgrading facilities as its involvement as 

an experienced, reputable and reliable partner will assist developers in obtaining financing.  It also 

suggests that less financing will be needed in total if it owns the upgrading equipment instead of 

the developer.  It further states that “[d]evelopers have indicated that a partner with experience in 

gas processing and gas technology is attractive.” (Exhibit B‐2, BCUC IR 1.2.2; Terasen Final 

Submission, p. 31) 

 

Terasen also submits that, to the extent that its involvement in the upgrading operation might 

discourage other market participants, such a line of enquiry is misplaced and that “[p]rotecting 

potential third party suppliers (if and when they exist) from competition…to encourage new market 

37   

 

participants cannot be the end objective of public utility regulation as defined by the [Utilities 

Commission] Act.”  It submits that the Commission only has jurisdiction over the competitive 

landscape for ownership of upgrading facilities to the extent that such ownership is ultimately 

related to the quality, reliability and cost‐effectiveness of Biomethane service.”  Terasen adds that 

“logic would suggest that the longer‐term effect of insulating third parties that might be interested 

in owning upgrading facilities from competition with an efficient producer like TGI will be 

inefficiencies that result in higher overall costs of supply to customers.” (Terasen Final Submission, 

p. 31) 

 

Terasen’s evidence is that the only constraint it is placing on potential third party involvement in 

the upgrading process is that they are “able to demonstrate they are capable of providing a reliable 

and safe source of Biomethane.” (Exhibit B‐3, BCUC IR 1.26.1) 

 

To the BCOAPO, “the nub of the issue is whether to permit the regulated monopoly distribution 

utility to venture into a commodity supply venture, and how to reconcile this intrusion into the 

unregulated, competitive supply market with the need to develop more environmentally benign 

ways of sourcing household energy.”  The BCOAPO offers only “strings‐attached” support for the 

Application, stressing that in its view, “biogas marketing and project costs are, for the most part, 

best undertaken by non‐utility entities” and that this “should not be taken as a template or 

precedent for the utility to venture further into the gas commodity refining and supply line of 

business.” (BCOAPO Final Submission, p. 3) 

 

Terasen maintains the view that its venture into the upgrading industry should be done through 

Terasen Gas itself in its current structure as opposed to through a non‐regulated business or 

through a separate, regulated entity.  It’s position is that all upgrading activities are subject to 

regulation by the Commission, given the definition of “public utility” in the UCA, and its application 

to a “person…who owns or operates…equipment or facilities…for… the production…of natural 

gas…or any other agent [i.e. Biomethane] for the production of … heat … to or for the public or a 

corporation for compensation…”  Terasen states that the definition of public utility covers both the 

upgrading of biogas to Biomethane and the notional sale of the Biomethane to customers and that 

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any entity that sells upgraded Biomethane either to the public or to Terasen will be subject to the 

Commission’s regulatory oversight. 

 

However, Terasen suggests that regulation of this business need not be active, but “passive” as the 

pricing issue can be addressed in the review of the purchase agreements. (Exhibit B‐3, BCUC 

IR 1.1.1) 

 

Terasen states that the “BCOAPO has not articulated how or why TGI’s supply model will impair fair 

competition, prevent a competitive marketplace, or negatively impact ratepayers” and suggests 

that its evidence in respect of its (or a reliable partner’s) need to own and operate biogas 

upgrading equipment was not challenged.  It further suggests that the BCOAPO did not address its 

other areas of evidence relating to the development of a competitive marketplace. (Terasen 

Reply, p. 4) 

 

Commission Determination 

 

Assuming, without necessarily deciding that upgrading processes are subject to regulation by the 

Commission, the Commission Panel remains concerned about Terasen’s entry into a new area of 

business.  The Commission Panel is not convinced that Terasen must be involved in the upgrading 

process to ensure the quality of product, reliability of delivery, and safety of the operation.  The 

Commission Panel is of the view that Terasen’s testing and control of the product in its 

interconnection facilities, prior to its inclusion in the distribution system, which will happen under 

either proposed business model, will provide that measure of protection.  However, the 

Commission Panel is prepared to allow the CSRD Project to proceed considering grants have been 

obtained to reduce the cost (and risk) of the project. 

 

The Commission Panel makes no finding on the acceptability of Terasen’s involvement in 

performing the upgrading at this time, particularly as there may be an industry developing which 

might result in a competitive business environment for future upgrading projects.  As this is a new 

business for Terasen, the Commission Panel rejects Terasen’s submission that it is or will 

39   

 

necessarily be an “efficient producer” and that its involvement in the upgrading process necessarily 

promotes “cost effectiveness”.  In addition, the Commission Panel notes that the upgrading of 

biogas does not have the significant upfront capital investment and potential economies of scale 

typical of a natural monopoly.  Upgrading of biogas may therefore evolve to an industry made up of 

a number of separate, small upgrading businesses.  The use of a separate entity, owned by Terasen, 

will maintain the advantages Terasen’s cites in terms of its reputation, experience and expertise.  

Accordingly, the Commission Panel directs that Terasen’s costs of the upgrading project be 

segregated so they may be compared with costs of other potential upgrading operations by other 

industry participants in the future.  The Commission Panel further directs that the upgrading 

business be kept sufficiently distinct so as to be severable, should the Commission determine 

that this business ought to be conducted through a separate entity in the future. 

 

4.7  Criteria for Future Projects 

 

As outlined in Section 3.3 of this Decision, TGI has proposed that the process for regulatory review 

of future new supply projects and contracts be streamlined.  Within the Application it has sought 

an order to allow future supply contracts that meet the criteria described within Section 8.4 of the 

Application to also meet the filing requirements in sections 71(1) (a) and 71(1) (b) of the UCA. 

(Exhibit B‐1, p. 133)  Accordingly, the Company proposes to file supply contracts only under 

section 70 [sic] without additional supporting information. (Exhibit B‐1, p. 80) 

 

In its Final Submission, Terasen states that the Commission can accept an energy supply contract 

under section 71 or it can require additional evidence in support of the public interest.  Terasen 

argues that many of the public interest considerations will be the same, while acknowledging there 

will be differences which will exist among future supply contracts with respect to terms of the 

agreements including price.  Accordingly, TGI submits that the potential for redundancy in the 

Commission’s review of what are relatively small supply projects makes it desirable for an efficient 

public interest review process and the criteria (outlined in Section 3.3 of this Decision) provide an 

appropriate reference point. (Terasen Final Submission, p. 34) 

 

40   

 

Both the CEC and BCSEA generally support the proposal put forward by Terasen with respect to 

establishing criteria for acceptance under section 71.  BCSEA notes that it provides a balance 

between efficiency and regulatory oversight. (BCSEA Final Submission, p. 7)  The CEC submits that 

because of the small size of the projects being considered, it would be inappropriate to burden this 

new initiative with undue regulatory process.  However, the CEC submits that the Commission 

should consider two additional criteria; continued prospects for customers buying the service and 

continued backup plans for mitigation of risk for the magnitude of supply under contract. (CEC Final 

Submission, p. 3)  BCOAPO provided no specific submissions with respect to the criteria issue. 

 

Terasen states that concerns underlying the CEC’s recommendation for the additional criteria have 

been adequately addressed in the proposal. (Terasen Reply, p. 2) 

 

The Commission Panel acknowledges the need to promote regulatory efficiency where appropriate 

and in the public interest.  However, in doing so, it underlines the importance of establishing 

criteria that are sufficiently precise and comprehensive to ensure the public interest continues to 

be met in the future.  The Panel believes there are a number of issues arising from the criteria 

which have been proposed by Terasen.  Firstly, there is concern as to whether the RIB Tier 2 rate 

proposed by Terasen as a price ceiling is appropriate.  Secondly, the Panel has concerns with 

respect to scope of the criteria being proposed and believes that consideration of further criteria 

should be undertaken in reaching a determination on this. 

 

As outlined previously in Section 3.3.2.1 of this Decision, TGI states that the justification to use RIB 

Tier 2 pricing as a proxy for Biomethane pricing is based upon two factors: 

 

• the lack of external benchmarks specific to Biomethane; and 

• the fact that RIB Tier 2 pricing (currently $15.28) reflects the price of new British Columbia based electrical supply which is viewed as a competing clean energy source. 

 

41   

 

On this issue the CEC, while stating it is comfortable with the proposed $15 ceiling, submits the RIB 

Tier 2 rate may not be the most appropriate way to regulate Biomethane as BC Hydro’s rates may 

vary for numerous unrelated reasons. (CEC Final Submission, p. 3)  BCSEA submits that it agrees 

with TGI’s reliance on the RIB Tier 2 rate as a benchmark for establishing an appropriate cost at 

least until an alternative market‐ based mechanism is found. (BCSEA Final Submission, p. 5) 

 

No other Intervener took a position on the price ceiling. 

 

Terasen Gas points out in its Reply that there are currently no external pricing benchmarks for 

Biomethane and the RIB Tier 2 rate is only an initial reference point and it will propose a price 

ceiling change in the event it becomes necessary in the future. (Terasen Reply, p. 2) 

 

With respect to the scope of criteria, the Panel notes again that this is a completely new business 

undertaking for Terasen.  While the research conducted indicates there is good potential, this has 

yet to be proven in the BC marketplace and, in spite of expectations, it could result in failure.  The 

potential impact of this is raised by BCOAPO in its Final Submission where it notes its main concern 

relates to the impact of the cost of stranded assets on non‐participants if the commercial venture is 

unsuccessful.  BCOAPO acknowledges that the small cost, the review process and the ability to 

remove and resell the installation if required, serve to mitigate its concern. (BCOAPO Final 

Submission, p. 3) 

 

Commission Determination 

 

The Commission Panel accepts that there is a need for streamlining of the approval process as it is 

likely that many of the projects which will be proposed in the future will be small in size and 

subjecting them to rigorous scrutiny in each case would not be in the public interest.  Accordingly, 

we have determined that future energy supply contracts for the purchase of biogas or 

Biomethane that meet the criteria listed in Section 3.3.3 of these Reasons with the following  

additional criteria will meet the filing requirements in sections 71(1)(a) and 71(1)(b) of the Act: 

 

42   

 

• The total production of Biomethane for all projects undertaken under what has been approved in this Decision does not exceed an annual purchase in each year of 250,000 GJ. 

• The maximum price for delivered Biomethane on the system is set at $15.28 per GJ.  

 

The Panel is encouraged by the initiative Terasen Gas has taken with this Biomethane Program and, 

subject to certain conditions raised within this Decision, is supportive of moving forward with 

additional projects in the future.  However, the Biomethane Program is a new initiative and has not 

been tested in the marketplace.  If the Panel were to approve future projects with no limitations as 

proposed by Terasen in the Application, it could be placing the ratepayer at risk for what in total 

could be a substantial amount.  We do not believe this would be in the public interest.  However, 

we are not convinced that the risk is so great that all future initiatives should be held back pending 

full testing of the model as suggested by the comments of BCOAPO.  Therefore, we have provided 

in our determination that TGI can purchase a total of 250,000 GJ annually which will allow some 

latitude for TGI to proceed with some additional projects before returning to the Commission with 

the results from what has been undertaken and recommendations for the future.  Nevertheless, 

the Panel would like to be clear that in spite of this, we view these initial programs as a test phase 

only.  The results from these projects will very much determine whether the Program will continue 

and whether the model as proposed is suitable.  We acknowledge the recommendations of the CEC 

with respect to additional criteria but given the limitations we have set, it is premature to add 

these criteria at this time.  Further, even with these criteria as Terasen has acknowledged, the 

Commission retains the right to depart from them and require further process. (Exhibit B‐3, 

BCUC 1.24.3) 

 

The Commission Panel notes the comments of CEC with respect to tying the pricing ceiling for 

future projects to the RIB Tier 2 rate as proposed by Terasen and has similar concerns with respect 

to the potential for future price changes.  However, the Panel is satisfied that setting the rate 

ceiling at $15.28 per GJ which corresponds to the current RIB Tier 2 rate is reasonable as it provides 

Terasen with sufficient discretion to operate with some flexibility with the initial projects. 

 

43   

 

4.8  Risk of Stranded Assets 

 

A stranded asset is an asset that is worth less on the market than it is on a balance sheet due to the 

fact that it has become obsolete in advance of complete depreciation.  Stranded costs related to 

stranded assets are inevitable in any industry where the regulatory environment changes 

dramatically, and partial or full compensation for stranded costs is usually considered fair play for 

monopoly services suddenly thrust into a competitive market place.  Today, the debate continues 

regarding the extent to which the regulatory compact entitles utilities to recover the cost of 

stranded assets in future rates.  Depending on circumstances, utilities have been allowed to 

recover the entire investment or a partial investment from their regular customers over a certain 

amortization period.  There may even be situations where no recovery would be permitted.  This 

larger question cannot be answered in this proceeding but, nevertheless, the following should be 

considered in this context of uncertainty regarding the ultimate responsibility over stranded assets. 

 

This Section addresses the risk of the Projects in the event those ventures are not commercially 

successful.  Related to the risk of failure to supply is the potential for permanent termination of the 

contract by project partners that would leave Terasen’s installed facilities idle.  This is a particular 

concern in the case of the CSRD Project where Terasen Gas is investing in the upgrading facilities. 

 

TGI submits that the risk of stranded assets is modest to start with and that Terasen has taken 

appropriate steps to mitigate that risk contractually: 

 

• The overall investment required by Terasen is low, being $1.8 Million for CSRD and $0.6 Million for Catalyst; 

• There is little risk of stranding associated with lack of customer demand, as the Biomethane generated by the two projects would be consumed based on the conservative measure of industry average demand; 

• The 15‐year and 10‐year terms for the CSRD and Catalyst Projects respectively provide longer term supply of biogas and a reasonable period over which to recover equipment costs; 

44   

 

• Under the contracts, Terasen has the right to enter the site and physically recover its facilities after a specified period of non‐performance.  The majority of facilities used for the project could be recovered and used for other projects.  In addition, the CSRD contract provides Terasen with a termination payment in excess of the estimated value of the stranded assests and moving costs whereas the Catalyst contract provides Terasen with appropriate security against stranding; and 

• Advancements in upgrading technology will have little impact on the success of the CSRD project, as the current equipment recovers as much as 95 percent of the methane in raw biogas.  As a result, any technological improvements over time will result in only minor efficiency improvements and would therefore not make the current technology obsolete. 

(Terasen Final Submission, pp. 24‐25, 28) 

 

BCOAPO submits that its main concern (apart from whether this is appropriate utility activity at all) 

is “the risk of stranded costs being visited upon non‐participants if the venture is not successful 

commercially.”  However, BCOAPO acknolwedges that in this case the relatively small cost, the 

post‐implementation review, and the configuration of the installation to facilitate removal and 

resale, all mitigate that concern.  Finally, BCOAPO submits that Biomethane is a technology which 

should have an opportunity to incubate under the aegis of the utility, so long as financial risks to 

non‐participants are contained, and that the proposed projects may be a useful and necessary 

“kickstart” for future green initiatives by other parties. (BCOAPO Final Submission, pp. 2‐3) 

 

The CEC submits that the investments proposed by Terasen are modest, the risks relative to those 

investments are well identified and Terasen has plans for substantial risk mitigation should they be 

realized.  Accordingly, the CEC agrees with Terasen’s summary of its evidence. (CEC Final 

Submission, p. 2) 

 

Commission Determination 

 

The Commission Panel finds that the total capital investment required by TGI for the Projects is 

relatively low; especially after allowing for the funding received from the Innovative Clean Energy 

fund and from the BC Bioenergy Network.  The Commission Panel also notes the supporting 

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Intervener submissions on this matter and finds that Terasen has taken reasonable steps to 

mitigate the ultimate risk of stranded assets in terms of the specific structure of contracts it has 

negotiated.  Finally, the Commission Panel finds that there is little risk of stranding due to lack of 

customer demand as the estimates used for projections are on the conservative side. 

 

With regard to future projects, the Commission Panel finds that the Guiding Principles for 

Development of Biomethane Supply, the proposed contract language as well as the price ceiling, a 

predetermined production quantity limit and the shorter time period to be allowed for the test 

period will serve to mitigate concern over the risk of stranded assets.  This should be true even in 

the cases of future projects that will not receive special funding. 

 

4.9  Principles for Cost Recovery 

 

As illustrated in the Biomethane Service Offering Model diagram in Section 3.0, Terasen proposes 

that customers opting for the Biomethane Offering should pay the full costs of the Biomethane gas 

supply while all Terasen Gas customers will share the costs related to the interconnection and 

monitoring equipment as well as the cost of IT upgrades, program management and customer 

education.  This Section outlines the proposal in more detail to address the question: Should any 

costs be shared by all Terasen customers at all? 

 

4.9.1  Rate Setting 

 

Terasen seeks approval for its proposed rate, tariff provisions, cost allocation methodology, and 

accounting treatment pursuant to sections 44.2, and 59 to 61 of the UCA.  These are listed in 

Appendix E. 

46   

 

4.9.2  General Cost Recovery Principles 

 

TGI proposes that customers opting into the Offering and committing to purchase Biomethane 

should pay the full costs to supply pipeline quality Biomethane gas.  Where Terasen will acquire 

raw biogas for upgrading, the acquisition costs of the raw biogas, and the costs of owning and 

operating the upgrading equipment will be fully recovered via the Biomethane rate.  Similarly, for 

those projects where Terasen will acquire pipeline‐ready Biomethane, these costs will be fully 

recovered via the Biomethane rate.  Terasen states that incremental Customer Works LP (CWLP) 

charges related to processing customer enrolments in the Biomethane Program and ongoing O&M 

such as customer drops, moves and changes will be fully recovered from only the Biomethane 

Program customers via the Biomethane rate. (Exhibit B‐1, p. 17) 

 

However, Terasen Gas states that some costs are being incurred in order to give all customers the 

choice of participating in the Biomethane Program, and that all customers obtain environmental 

benefits from Terasen offering Biomethane as an option.  Terasen further states that costs incurred 

to provide this choice and deliver environmental benefits should be allocated to all customers of 

the utility because this is consistent with the implementation of other programs, such as the 

Customer Choice Program. (Exhibit B‐1, pp. 107‐108) 

 

All operating and maintenace and capital costs included in the determination of the rate impacts, 

including the allocation of costs between all customers and those choosing to participate in the 

Biomethane Program, are shown in the following two tables. 

 

47   

 

Table 4‐1 Terasen Gas Inc. – Biogas O&M Details 

   Source:  Exhibit B‐1, Appendix J‐1, p. 1 

 

48   

 

Table 4‐2 Terasen Gas Inc. – Biogas Capital Details 

   Source:  Exhibit B‐1, Appendix J‐1, p. 2  

4.9.3  Determination of Costs Related to System Changes 

 

TGI commissioned an IT consulting firm to assess the required business system changes and 

estimate the costs required to implement the new Offering, including customer enrolment, 

program management, nominations, customer billing and rate setting.  Terasen states that the 

system impact analysis has taken into consideration the existing initiative to replace the current 

customer billing system and move customer care services in‐house.  Terasen believes it has 

developed a cost‐effective and workable solution along with supporting processes and systems to 

implement a Biomethane Program in British Columbia. (Exhibit B‐1, p. 109) 

 

4.9.4  Costs to be Allocated to all Customers 

 

Costs that will be allocated to all Terasen Gas distribution customers will include: 

 

• Cost of service related to gas analyzing equipment, meters, transmission or distribution pipeline extensions constructed to receive the injection of Biomethane; 

49   

 

• Capital costs for application development and configuration of the current customer billing system and modifications to supporting processes to support accepting on‐line enrolment requests, configure the new Biomethane tariff and provide additional reporting; 

• On‐going operating costs related to additional customer inquiry calls, quarterly updates to the tariff rate, customer education costs, including costs associated with marketing the Program, and a new full time position of biogas Program Manager. 

 

Terasen proposes the creation of a non‐rate base deferral account to capture costs applicable to all 

customers incurred prior to January 1, 2012.  It further proposes to recover these costs from all 

non‐bypass customers by amortizing them through delivery rates commencing January 1, 2012 

over a three year period.  The forecast levelized rate impact for these customers is $0.004 per GJ.  

By way of example, Terasen states that for a residential customer using 95 GJ per year, the annual 

incremental cost is 38 cents. (Exhibit B‐1, pp. 110‐111) 

 

4.9.5  Costs to be Allocated to Biomethane Program Customers 

 

Costs to be allocated to Biomethane Program customers include the cost of purchasing 

Biomethane and raw biogas, including upgrading costs, as well as the ongoing administrative O&M 

costs directly related to Biomethane customers such as customer enrollment, removal of 

customers from the program and billing adjustments. 

 

Terasen proposes to recover these costs through a Biomethane Energy Recovery Charge.  As this 

rate will be based on forecast costs, Terasen seeks Commission approval of a deferral account, the 

Biomethane Variance Account (BVA), to capture the difference between actual costs and revenues 

collected through the BERC rate.  Terasen has calculated the BERC rate as $ 9.904/GJ and seeks 

approval of the Biomethane Energy Recovery Charge at this amount effective October 1, 2010. 

(Exhibit B‐1, p. 117) 

 

50   

 

By electing to participate in the first phase of the Biomethane Program offering, residential 

customers will pay a gas commodity price based on a 10 percent Biomethane and 90 percent 

natural gas blend.  Terasen submits its proposal results in a minimal rate impact for all non‐bypass 

customers, and a Premium Service rate that reflects the premium cost of Biomethane.  It also 

points out that there is a longer‐term customer interest in ensuring that its product offerings meet 

the expectations of customers and potential customers and also submits “[a]ll customers benefit 

from initiatives to retain and add throughput to the Terasen system because added throughput 

spreads system costs over a larger base, thus resulting (all else equal) in lower delivery rates.”  

Finally, Terasen submits that that the proposed rates are just and reasonable, given the benefits to 

all customers associated with the premium offering, and the principled basis Terasen has proposed 

for cost allocation. (Terasen Final Submission, pp. 19, 51) 

 

4.9.6  Intervener Submissions 

 

BCOAPO strongly supports “thoughtful and economical efforts to increase the use of renewable 

resources and reduce GHG emissions in the province” and believes that such efforts are in the 

public interest.  However, BCOAPO submits that the costs of achieving that goal must be 

distributed appropriately and through correct mechanisms.  While BCOAPO has some concerns, it 

supports the Application noting the small annual costs to non‐participants. (BCOAPO Final 

Submission, pp. 2‐3) 

 

BCSEA supports the concept that customers in the Biomethane Program should pay for the cost of 

Biomethane and all customers should pay for the cost of making the Biomethane Program 

available.  BCSEA agrees with Terasen that the principle is analogous to the Commission‐approved 

treatment of the Customer Choice Program. (BCSEA Final Submission, p. 6) 

 

The CEC supports Terasen’s efforts to address the long term management of risk by way of this 

initiative to ensure retention and addition of customers to the system in order to spread 

distribution costs over a larger base.  The CEC submits that Terasen’s rates should be set on the 

basis of cost causality for utility service rates and believes that the Shareholder should not be 

51   

 

inherently responsible for the cost of any of the proposed Biomethane Service.  The CEC further 

submits that Terasen has correctly defined cost allocation methodologies appropriate for utility 

service and has proposed to apply them correctly.  Finally, the CEC notes that the allocation of 

marketing, advertising, promotion and education back to all customers appears to be standard 

practice and that there is no quality evidence on the record to support alternative cost‐allocation 

methodologies.  The CEC submits that the Commission should give weight to the fact that the 

magnitude of the expenditures for this new service does not warrant revision of the cost allocation 

methodology at this time.  “The broad interest of customers in GHG reduction and the potential for 

renewable options makes the cost allocation to all customers appropriate.” (CEC Final Submission, 

pp. 4‐5) 

 

Commission Determination 

 

The Commission Panel is cognizant of the new post CEA environment which is challenging TGI to 

innovate and adapt its utility service model.  In this regard, the Commission Panel agrees with 

Terasen and the CEC that it is in the long term interest of all Terasen utility customers that new 

initiatives contribute to retention and the addition of throughput in the system, which will result in 

system costs being spread over a larger base.  The Commission Panel also notes the dual role of the 

Commission in balancing the interests of ratepayers and the utility. 

 

It is in this context that the Commission Panel approves the cost allocation methodology 

proposed by Terasen Gas for the test period as just and reasonable.  It is important to consider 

this finding as a test period approval only, as another determination will be required at the point of 

the review for Phase 1.  The Commission Panel also notes the “strings‐attached” support given by 

BCOAPO.  Because in this Application the small levelized annual cost to non‐participants, 

(estimated at 38 cents to an average customer) is not material, it is relatively easy to approve the 

methodology.  Small programs like this give Terasen an opportunity to develop the markets and 

test customer demand under the auspices of the utility regulatory model.  However, as the 

Biomethane business grows and matures the issue of “who pays” becomes more significant.  In the 

long term, once the markets have evolved, a time may come to take a fresh look at the role of the 

52   

 

utility vis‐a‐vis competitive markets as discussed in Section 6.0. 

 

The Commission is concerned that distribution (or transmission) pipeline extensions to connect the 

projects are included in the costs allocated to all customers.  These costs can vary widely from 

project to project, and arguably are more akin to upgrading costs.  However, considering the 

relatively modest amount of those connection costs for the two projects at hand and the test 

period nature of this approval, the Commission will only require that this cost be identified and 

monitored. 

 

The Commission Panel notes that TGI has budgeted $160,000, $240,000 and $300,000 for customer 

education in 2010, 2011 and 2012 respectively, but has not sought approval of these.  The 

Commission accepts that these expenditures will be recorded in the appropriate deferral account.  

However, the Panel notes that recovery in future rates of these amounts will be subject to future 

review by Commission. 

 

Specific approvals for the Biomethane Energy Recovery Charge, the Biomethane Variance Account 

and other components of the approvals sought will be addressed in Section 5.0. 

 

4.10  Other Project Risks 

 

This Section addresses project risks other than risk of stranded assets for the CSRD and Catalyst 

Projects and summarizes Terasen’s mitigation measures. 

 

4.10.1  Risk to Gas Supply Portfolio 

 

TGI states that quantity of biogas and Biomethane from the Projects will not impact its overall gas 

supply portfolio.  At these early stages with low levels of supply, entering the two agreements will 

not cause Terasen to alter its other portfolio or planning practices or contracts.  Terasen further 

states that because of this, the amounts of new supply promised will not leave the Company 

vulnerable to either additional market purchases or access to alternative sources of conventional 

53   

 

gas to replace biogas or Biomethane that is not delivered.  However, Terasen also states that as 

additional biogas and Biomethane purchase agreements come on line it will reassess the impact on 

its overall portfolio.  Finally, Terasen points out that the Catalyst agreement includes the full costs 

of replacement gas in the non‐performance remedies within the agreement. (Exhibit B‐1, pp. 92, 

101, 102) 

 

4.10.2  Risk of Failure to Supply Biomethane 

 

In the case of the CSRD Project, Terasen notes that the composition of buried waste in the Salmon 

Arm landfill is not fully predictable and therefore neither is the gas production from the landfill.  As 

a result, there is the potential for an interruption in either supply of raw gas or Biomethane.  It 

states that it has mitigated these risks in two ways: 

 

• From the gas system perspective, planning will be done assuming that biogas is not available; 

• From a financial perspective, the compensation for sale of gas is based on sellable (purified) gas.  The CSRD will not receive any payments unless Terasen can successfully upgrade the biogas and inject it into the distribution system.  Further, there is also a minimum supply requirement that if not met will trigger a contractual default. 

(Exhibit B‐1, p. 92) 

 

In the case of the Catalyst Project, Terasen explains that failure of Catalyst to provide gas to the 

Company could result from events such as loss of waste stream supplies (anaerobic digester 

feedstock), failure to meet gas specifications, breach of contract or poor financial health resulting 

in interruption to operation.  Terasen states that it has addressed these risks through a non‐

performance clause in the agreement. (Exhibit B‐1, p. 102) 

 

54   

 

4.10.3  Operational and System Risk 

 

Terasen Gas takes the position that “in the unlikely event that a failure of the biogas upgrading 

equipment occurs”, contaminants harmful to the pipeline or disruptive to customer service could 

occur.  In order to mitigate this risk, Terasen will ensure the upgrading system be designed to self‐

monitor for abnormal conditions and, as owner of the upgrading equipment, will always have the 

final control of the gas quality.  Should Biomethane not meet these specified quality, Terasen will 

immediately stop delivery to customers and evaluate the problem with the CSRD. (Exhibit B‐12, 

p. 93) 

 

To mitigate the same concerns in the case of Biomethane delivery from Catalyst, the agreement 

requires that Biomethane must meet Terasen Gas specifications and includes the right of Terasen 

to interrupt delivery from the project if the gas does not meet these quality specifications.  The 

Catalyst facilities will also be linked with TGI’s gas control system to allow real time monitoring of 

the quality sampling equipment.  Terasen further states that the pressurized flows of conventional 

natural gas will automatically backfill and replace the lost flow of Biomethane during any such 

stoppage. (Exhibit B‐1, p. 102) 

 

4.10.4  Facilities Cost Risk 

 

Terasen states there is some risk that costs for the facilities could be higher than expected, but 

notes it has followed best practices for cost projections and used conservative estimates for 

interconnection and monitoring equipment to mitigate this risk.  Terasen further states that for the 

upgrading plant it has negotiated a fixed price contract with the supplier.  Finally, Terasen notes 

that in the CSRD cost‐of‐service analysis it has included a 10 percent contingency allowance on 

capital costs. (Exhibit B‐1, p. 93) 

 

In the case of the Catalyst Project, Terasen has followed the above practices for the 

interconnection and monitoring equipment to mitigate risk.  In addition, it has included a 

20 percent contingency allowance on capital costs. (Exhibit B‐1, p. 103) 

55   

 

Commission Determination 

 

The Commission Panel finds that Terasen Gas has taken prudent steps to mitigate risks inherent in 

innovative new projects such as the CSRD biogas and Catalyst Biomethane Projects.  However, the 

Commission Panel notes that after the test period there will be a requirement for a more 

comprehensive review of who owns the upgrading facilities as discussed in Section 4.5.  This review 

should also provide an opportunity for a further risk assessment. 

 

4.11  Post Implementation Review and Reporting 

 

In its Application, Terasen acknowledges that following implementation a thorough review of the 

Biomethane Program will be necessary.  The Company proposes that the review be carried out five 

years following the Program launch and be made up of two components; a post‐implementation 

report and a workshop.  The report and workshop will address the following elements: 

 

• How many and what types of supply projects have been developed; 

• Customer segmentation; 

• Enrollment and attrition Rates; and 

• Review of the costs incurred and their recovery. 

 

Terasen notes that the five year time span will be sufficient to allow the industry to mature through 

the development of additional projects and to validate the research which has been conducted into 

the residential and commercial markets.  In the ensuing period, Terasen proposes to report on the 

development of the Program through its revenue requirement applications as well as report on the 

costs of Biomethane gas as part of the regular quarterly gas cost reporting which has been 

established with the Commission. (Exhibit B‐1, p. 81) 

 

BC Hydro had no comments in its submissions with respect to the post‐implementation review and 

reporting process.  Likewise, the BCOAPO had no comments concerning the timing and review of 

the Program.  However, based on the BCOAPO’s stated position that the Projects should be made a 

56   

 

“one off” and not be taken as a template for further ventures into the gas commodity refining and 

the supply line of business, it can be inferred that it is BCOAPO’s view the timeline for review of the 

Projects could be shortened. (BCOAPO Final Submission, p. 3)  BCSEA stated in its submission that it 

was in support of what Terasen has proposed. (BCSEA Final Submission, p. 7)  The CEC recommends 

that the Commission request annual reporting encompassing on‐going investment expenditures, 

operating costs and updated projections for customers, as well as volumes and costs in addition to 

what has been proposed. (CEC Final Submission, p. 5) 

 

In Reply to the CEC submission, Terasen states that if the Commission wishes it to address the 

additional information in annual reports it will do so.  However, it notes that what has been 

proposed is redundant as it will be addressed more appropriately in TGI’s future resource plans 

and/or revenue requirements applications.  Terasen concludes by pointing out that the costs for 

what it describes as redundant reporting will be borne by customers. (Terasen Reply, p. 3) 

 

Commission Determination 

 

As outlined in Section 4.6, the Panel has placed limits on total Biomethane production for all 

projects undertaken in this program.  Our purpose is to allow Terasen the flexibility to expand the 

program from the two Projects.  However, we also want to ensure there is the opportunity for 

stakeholders to better understand and review the success or failure of this Program and whether 

the proposed Biomethane Offering Model is appropriate before it is allowed to grow to the point 

where it would be difficult to reverse without a significant financial impact. In keeping with this 

view, the Panel finds the five year time period proposed by Terasen for a full review of the program 

to be unnecessarily lengthy.  We believe that reducing this time period to a period of two years will 

allow TGI sufficient time to launch some additional projects and undertake the analysis necessary 

to provide an adequate basis for review.  Accordingly, the Commission Panel, to safeguard the 

public interest, has determined that Terasen will be granted a period of two years from the date 

of the Order issued concurrently with this Decision for review and preparation of further 

applications in support of expansion of this Program. 

 

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The Panel, acknowledging the CEC recommendations, expects Terasen’s analysis and report to be 

comprehensive.  Our requirements include but are not limited to examination of the following 

information: 

 

• Full financial review of all projects (individual and aggregate numbers) which have been undertaken; 

• Validation of the market research; 

• Enrollment and attrition rates; 

• Costs and assessment of customer marketing/education programs; 

• Customer segmentation and targeting; 

• Assessment of Pricing Methodology and Principles for Cost Recovery; 

• Future Projects that are under consideration 

• Forecasts of Biomethane supply as well as customer demand and anticipated update for the next ten year period. 

 

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5.0  OTHER APPROVALS REQUESTED 

 

5.1  Biomethane Variance Account 

 

The Commission Panel approves the creation of a rate base deferral account, called the 

Biomethane Variance Account, as proposed by Terasen.  This account will capture costs to procure 

and process consumable Biomethane gas as well as revenues collected through Biomethane energy 

recovery components of rates.  The Commission Panel finds the BVA to be a reasonable mechanism 

to accumulate any differences in Biomethane service costs and revenues.  Further, the Panel 

accepts Terasen’s quarterly reporting process and Biomethane Energy Recovery Charge rate setting 

mechanism as proposed in the Application as this methodology is consistent with the Company’s 

existing gas reporting and rate setting methodologies. 

 

Commencing January 1, 2012, the treatment of all costs related to and resulting from ongoing 

Biomethane operations will be reviewed by the Commission as a component of Terasen’s Revenue 

Requirements Application (RRA).  Within TGI’s RRA for 2012 and onwards, Terasen is directed to 

include a separate section providing actual and forecasted Biomethane operating, maintenance 

and capital costs and an analysis of these costs.  This disclosure is to include, amongst other 

things, a breakdown of costs incurred by category of past and projected years and an explanation 

of the financial results experienced and expected in the test period.  Details of all accumulations 

within the BVA should also be provided. 

 

The Commission Panel further approves Terasen’s request for two new non‐rate base deferral 

accounts (New Deferral Accounts) to capture the following costs, as described by the Application, 

incurred prior to January 1, 2012: 

 

i)  Costs of service associated with the capital additions to the delivery system; and 

ii)  Operating and maintenance costs applicable to all customers (attracting AFUDC). 

(Exhibit B‐1, pp. 110‐111) 

 

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As costs associated with the New Deferral Accounts will be incurred in the remaining portion of the 

revenue requirement period, the Panel accepts the proposed deferral treatment until January 1, 

2012. 

 

In the Application, the Company seeks to recover costs accumulated in the New Deferral Accounts 

from all non‐bypass customers over a three year period by amortizing them through delivery rates 

commencing January 1, 2012. (Exhibit B‐1, p. 111)  The Commission Panel approves this request as 

an acceptable recovery period given the nature and forecasted extent of these costs. 

 

As part of its 2012 Revenue Requirements Application, TGI is directed to report the total values 

accumulated in the New Deferral Accounts from inception as well as a breakdown of the costs 

accumulated in the accounts by nature and dollar amount.  Further, the Company is directed to 

present within its annual regulatory report to the Commission, the total value of each of these 

deferral accounts, net of any amortization.  This is to be done each year until the remaining 

balance is $nil. 

 

Terasen also seeks to set the Biomethane Energy Recovery Charge at $9.904/GJ and seeks approval 

that the Biomethane Energy Recovery Charge is set at this amount effective October 1, 2010. 

(Exhibit B‐1, p. 117)  Because the rate of $9.904/GJ is well below the maximum rate of $15.28 

previously established in Section 4.6, the Panel accepts the Biomethane Energy Recovery Charge 

at $9.904 for all Rate Schedules effective October 1, 2010 to recover forecasted costs. 

 

5.2 Rate Schedules 

 

TGI seeks approval of rate schedules of both Phase 1 and 2 of the proposed Offering.  TGI proposes 

that the Commission approve Rate Schedules 1B and 11B and amendments to Rate Schedule 30 

effective October 1, 2010 (Phase 1), and also approve Rate Schedules 2B and 3B for commercial 

customers effective January 1, 2012 (Phase 2).  TGI notes that Rates Schedules 1B, 11B and the 

amendments to Rate Schedule 30 reflect the rate methodology described in this Application.  Rate 

Schedules 2B and 3B reflect methodology which TGI indicates is consistent with Phase 1 as well as 

60   

 

offering higher blends of Biomethane which TGI believes may appeal to commercial customers.  

TGI also requests an amendment to its General Terms and Conditions to include reference to the 

Biomethane Offering. (Exhibit B‐1, pp. 52‐53 as amended by Exhibits B‐1‐1 and B‐3) 

 

TGI believes it is important to approve both Phase 1 and 2 Rate Schedules at this time for two 

reasons.  The first reason is to avoid the additional regulatory cost to review Phase 2 as a separate 

proceeding in the future, especially given the body of evidence submitted in this proceeding, and 

secondly to avoid future delays on timely expansion. (Terasen Final Submission, p. 40) 

 

TGI indicates its intent to file with the Commission additional tariff schedules when the opportunity 

to expand the program exists.  Also, TGI notes that the Biomethane rollout to other regions and 

rate classes will be driven by customer uptake rates in Phase 1 combined with supply availability.  

TGI proposes that as such, customer offerings and rate schedules could be modified from time to 

time. (Exhibit B‐1, p. 53) 

 

CEC submits that the proposed phase in of the TGI Biomethane service is reasonable and sensible 

and agrees that setting rates now is appropriate and may avoid unnecessary regulatory 

proceedings. (CEC Final Submission, p. 4) 

 

BCSEA accepts TGI’s explanation for offering the Biomethane Program to residential customers 

initially and later expanding the program to make it available to commercial customers and 

possibly offer Biomethane blends higher than the 10 percent proposed in Phase 1.  Also, BCSEA 

accepts TGI’s rationale for seeking approval for the Phase 2 rate schedules at this time. (BCSEA 

Final Submission, p. 6) 

 

BCOAPO and BC Hydro express no position on tariff matters. 

 

61   

 

Commission Determination 

 

The Commission Panel approves TGI’s Biomethane new Rate Schedules 1B, 11B, 2B and 3B and 

the proposed amendments to existing Rate Schedule 30 as well as requested changes to TGI’s 

General Terms and Conditions.  The Commission Panel finds that sufficient evidence has been 

presented in this proceeding for it to determine that the proposed Rate Schedules are just and 

reasonable based on the proposed allocation methodology.  It therefore approves them for Phase 1 

and 2 of the Biomethane Program.  However, if the new Rate Schedules 2B and 3B, when filed, 

deviate from the methodology described in the Application, the Commission may determine 

further regulatory process is necessary for those Rate Schedules. In addition, the Panel directs TGI 

to provide to the Commission any future proposed Biomethane Rate Schedules or amendments 

to schedules at least 60 days in advance of their proposed effective date.  If the Commission 

identifies Biomethane program matters for those Rate Schedules that deviate from the 

methodology described in the Application, the Commission may determine that further regulatory 

process is necessary before approving any proposed rate offerings or changes related to TGI’s 

Biomethane Program. 

 

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6.0  OTHER COMMISSION PANEL CONSIDERATIONS 

 

This Application for approval of a Biomethane Program and Supporting Business Model is just one 

of a number of projects Terasen is contemplating as means of dealing with the new environment 

which has resulted from passage of recent legislation including the Clean Energy Act.  A number of 

other new initiatives have been outlined as being under consideration within the Company’s 2010 

Long Term Resource Plan which was filed with the Commission in July of this year.  Collectively, 

these represent a significant departure from the role Terasen has traditionally played as a public 

utility.  As the Company moves forward with what is a new business model, the issue becomes how 

to best reconcile those instances where it has moved to a different position on the supply side or is 

undertaking activities which are more characteristic of a non monopolistic company dealing within 

a competitive market.  In undertaking these new initiatives questions arise as to whether they 

should be allowed within a regulatory framework and where this leaves the ratepayer with respect 

to who bears the risk. 

 

This Hearing has dealt with a number of questions related to Terasen’s departure from the status 

quo.  Included among these are the following: 

 

• The provision of biogas upgrading services representing a move up the supply chain. 

• Principles governing the allocation of costs to ratepayers. 

• The risk of stranded assets and resultant question of who pays. 

 

In order to facilitate the process and avoid unnecessary impediments, the Commission Panel chose 

to deal with this application with the understanding that it represents a test program which will 

provide valuable information and answers to the question as to how best to handle this model on a 

go forward basis.  Accordingly, the Panel provided direction with respect to Terasen’s proposal to 

own the upgrading facilities in some instances, share costs for the Program among various 

ratepayer groups and place overall risk for the Program on the broad ratepayer group.  However, 

the Commission Panel would like to be clear that these decisions were made to facilitate the test 

program only.  Following the filing of the Post Implementation report, the Commission may decide 

63   

 

to fully review the model and make other determinations based on the information or lack thereof 

in that report. 

 

As to the larger questions involving the impact of Terasen’s proposed new business model, the 

Commission Panel does not consider it appropriate to answer these questions within the context of 

this Hearing.  However, we do believe that the changes being contemplated and the issues which 

arise from them are significantly important to warrant a formal process to deal with them at a 

future date. 

 

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7.0  SUMMARY OF DIRECTIVES 

 

This Summary is provided for the convenience of readers.  In the event of any difference between 

the Directives in this Summary and those in the body of the Decision, the wording in the Decision 

shall prevail. 

 

  Directive  Page 

1. The Commission Panel therefore finds that the Application is consistent with British Columbia’s energy objectives and Provincial Government energy policy.  

27 

2. The Commission Panel accepts TGI’s estimate of its potential Biomethane supply and finds this supply to be sufficient to justify moving forward with the Biomethane Program but the Panel also acknowledges the limited data available to support this estimate.  

30 

3. The Commission Panel finds that TGI has proposed reasonable techniques to address the risk of Biomethane shortfalls if short‐term supply estimates are overstated.  Further, the Commission Panel approves TGI’s proposal to purchase carbon offsets and to recover costs through the Biomethane Variance Account in the event of under‐supply of Biomethane, at a per gigajoule unit price not to exceed the difference between the Biomethane Energy Recovery Charge and the Commodity Cost Recovery Charge in effect at that time.  

30 

4. The Commission Panel finds that the research presented by Terasen supports the position that there is likely to be sufficient demand to justify moving forward with a Biomethane Program.  

34 

5. Accordingly, we approve the Purchase Agreements with the CSRD and Catalyst, and expenditures related to the facilities for both of these Projects.  

34 

6. Therefore, we have determined the scope of the Biomethane Program should be limited until such time as actual results can be analyzed and more definitive conclusions drawn.  

34 

65   

 

7. Accordingly, the Commission Panel directs that Terasen’s costs of the upgrading project be segregated so they may be compared with costs of other potential upgrading operations by other industry participants in the future.  The Commission Panel further directs that the upgrading business be kept sufficiently distinct so as to be severable, should the Commission determine that this business ought to be conducted through a separate entity in the future.  

39 

8. Accordingly, we have determined that future energy supply contracts for the purchase of biogas or Biomethane that meet the criteria listed in Section 3.3.3 of these Reasons with the following additional criteria will meet the filing requirements in sections 71(1)(a) and 71(1)(b) of the Act:  • The total production of Biomethane for all projects undertaken under what has 

been approved in this Decision does not exceed an annual purchase in each year of 250,000 GJ. 

• The maximum price for delivered Biomethane on the system is set at $15.28 per GJ. 

 

41 

9. It is in this context that the Commission Panel approves the cost allocation methodology proposed by Terasen Gas for the test period as just and reasonable.  

51 

10. Accordingly, the Commission Panel, to safeguard the public interest, has determined that Terasen will be granted a period of two years from the date of the Order issued concurrently with this Decision for review and preparation of further applications in support of expansion of this Program.  

56 

11. Within TGI’s RRA for 2012 and onwards, Terasen is directed to include a separate section providing actual and forecasted Biomethane operating, maintenance and capital costs and an analysis of these costs.  

58 

12. The Commission Panel approves this request as an acceptable recovery period given the nature and forecasted extent of these costs.  

59 

13. As part of its 2012 Revenue Requirements Application, TGI is directed to report the total values accumulated in the New Deferral Accounts from inception as well as a breakdown of the costs accumulated in the accounts by nature and dollar amount.  Further, the Company is directed to present within its annual regulatory report to the Commission, the total value of each of these deferral accounts, net of any amortization.  This is to be done each year until the remaining balance is $nil.  

59 

66   

 

14. The Panel accepts the Biomethane Energy Recovery Charge at $9.904 for all Rate Schedules effective October 1, 2010 to recover forecasted costs.  

59 

15. The Commission Panel approves TGI’s Biomethane new Rate Schedules 1B, 11B, 2B and 3B and the proposed amendments to existing Rate Schedule 30 as well as requested changes to TGI’s General Terms and Conditions.  

61 

16. In addition, the Panel directs TGI to provide to the Commission any future proposed Biomethane Rate Schedules or amendments to schedules at least 60 days in advance of their proposed effective date.  

61 

 

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DATED at the City of Vancouver, in the Province of British Columbia, this    14th     day of December 2010.       ___Original signed by:         DENNIS A. COTE   PANEL CHAIR       ___Original signed by:         ALISON A. RHODES   COMMISSIONER       ___Original signed by:         LIISA A. O’HARA   COMMISSIONER   

                    

SIXTH FLOOR, 900 HOWE STREET, BOX 250 VANCOUVER, BC  V6Z 2N3   CANADA web site: http://www.bcuc.com 

    

  

         

TELEPHONE:  (604)  660‐4700 BC TOLL FREE:  1‐800‐663‐1385 FACSIMILE:  (604)  660‐1102 

…/2 

 BRIT I SH  COLUMBIA  

UTIL I T I ES  COMMISS ION      ORDER    NUMBER   G‐ 194‐10  

IN THE MATTER OF the Utilities Commission Act, R.S.B.C. 1996, Chapter 473 

 and  

Application by Terasen Gas Inc. for Approval of a Biomethane Service Offering and Supporting Business Model 

and for the Approval of the Salmon Arm Biomethane Project and  

for the Approval the Catalyst Biomethane Project    

BEFORE:  D.A. Cote, Panel Chair/Commissioner   A.A. Rhodes, Commissioner  December 14, 2010   L.A. O’Hara, Commissioner     

O  R  D  E  R WHEREAS: 

A. On June 8, 2010, Terasen Gas Inc. (Terasen Gas) filed an application (the Application) for approval of rate schedules, related deferral accounts, a cost recovery mechanism and a Biomethane Energy Recovery Charge to support a Biomethane Service Offering; 

B. The Application also sought approval of an expenditure schedule in respect of two Biomethane supply projects: the Salmon Arm Biomethane Project and the Catalyst Biomethane Project, and sought acceptance of the associated energy supply contracts; 

C. On June 23, 2010, the Commission issued Order G‐109‐10 establishing a Written Public Hearing Process and a Regulatory Timetable; 

D. The Commission has reviewed the Application, the evidence, and the submissions, and for the reasons set out in the Decision issued concurrently with this Order, concludes that the Application should be approved subject to certain additional terms and directives included in this Order and the Decision; 

   

        

2  

 

…/3 

 BRIT I SH  COLUMBIA  

UTIL IT I ES  COMMISS ION      ORDER    NUMBER   G‐ 194‐10  

NOW THEREFORE pursuant to the provisions of the Utilities Commission Act (the Act), the Commission orders as follows:  

1. The Commission approves Rates Schedules 1B, 2B, 3B, 11B, the amended Rate Schedule 30, and the amendments to Terasen Gas’ General Terms and Conditions described in Section 6 of the Application. 

2. The Commission will accept, subject to timely filing, the new Rate Schedules 1B, 11B, the amended Rate Schedule 30, and the amendments to Terasen Gas’ General Terms and Conditions, in accordance with this Order and the Decision. 

3. The Commission will accept for filing, on or after January 1, 2012, the new Rate Schedules 2B and 3B in accordance with this Order and the Decision. 

4. The cost allocations, deferral accounts, and accounting treatment for the costs associated with the Biomethane Program requested by Terasen Gas and described in Section 10 of the Application are approved as described in the accompanying Decision. 

5. Terasen Gas may purchase carbon offsets and recover the costs through the Biomethane Variance Account in the event of under‐supply of Biomethane, at a per gigajoule unit price not exceeding the difference between the Biomethane Energy Recovery Charge and the Commodity Cost Recovery Charge in effect at that time. 

6. The Biomethane Energy Recovery Charge is set at $9.904/GJ effective October 1, 2010. 

7. Pursuant to section 71 of the Act, the following energy supply contracts are accepted as filed: 

• the Purchase of Biogas Agreement with the Columbia Shushwap Regional District; and • the Purchase of Biogas Agreement with Catalyst Power Incorporated. 

8. Pursuant to subsection 44.2(3) of the Act, the following expenditures are in the public interest and are accepted: 

• the expenditures relating to the facilities required for the Salmon Arm Project; and • the expenditures relating to the facilities required for the Catalyst Project. 

9. Future Biomethane Program supply contracts for the purchase of biogas or Biomethane filed with the Commission that meet the criteria described in Section 8 of the Application (p. 80), with the following changes and additions, meet the filing requirements described in sections 71(1)(a) and 71(1)(b) of the Act : 

i. The total production of Biomethane from all projects undertaken under what has been approved in this Decision does not exceed an annual purchase of 250,000GJ;  

     

3 

Orders/G‐194‐10_TGI‐Biomethane Service Offering 

 BRIT I SH  COLUMBIA  

UTIL IT I ES  COMMISS ION      ORDER    NUMBER   G‐ 194‐10  

ii. The Maximum price for delivered Biomethane on the system is set at $15.28. 

10. Terasen Gas is directed to: 

• Maintain separate records of project costs related to Biomethane upgrading facilities to allow for cost comparisons to other upgrading operations; 

• Keep the Biomethane upgrading process sufficiently distinct so as to be severable should the Commission determine that this business ought to be conducted through a separate entity in the future; 

• Include in its next Revenue Requirements Application, in accordance with this Order and the Decision, details of costs for all deferral accounts created by this Order; 

• Provide to the Commission any future proposed Biomethane rate schedules, or amendments to schedules, at least 60 days in advance of their proposed effective date; 

• File a Post‐Implementation Report that provides the information described in Section 8.4.4 of the Application within 2 years of the date of this Order; 

• Hold a post‐implementation Workshop for the interveners in this proceeding and any interested stakeholders at which it will address the contents of the Post‐Implementation Report; and 

• Comply with all other directives in the Decision. 

DATED at the City of Vancouver, in the Province of British Columbia, this    14th       day of December, 2010. 

  BY ORDER    Original signed by:    D.A. Cote   Panel Chair/Commissioner 

APPENDIX A Page 1 of 3 

  

APPROVALS SOUGHT  Rate Related Orders  1.  An order pursuant to sections 59‐61 of the Act approving:  

(a) the new Rate Schedules 1B, 11B, and the amendments to Rate Schedule 30;  

(b) the new Rate Schedules 2B and 3B effective upon filing of the rate schedules with the Commission, but in any event not before January 1, 2012; 

 (c) the proposed amendments to Terasen Gas’ General Terms and Conditions, specifically, the 

addition of new definitions relating to the Biomethane Service, and the introduction of a Section 28 – Biomethane Service. 

  Cost Recovery Related Orders (All Customers)  2.  An order pursuant to sections 59‐61 of the Act approving:  

(a) the allocation of costs to all customers and the accounting treatment of those costs as described in Section 10 of the Application. 

 (b) a non‐rate base deferral account attracting AFUDC to capture the O&M costs applicable to 

all customers incurred prior to January 1, 2012, and to recover these costs from all non‐bypass customers by amortizing them through delivery rates commencing January 1, 2012 over a three year period. 

 (c) a non‐rate base deferral account to capture the cost of service associated with the capital 

additions to the delivery system incurred prior to January 1, 2012, and to recover these costs from all non‐bypass customers by amortizing them through delivery rates commencing January 1, 2012 over a three year period. 

  Cost Recovery Related Orders  3.  An order pursuant to sections 59‐61 of the Act approving:  

(a) the allocation of costs to Biomethane Program customers and the accounting treatment of those costs as described in Section 10.6 of the Application. 

   

APPENDIX A Page 2 of 3  

(b) the cost recovery methodology applicable to Biogas processing related assets.  

(c) a rate base deferral account to capture the costs incurred by Terasen Gas to procure and process consumable Biomethane gas and the revenues collected through the Biomethane energy recovery component of rates, and thereby accumulate any differences (the “Biomethane Variance Account”). 

 (d) the Biomethane Variance Account balance quarterly reporting process and the Biomethane 

Energy Recovery Charge rate setting mechanism on a basis consistent with the Company’s existing gas cost reporting and rate setting mechanisms, as described in Section 10.7 of the Application. 

 (e) Terasen Gas purchasing carbon offsets and recovering the costs through the Biomethane 

Variance Account in the event of under‐supply of Biomethane, at a per gigajoule unit price not to exceed the difference between the Biomethane Energy Recovery Charge and the Commodity Cost Recovery Charge in effect at that time. 

 (f) the Biomethane Energy Recovery Charge at $9.904/GJ effective October 1, 2010. 

  Supply Project Related Orders  4.  An order pursuant to section 71 of the Act accepting as filed:  

(a) the Purchase of Biogas Agreement with the CSRD; and  

(b) the Purchase of Biogas Agreement with Catalyst Power Incorporated.  5.  An order pursuant to section 44.2 of the Act that the following capital expenditures are 

accepted by the Commission and are in the public interest:  

(a) The expenditures relating to the facilities required for the Salmon Arm Project described at Table 9‐1 of the Application; and 

 (b) The expenditures relating to the facilities required for the Catalyst Project described at 

Table 9‐4 of the Application.  6.  An order that future supply contracts for the purchase of Biogas or Biomethane filed with the 

Commission that meet the criteria described in Section 8.4, meet the filing requirements in sections 71(1)(a) and 71(1)(b) of the Act.

APPENDIX A Page 3 of 3 

  Post‐Implementation Review Orders  7.  A direction that Terasen Gas, within 5 years of the date of this order:  

(a) file a Post‐implementation Report that provides the information described in Section 8.4.4 of the Application; and 

 (b) hold a Post‐implementation Workshop, to be attended by Terasen Gas, and any interested 

stakeholders and interveners, at which Terasen Gas will address the contents of the Post‐implementation Report. 

  

APPENDIX B Page 1 of 1 

 THE REGULATORY PROCESS 

 By Order G‐109‐10 dated June 24, 2010, the Commission established a written hearing process and the following Timetable.  

ACTION   DATE (2010) 

Workshop  Thursday, June 24

Intervener Registration Deadline  Monday, July 5

Commission Information Request No. 1  Friday, July 16

Intervener Information Requests No. 1  Friday, July 23

Terasen Responses to Information Requests No. 1  Friday, August 6

Commission Information Request No. 2  Friday, August 20

Intervener Information Requests No. 2  Monday, August 23

Terasen Response to Information Requests No. 2  Friday, September 3

Terasen Written Final Submission  Friday, September 10

Intervener Written Final Submissions  Monday, September 20

Terasen Written Reply Submission  Tuesday, September 28

Oral Argument (if Required)  Friday, October 8

 The Commission received Final Submissions from:  

• Terasen on September 10, 2010 

• CEC on September 20, 2010 

• BC Hydro on September 20, 2010 

• BCSEA on September 20, 2010 

• BCOAPO on September 21, 2010 

 Terasen submitted its Reply Submission responding to final submissions of CEC, BC Hydro, BCSEA and BCOAPO on September 27, 2010.  

APPENDIX C Page 1 of 4 

  

IN THE MATTER OF the Utilities Commission Act, R.S.B.C. 1996, Chapter 473 

 and  

Terasen Gas Inc. Application for Approval of a Biomethane Service Offering, 

Supporting Business Model, for the Approval of the Salmon Arm Biomethane Project and for the Approval the Catalyst Biomethane Project 

EXHIBIT LIST 

 Exhibit No.  Description  COMMISSION DOCUMENTS  A‐1  Letter dated June 10, 2010 – Commission comments on the Application and Notice 

of Workshop  

A‐2  Letter dated June 24, 2010 – Regulatory Timetable 

A‐3  Letter dated June 25, 2010 – Appointment of Commission Panel 

A‐4  Letter dated July 5, 2010 – Release of Confidential Application Documents to BC Bioenergy Network 

A‐5  Letter dated July 16, 2010 – Commission Information Request No. 1 

A‐6  Letter dated August 20, 2010 – Commission Information Request No. 2 

A‐7  Letter dated October 4, 2010 – Cancellation of Oral Argument scheduled for Friday, October 8, 2010 

 APPLICANT DOCUMENTS TGI  B‐1  TERASEN GAS INC.  (TGI) Letter Dated June 8, 2010 ‐ Application for Approval of a 

Biomethane Service Offering and Supporting Business Model, for the Approval of the Salmon Arm Biomethane Project and for the Approval the Catalyst Biomethane Project  

B‐1‐1  Letter dated June 23, 2010 – Filing errata to the application 

APPENDIX C Page 2 of 4  Exhibit No.  Description  B‐1‐2  Confidential Letter dated June 8, 2010 – TGI  CONFIDENTIAL Appendices I J‐3 to the 

Application  

B‐1‐3  Confidential Letter dated September 1, 2010 ‐ TGI  CONFIDENTIAL Contract Amendment to Confidential Appendix I‐2  

B‐2  Letter dated June 25, 2010 ‐ Workshop Presentation Materials  

B‐2‐1  Letter dated July 8, 2010 – Response to Workshop Undertaking 

B‐3  Letter dated August 6, 2010 ‐ TGI Response to BCUC IR No. 1  

B‐3‐1  CONFIDENTIAL Letter dated August 6, 2010 ‐ TGI CONFIDENTIAL Response to BCUC IR No. 1  

B‐4  Letter dated August 6, 2010 ‐ TGI Response to BCOAPO IR No. 1 

B‐4‐1  CONFIDENTIAL Letter dated August 6, 2010 ‐ TGI CONFIDENTIAL Response to BCOAPO IR No. 1  

B‐5  Letter dated August 6, 2010 ‐ TGI Response to BCSEA IR No. 1 

B‐5‐1  CONFIDENTIAL Letter dated August 6, 2010 ‐ TGI CONFIDENTIAL Response to BCSEA IR No. 1  

B‐6  Letter dated August 6, 2010 ‐ TGI Response to CEC IR No. 1 

B‐7  Letter dated August 17, 2010 ‐ TGI Response to BCSEA IR No1.20.2 

B‐8  Letter dated August 17, 2010 ‐ TGI Response to CEC IR No1.10.1‐2 

B‐9  Letter dated August 17, 2010 ‐ TGI Response to BCUC IR No. 1 Attachment 43.1.6 Redacted  

B‐10  Letter dated September 2, 2010 – TGI Response to BCUC IR No. 2 

B‐11  Letter dated September 2, 2010 – TGI Response to BCOAPO IR No. 2 

B‐12  Letter dated September 2, 2010 – TGI Response to BCSEA IR No. 2 

B‐13  Letter dated September 2, 2010 – TGI Response to CEC IR No. 2 

 

APPENDIX C Page 3 of 4 

 Exhibit No.  Description  INTERVENER DOCUMENTS  C1‐1  CATALYST POWER INC. (CP) Online registration dated June 16, 2010 – Requesting 

Intervener status by Christopher Bush 

C2‐1  BC AGRICULTURE COUNCIL (BCAC) Online registration dated June 16, 2010 – Requesting Intervener status by Mathew Dickson 

C3‐1  BC BIOENERGY NETWORK (BCBN) Online registration dated June 23, 2010 – Requesting Intervener status by Sandy Ferguson 

C3‐2  Letter dated June 23, 2010 – BCBN Filing Undertaking of Confidentiality by Sandra Ferguson 

C3‐3  Letter dated June 23, 2010 – BCBN Filing Undertaking of Confidentiality by Michael Weedon 

C3‐4  Online registration dated June 24, 2010 – BCBN addition of  Michael Weedon  

C4‐1  BRITISH COLUMBIA HYDRO AND POWER AUTHORITY (BC HYDRO) ‐ Online registration dated June 23, 2010 – Requesting Intervener status by Tatiana Noskova 

C5‐1  BRITISH COLUMBIA OLD AGE PENSIONERS’ ORGANIZATION (BCOAPO) VIA EMAIL  Letter Dated June 23, 2010  ‐ Request for Intervener Status by Jim Quail and James Wightman 

C5‐2  Letter Dated July 23, 2010  ‐ BCOAPO Information Request No. 1 

C5‐3  Letter Dated August 23, 2010  ‐ BCOAPO Information Request No. 2 

C6‐1 

 

ELEMENTAL ENERGY INC. (EEI) ‐ Online registration dated June 25, 2010 – Requesting Intervener status by Richard Hopp 

C7‐1  

COMMERCIAL ENERGY CONSUMERS ASSOCIATION (CEC)‐Letter dated June 29, 2010 – Requesting Intervener Status 

C7‐2  Letter Dated July 23, 2010  ‐ CEC Information Request No. 1 

C7‐3  Letter Dated August 23, 2010  ‐ CEC Information Request No. 2 

C8‐1  

BC SUSTAINABLE ENERGY ASSOCIATION (BCSEA)‐Letter dated July 5, 2010 – Requesting Intervener Status 

C8‐2  Letter dated July 7, 2010 – Advising that W.J. Andrews to serve as their counsel  

C8‐3  Letter Dated July 21, 2010  ‐ BCSEA Information Request No. 1 

APPENDIX C Page 4 of 4  Exhibit No.  Description  C8‐4  Letter Dated August 23, 2010  ‐  BCSEA Information Request No. 2 

C9‐1  BP CANADA ENERGY COMPANY (BPE) Online registration dated July 6, 2010 – Requesting Intervener status by Cheryl Worthy 

 INTERESTED PARTY DOCUMENTS  D‐1  UNION GAS LIMITED (UGL) Online registration dated June 16, 2010 ‐ Request for 

Interested Party Status by Patrick McMahon 

D‐2  FLOTECH SERVICES NA, LTD (FLOTECH) Online registration dated June 17, 2010 ‐ Request for Interested Party Status by Sean Mezei 

D‐3  ENBRIDGE GAS DISTRIBUTION INC. Online registration dated June 17, 2010 ‐ Request for Interested Party Status by Lesley Austin 

D‐4  LIFE SCIENCES BC (LSBC) Online registration dated June 24, 2010 ‐ Request for Interested Party Status by Bob Ingratta 

D‐5  MANITOBA HYDRO (MH) Online registration dated June 29, 2010 ‐ Request for Interested Party Status by Ashley Jansen 

 LETTERS OF COMMENT  E‐1  MINISTRY OF ENERGY, MINES AND PETROLEUM RESOURCES – Letter dated August 3, 2010 

supporting TGI’s Application  

   

 

APPENDIX D Page 1 of 2 

 LIST OF ACRONYMS 

 BCBN   BC Bioenergy Network  

BCOAPO  BC Old Age Pensioners’ Organization, BC Coalition of People with Disabilities, Council of Senior Citizens’ Organizations of BC, federated anti‐poverty groups of BC, and Tenant Resource and Advisory Centre 

BCSEA  BC Sustainable Energy Association 

BERC  Biomethane Energy Recovery Charge 

BVA  Biomethane Variance Account 

BC  British Columbia 

BC Hydro  British Columbia Hydro and Power Authority 

Commission, BCUC  British Columbia Utilities Commission 

CEA  Clean Energy Act 

CEC  Commercial Energy Consumers Association of British Columbia 

Catalyst  Catalyst Power Incorporated  

CSRD  Columbia Shuswap Regional District 

COS  cost of service 

CWLP  Customer Works LP 

DGE  Dockside Green Energy 

GHG  Greenhouse Gas 

GJ  gigajoule 

ICE  Innovative Clean Energy 

IT  Information and Technology 

NREL  National Renewable Energy Laboratory 

O & M  Operating and Maintenance 

APPENDIX D Page 2 of 2  PJ  petajoule 

RIB  Residential Inclining Block 

RRA  Revenue Requirements Application 

SEFCDES  South East False Creek District Energy System 

Terasen, TGI or the Company  Terasen Gas Inc. 

the Act or UCA  Utilities Commission Act 

  

APPENDIX E Page 1 of 6 

 

 

 SECTIONS OF UTILITIES COMMISSION ACT 

 

Section 44.2 states: Expenditure schedule 

44.2  (1) A public utility may file with the commission an expenditure schedule containing 

one or more of the following: 

(a) a statement of the expenditures on demand‐side measures the public utility has made or 

anticipates making during the period addressed by the schedule; 

(b) a statement of capital expenditures the public utility has made or anticipates making 

during the period addressed by the schedule; 

(c) a statement of expenditures the public utility has made or anticipates making during the 

period addressed by the schedule to acquire energy from other persons. 

(2) The commission may not consent under section 61 (2) to an amendment to or a 

rescission of a schedule filed under section 61 (1) to the extent that the amendment 

or the rescission is for the purpose of recovering expenditures referred to in 

subsection (1) (a) of this section, unless 

(a) the expenditure is the subject of a schedule filed and accepted under this section, or 

(b) the amendment or rescission is for the purpose of setting an interim rate. 

(3) After reviewing an expenditure schedule submitted under subsection (1), the 

commission, subject to subsections (5), (5.1) and (6), must 

(a) accept the schedule, if the commission considers that making the expenditures referred 

to in the schedule would be in the public interest, or 

(b) reject the schedule. 

(4) The commission may accept or reject, under subsection (3), a part of a schedule. 

(5) In considering whether to accept an expenditure schedule filed by a public utility other 

than the authority, the commission must consider 

(a) the applicable of British Columbia's energy objectives,  

APPENDIX E Page 2 of 6  

 

(b) the most recent long‐term resource plan filed by the public utility under section 44.1, if 

any, 

(c) the extent to which the plan is consistent with the applicable requirements under 

sections 6 and 19 of the Clean Energy Act, 

(d) if the schedule includes expenditures on demand‐side measures, whether the demand‐

side measures are cost‐effective within the meaning prescribed by regulation, if any, 

and 

(e) the interests of persons in British Columbia who receive or may receive service from the 

public utility. 

(5.1) In considering whether to accept an expenditure schedule filed by the authority, the 

commission, in addition to considering the interests of persons in British Columbia 

who receive or may receive service from the authority, must consider and be guided 

by 

(a) British Columbia's energy objectives, 

(b) an applicable integrated resource plan approved under section 4 of the Clean Energy 

Act, 

(c) the extent to which the schedule is consistent with the requirements under section 19 of 

the Clean Energy Act, and 

(d) if the schedule includes expenditures on demand‐side measures, the extent to which the 

demand‐side measures are cost‐effective within the meaning prescribed by 

regulation, if any. 

(6) If the commission considers that an expenditure in an expenditure schedule was 

determined to be in the public interest in the course of determining that a long‐term 

resource plan was in the public interest under section 44.1 (6), 

(a) subsection (5) of this section does not apply with respect to that expenditure, and 

(b) the commission must accept under subsection (3) the expenditure in the expenditure 

schedule.  

APPENDIX E Page 3 of 6 

 

 

Section 59 states: Discrimination in rates 

59  (1) A public utility must not make, demand or receive 

(a) an unjust, unreasonable, unduly discriminatory or unduly preferential rate for a 

service provided by it in British Columbia, or 

(b) a rate that otherwise contravenes this Act, the regulations, orders of the 

commission or any other law. 

(2) A public utility must not 

(a) as to rate or service, subject any person or locality, or a particular description of 

traffic, to an undue prejudice or disadvantage, or 

(b) extend to any person a form of agreement, a rule or a facility or privilege, unless 

the agreement, rule, facility or privilege is regularly and uniformly extended to all 

persons under substantially similar circumstances and conditions for service of the 

same description. 

(3) The commission may, by regulation, declare the circumstances and conditions that 

are substantially similar for the purpose of subsection (2) (b). 

(4) It is a question of fact, of which the commission is the sole judge, 

(a) whether a rate is unjust or unreasonable, 

(b) whether, in any case, there is undue discrimination, preference, prejudice or 

disadvantage in respect of a rate or service, or 

(c) whether a service is offered or provided under substantially similar circumstances 

and conditions. 

(5) In this section, a rate is "unjust" or "unreasonable" if the rate is 

(a) more than a fair and reasonable charge for service of the nature and quality 

provided by the utility,  

APPENDIX E Page 4 of 6  

 

(b) insufficient to yield a fair and reasonable compensation for the service provided 

by the utility, or a fair and reasonable return on the appraised value of its property, 

or 

(c) unjust and unreasonable for any other reason.  

Section 60 states: Setting of rates 

60  (1) In setting a rate under this Act 

(a) the commission must consider all matters that it considers proper and relevant 

affecting the rate, 

(b) the commission must have due regard to the setting of a rate that 

(i)  is not unjust or unreasonable within the meaning of section 59, 

(ii)  provides to the public utility for which the rate is set a fair and reasonable 

return on any expenditure made by it to reduce energy demands, and 

(iii)  encourages public utilities to increase efficiency, reduce costs and enhance 

performance, 

(b.1) the commission may use any mechanism, formula or other method of setting 

the rate that it considers advisable, and may order that the rate derived from such a 

mechanism, formula or other method is to remain in effect for a specified period, 

and 

(c) if the public utility provides more than one class of service, the commission must 

(i)  segregate the various kinds of service into distinct classes of service, 

(ii)  in setting a rate to be charged for the particular service provided, consider 

each distinct class of service as a self contained unit, and 

(iii)  set a rate for each unit that it considers to be just and reasonable for that 

unit, without regard to the rates fixed for any other unit.  

APPENDIX E Page 5 of 6 

 

 

(2) In setting a rate under this Act, the commission may take into account a distinct or 

special area served by a public utility with a view to ensuring, so far as the commission 

considers it advisable, that the rate applicable in each area is adequate to yield a fair 

and reasonable return on the appraised value of the plant or system of the public utility 

used, or prudently and reasonably acquired, for the purpose of providing the service in 

that special area. 

(3) If the commission takes a special area into account under subsection (2), it must 

have regard to the special considerations applicable to an area that is sparsely settled or 

has other distinctive characteristics. 

(4) For this section, the commission must exclude from the appraised value of the 

property of the public utility any franchise, licence, permit or concession obtained or 

held by the utility from a municipal or other public authority beyond the money, if any, 

paid to the municipality or public authority as consideration for that franchise, licence, 

permit or concession, together with necessary and reasonable expenses in procuring the 

franchise, licence, permit or concession.   Section 61 states: 

Rate schedules to be filed with commission 

61  (1) A public utility must file with the commission, under rules the commission specifies 

and within the time and in the form required by the commission, schedules showing 

all rates established by it and collected, charged or enforced or to be collected or 

enforced. 

(2) A schedule filed under subsection (1) must not be rescinded or amended without 

the commission's consent. 

(3) The rates in schedules as filed and as amended in accordance with this Act and the 

regulations are the only lawful, enforceable and collectable rates of the public utility 

filing them, and no other rate may be collected, charged or enforced.  

APPENDIX E Page 6 of 6  

 

(4) A public utility may file with the commission a new schedule of rates that the utility 

considers to be made necessary by a rise in the price, over which the utility has no 

effective control, required to be paid by the public utility for its gas supplies, other 

energy supplied to it, or expenses and taxes, and the new schedule may be put into 

effect by the public utility on receiving the approval of the commission. 

(5) Within 60 days after the date it approves a new schedule under subsection (4), the 

commission may, 

(a) on complaint of a person whose interests are affected, or 

(b) on its own motion, 

direct an inquiry into the new schedule of rates having regard to the fixing of a rate 

that is not unjust or unreasonable.  

(6) After an inquiry under subsection (5), the commission may 

(a) rescind or vary the increase and order a refund or customer credit by the utility of 

all or part of the money received by way of increase, or 

(b) confirm the increase or part of it.  

SUPREME COURT OF CANADA

CITATION: ATCO Gas & Pipelines Ltd. v. Alberta (Energy &Utilities Board), [2006] 1 S.C.R. 140, 2006 SCC 4

DATE: 20060209DOCKET: 30247

BETWEEN:City of Calgary

Appellant/Respondent on cross-appealv.

ATCO Gas and Pipelines Ltd.Respondent/Appellant on cross-appeal

- and -Alberta Energy and Utilities Board,

Ontario Energy Board, Enbridge GasDistribution Inc. and Union Gas Limited

Interveners

CORAM: McLachlin C.J. and Bastarache, Binnie, LeBel, Deschamps, Fish and Charron JJ.

REASONS FOR JUDGMENT: (paras. 1 to 87)

DISSENTING REASONS:(paras. 88 to 149)

Bastarache J. (LeBel, Deschamps and Charron JJ.concurring)

Binnie J. (McLachlin C.J. and Fish J. concurring)

______________________________

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ATCO Gas and Pipelines Ltd. v. Alberta (Energy and Utilities Board), [2006] 1 S.C.R.

140, 2006 SCC 4

City of Calgary Appellant/Respondent on cross-appeal

v.

ATCO Gas and Pipelines Ltd. Respondent/Appellant on cross-appeal

and

Alberta Energy and Utilities Board, Ontario Energy Board, Enbridge Gas Distribution Inc. and Union Gas Limited Interveners

Indexed as: ATCO Gas and Pipelines Ltd. v. Alberta (Energy and Utilities Board)

Neutral citation: 2006 SCC 4.

File No.: 30247.

2005: May 11; 2006: February 9.

Present: McLachlin C.J. and Bastarache, Binnie, LeBel, Deschamps, Fish andCharron JJ.

on appeal from the court of appeal for alberta

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Administrative law — Boards and tribunals — Regulatory boards —

Jurisdiction — Doctrine of jurisdiction by necessary implication — Natural gas public

utility applying to Alberta Energy and Utilities Board to approve sale of buildings and

land no longer required in supplying natural gas — Board approving sale subject to

condition that portion of sale proceeds be allocated to ratepaying customers of utility

— Whether Board had explicit or implicit jurisdiction to allocate proceeds of sale — If

so, whether Board’s decision to exercise discretion to protect public interest by

allocating proceeds of utility asset sale to customers reasonable — Alberta Energy and

Utilities Board Act, R.S.A. 2000, c. A-17, s. 15(3) — Public Utilities Board Act, R.S.A.

2000, c. P-45, s. 37 — Gas Utilities Act, R.S.A. 2000, c. G-5, s. 26(2).

Administrative law — Judicial review — Standard of review — Alberta

Energy and Utilities Board — Standard of review applicable to Board’s jurisdiction to

allocate proceeds from sale of public utility assets to ratepayers — Standard of review

applicable to Board’s decision to exercise discretion to allocate proceeds of sale —

Alberta Energy and Utilities Board Act, R.S.A. 2000, c. A-17, s. 15(3) — Public Utilities

Board Act, R.S.A. 2000, c. P-45, s. 37 — Gas Utilities Act, R.S.A. 2000, c. G-5, s. 26(2).

ATCO is a public utility in Alberta which delivers natural gas. A division

of ATCO filed an application with the Alberta Energy and Utilities Board for approval

of the sale of buildings and land located in Calgary, as required by the Gas Utilities Act

(“GUA”). According to ATCO, the property was no longer used or useful for the

provision of utility services, and the sale would not cause any harm to ratepaying

customers. ATCO requested that the Board approve the sale transaction, as well as the

proposed disposition of the sale proceeds: to retire the remaining book value of the sold

assets, to recover the disposition costs, and to recognize that the balance of the profits

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resulting from the sale should be paid to ATCO’s shareholders. The customers’ interests

were represented by the City of Calgary, who opposed ATCO’s position with respect to

the disposition of the sale proceeds to shareholders.

Persuaded that customers would not be harmed by the sale, the Board

approved the sale transaction on the basis that customers would not “be exposed to the

risk of financial harm as a result of the Sale that could not be examined in a future

proceeding”. In a second decision, the Board determined the allocation of net sale

proceeds. The Board held that it had the jurisdiction to approve a proposed disposition

of sale proceeds subject to appropriate conditions to protect the public interest, pursuant

to the powers granted to it under s. 15(3) of the Alberta Energy and Utilities Board Act

(“AEUBA”). The Board applied a formula which recognizes profits realized when

proceeds of sale exceed the original cost can be shared between customers and

shareholders, and allocated a portion of the net gain on the sale to the ratepaying

customers. The Alberta Court of Appeal set aside the Board’s decision, referring the

matter back to the Board to allocate the entire remainder of the proceeds to ATCO.

Held (McLachlin C.J. and Binnie and Fish JJ. dissenting): The appeal is

dismissed and the cross-appeal is allowed.

Per Bastarache, LeBel, Deschamps and Charron JJ.: When the relevant

factors of the pragmatic and functional approach are properly considered, the standard

of review applicable to the Board’s decision on the issue of jurisdiction is correctness.

Here, the Board did not have the jurisdiction to allocate the proceeds of the sale of the

utility’s asset. The Court of Appeal made no error of fact or law when it concluded that

the Board acted beyond its jurisdiction by misapprehending its statutory and common

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law authority. However, the Court of Appeal erred when it did not go on to conclude

that the Board has no jurisdiction to allocate any portion of the proceeds of sale of the

property to ratepayers. [21-34]

The interpretation of the AEUBA, the Public Utilities Board Act (“PUBA”)

and the GUA can lead to only one conclusion: the Board does not have the prerogative

to decide on the distribution of the net gain from the sale of assets of a utility. On their

grammatical and ordinary meaning, s. 26(2) GUA, s. 15(3) AEUBA and s. 37 PUBA are

silent as to the Board’s power to deal with sale proceeds. Section 26(2) GUA conferred

on the Board the power to approve a transaction without more. The intended meaning

of the Board’s power pursuant to s. 15(3) AEUBA to impose conditions on an order that

the Board considers necessary in the public interest, as well as the general power in s. 37

PUBA, is lost when the provisions are read in isolation. They are, on their own, vague

and open-ended. It would be absurd to allow the Board an unfettered discretion to attach

any condition it wishes to any order it makes. While the concept of “public interest” is

very wide and elastic, the Board cannot be given total discretion over its limitations.

These seemingly broad powers must be interpreted within the entire context of the

statutes which are meant to balance the need to protect consumers as well as the property

rights retained by owners, as recognized in a free market economy. The context

indicates that the limits of the Board’s powers are grounded in its main function of fixing

just and reasonable rates and in protecting the integrity and dependability of the supply

system. [7] [41] [43] [46]

An examination of the historical background of public utilities regulation in

Alberta generally, and the legislation in respect of the powers of the Alberta Energy and

Utilities Board in particular, reveals that nowhere is there a mention of the authority for

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the Board to allocate proceeds from a sale or the discretion of the Board to interfere with

ownership rights. Moreover, although the Board may seem to possess a variety of

powers and functions, it is manifest from a reading of the AEUBA, the PUBA and the

GUA that the principal function of the Board in respect of public utilities, is the

determination of rates. Its power to supervise the finances of these companies and their

operations, although wide, is in practice incidental to fixing rates. The goals of

sustainability, equity and efficiency, which underlie the reasoning as to how rates are

fixed, have resulted in an economic and social arrangement which ensures that all

customers have access to the utility at a fair price — nothing more. The rates paid by

customers do not incorporate acquiring ownership or control of the utility’s assets. The

object of the statutes is to protect both the customer and the investor, and the Board’s

responsibility is to maintain a tariff that enhances the economic benefits to consumers

and investors of the utility. This well-balanced regulatory arrangement does not,

however, cancel the private nature of the utility. The fact that the utility is given the

opportunity to make a profit on its services and a fair return on its investment in its

assets should not and cannot stop the utility from benefiting from the profits which

follow the sale of assets. Neither is the utility protected from losses incurred from the

sale of assets. The Board misdirected itself by confusing the interests of the customers

in obtaining safe and efficient utility service with an interest in the underlying assets

owned only by the utility. [54-69]

Not only is the power to allocate the proceeds of the sale absent from the

explicit language of the legislation, but it cannot be implied from the statutory regime

as necessarily incidental to the explicit powers. For the doctrine of jurisdiction by

necessary implication to apply, there must be evidence that the exercise of that power

is a practical necessity for the Board to accomplish the objects prescribed by the

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legislature, something which is absent in this case. Not only is the authority to attach a

condition to allocate the proceeds of a sale to a particular party unnecessary for the

Board to accomplish its role, but deciding otherwise would lead to the conclusion that

broadly drawn powers, such as those found in the AEUBA, the GUA and the PUBA, can

be interpreted so as to encroach on the economic freedom of the utility, depriving it of

its rights. If the Alberta legislature wishes to confer on ratepayers the economic benefits

resulting from the sale of utility assets, it can expressly provide for this in the legislation.

[39] [77-80]

Notwithstanding the conclusion that the Board lacked jurisdiction, its

decision to exercise its discretion to protect the public interest by allocating the sale

proceeds as it did to ratepaying customers did not meet a reasonable standard. When it

explicitly concluded that no harm would ensue to customers from the sale of the asset,

the Board did not identify any public interest which required protection and there was,

therefore, nothing to trigger the exercise of the discretion to allocate the proceeds of sale.

Finally, it cannot be concluded that the Board’s allocation was reasonable when it

wrongly assumed that ratepayers had acquired a proprietary interest in the utility’s assets

because assets were a factor in the rate-setting process. [82-85]

Per McLachlin C.J. and Binnie and Fish JJ. (dissenting): The Board’s

decision should be restored. Section 15(3) AEUBA authorized the Board, in dealing

with ATCO’s application to approve the sale of the subject land and buildings, to

“impose any additional conditions that the Board considers necessary in the public

interest”. In the exercise of that authority, and having regard to the Board’s “general

supervision over all gas utilities, and the owners of them” pursuant to s. 22(1) GUA, the

Board made an allocation of the net gain for public policy reasons. The Board’s

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discretion is not unlimited and must be exercised in good faith for its intended purpose.

Here, in allocating one third of the net gain to ATCO and two thirds to the rate base, the

Board explained that it was proper to balance the interests of both shareholders and

ratepayers. In the Board’s view to award the entire gain to the ratepayers would deny

the utility an incentive to increase its efficiency and reduce its costs, but on the other

hand to award the entire gain to the utility might encourage speculation in

non-depreciable property or motivate the utility to identify and dispose of properties

which have appreciated for reasons other than the best interest of the regulated business.

Although it was open to the Board to allow ATCO’s application for the entire profit, the

solution it adopted in this case is well within the range of reasonable options. The

“public interest” is largely and inherently a matter of opinion and discretion. While the

statutory framework of utilities regulation varies from jurisdiction to jurisdiction,

Alberta’s grant of authority to its Board is more generous than most. The Court should

not substitute its own view of what is “necessary in the public interest”. The Board’s

decision made in the exercise of its jurisdiction was within the range of established

regulatory opinion, whether the proper standard of review in that regard is patent

unreasonableness or simple reasonableness. [91-92] [98-99] [110] [113] [122] [148]

ATCO’s submission that an allocation of profit to the customers would

amount to a confiscation of the corporation’s property overlooks the obvious difference

between investment in an unregulated business and investment in a regulated utility

where the ratepayers carry the costs and the regulator sets the return on investment, not

the marketplace. The Board’s response cannot be considered “confiscatory” in any

proper use of the term, and is well within the range of what is regarded in comparable

jurisdictions as an appropriate regulatory allocation of the gain on sale of land whose

original investment has been included by the utility itself in its rate base. Similarly,

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ATCO’s argument that the Board engaged in impermissible retroactive rate making

should not be accepted. The Board proposed to apply a portion of the expected profit

to future rate making. The effect of the order is prospective not retroactive. Fixing the

going-forward rate of return, as well as general supervision of “all gas utilities, and the

owners of them”, were matters squarely within the Board’s statutory mandate. ATCO

also submits in its cross-appeal that the Court of Appeal erred in drawing a distinction

between gains on sale of land whose original cost is not depreciated and depreciated

property, such as buildings. A review of regulatory practice shows that many, but not

all, regulators reject the relevance of this distinction. The point is not that the regulator

must reject any such distinction but, rather, that the distinction does not have the

controlling weight as contended by ATCO. In Alberta, it is up to the Board to determine

what allocations are necessary in the public interest as conditions of the approval of sale.

Finally, ATCO’s contention that it alone is burdened with the risk on land that declines

in value overlooks the fact that in a falling market the utility continues to be entitled to

a rate of return on its original investment, even if the market value at the time is

substantially less than its original investment. Further, it seems such losses are taken

into account in the ongoing rate-setting process. [93] [123-147]

Cases Cited

By Bastarache J.

Referred to: Re ATCO Gas-North, Alta. E.U.B., Decision 2001-65, July 31,

2001; TransAlta Utilities Corp. v. Public Utilities Board (Alta.) (1986), 68 A.R. 171;

Re TransAlta Utilities Corp., Alta. E.U.B., Decision 2000-41, July 5, 2000;

Pushpanathan v. Canada (Minister of Citizenship and Immigration), [1998] 1 S.C.R.

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982; United Taxi Drivers’ Fellowship of Southern Alberta v. Calgary (City), [2004] 1

S.C.R. 485, 2004 SCC 19; Consumers’ Gas Co. v. Ontario (Energy Board), [2001] O.J.

No. 5024 (QL); Coalition of Citizens Impacted by the Caroline Shell Plant v. Alberta

(Energy Utilities Board) (1996), 41 Alta. L.R. (3d) 374; Atco Ltd. v. Calgary Power Ltd.,

[1982] 2 S.C.R. 557; Dome Petroleum Ltd. v. Public Utilities Board (Alberta) (1976),

2 A.R. 453, aff’d [1977] 2 S.C.R. 822; Barrie Public Utilities v. Canadian Cable

Television Assn., [2003] 1 S.C.R. 476, 2003 SCC 28; Rizzo & Rizzo Shoes Ltd. (Re),

[1998] 1 S.C.R. 27; Bell ExpressVu Limited Partnership v. Rex, [2002] 2 S.C.R. 559,

2002 SCC 42; H.L. v. Canada (Attorney General), [2005] 1 S.C.R. 401, 2005 SCC 25;

Marche v. Halifax Insurance Co., [2005] 1 S.C.R. 47, 2005 SCC 6; Contino v.

Leonelli-Contino, [2005] 3 S.C.R. 217, 2005 SCC 63; Re Alberta Government

Telephones, Alta. P.U.B., Decision No. E84081, June 29, 1984; Re TransAlta Utilities

Corp., Alta. P.U.B., Decision No. E84116, October 12, 1984; TransAlta Utilities Corp.

(Re), [2002] A.E.U.B.D. No. 30 (QL); ATCO Electric Ltd. (Re), [2003] A.E.U.B.D.

No. 92 (QL); Canadian Pacific Air Lines Ltd. v. Canadian Air Line Pilots Assn., [1993]

3 S.C.R. 724; Bristol-Myers Squibb Co. v. Canada (Attorney General), [2005] 1 S.C.R.

533, 2005 SCC 26; Chieu v. Canada (Minister of Citizenship and Immigration), [2002]

1 S.C.R. 84, 2002 SCC 3; Bell Canada v. Canada (Canadian Radio-Television and

Telecommunications Commission), [1989] 1 S.C.R. 1722; R. v. McIntosh, [1995] 1

S.C.R. 686; Re Dow Chemical Canada Inc. and Union Gas Ltd. (1982), 141 D.L.R. (3d)

641, aff’d (1983), 42 O.R. (2d) 731; Interprovincial Pipe Line Ltd. v. National Energy

Board, [1978] 1 F.C. 601; Canadian Broadcasting League v. Canadian Radio-television

and Telecommunications Commission, [1983] 1 F.C. 182, aff’d [1985] 1 S.C.R. 174;

Northwestern Utilities Ltd. v. City of Edmonton, [1929] S.C.R. 186; Northwestern

Utilities Ltd. v. City of Edmonton, [1979] 1 S.C.R. 684; Re Canadian Western Natural

Gas Co., Alta. P.U.B., Decision No. E84113, October 12, 1984; Re Union Gas Ltd. and

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Ontario Energy Board (1983), 1 D.L.R. (4th) 698; Duquesne Light Co. v. Barasch, 488

U.S. 299 (1989); Market St. Ry. Co. v. Railroad Commission of State of California, 324

U.S. 548 (1945); Re Coseka Resources Ltd. and Saratoga Processing Co. (1981), 126

D.L.R. (3d) 705, leave to appeal refused, [1981] 2 S.C.R. vii; Re Consumers’ Gas Co.,

E.B.R.O. 410-II, 411-II, 412-II, March 23, 1987; National Energy Board Act (Can.) (Re),

[1986] 3 F.C. 275; Pacific National Investments Ltd. v. Victoria (City), [2000] 2 S.C.R.

919, 2000 SCC 64; Leiriao v. Val-Bélair (Town), [1991] 3 S.C.R. 349; Hongkong Bank

of Canada v. Wheeler Holdings Ltd., [1993] 1 S.C.R. 167.

By Binnie J. (dissenting)

Atco Ltd. v. Calgary Power Ltd., [1982] 2 S.C.R. 557; C.U.P.E. v. Ontario

(Minister of Labour), [2003] 1 S.C.R. 539, 2003 SCC 29; TransAlta Utilities Corp. v.

Public Utilities Board (Alta.) (1986), 68 A.R. 171; Dr. Q v. College of Physicians and

Surgeons of British Columbia, [2003] 1 S.C.R. 226, 2003 SCC 19; Calgary Power Ltd.

v. Copithorne, [1959] S.C.R. 24; United Brotherhood of Carpenters and Joiners of

America, Local 579 v. Bradco Construction Ltd., [1993] 2 S.C.R. 316; Pezim v. British

Columbia (Superintendent of Brokers), [1994] 2 S.C.R. 557; Memorial Gardens

Association (Canada) Ltd. v. Colwood Cemetery Co., [1958] S.C.R. 353; Union Gas Co.

of Canada Ltd. v. Sydenham Gas and Petroleum Co., [1957] S.C.R. 185; Re C.T.C.

Dealer Holdings Ltd. and Ontario Securities Commission (1987), 59 O.R. (2d) 79;

Committee for the Equal Treatment of Asbestos Minority Shareholders v. Ontario

(Securities Commission), [2001] 2 S.C.R. 132, 2001 SCC 37; Re Consumers’ Gas Co.,

E.B.R.O. 341-I, June 30, 1976; Re Boston Gas Co., 49 P.U.R. 4th 1 (1982); Re

Consumers’ Gas Co., E.B.R.O. 465, March 1, 1991; Re Natural Resource Gas Ltd.,

O.E.B., RP-2002-0147, EB-2002-0446, June 27, 2003; Yukon Energy Corp. v. Utilities

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Board (1996), 74 B.C.A.C. 58; Re Arizona Public Service Co., 91 P.U.R. 4th 337 (1988);

Re Southern California Water Co., 43 C.P.U.C. 2d 596 (1992); Re Southern California

Gas Co., 118 P.U.R. 4th 81 (1990); Democratic Central Committee of the District of

Columbia v. Washington Metropolitan Area Transit Commission, 485 F.2d 786 (1973);

Board of Public Utility Commissioners v. New York Telephone Co., 271 U.S. 23 (1976);

Northwestern Utilities Ltd. v. City of Edmonton, [1979] 1 S.C.R. 684; New York Water

Service Corp. v. Public Service Commission, 208 N.Y.S.2d 857 (1960); Re Compliance

with the Energy Policy Act of 1992, 62 C.P.U.C. 2d 517 (1995); Re California Water

Service Co., 66 C.P.U.C. 2d 100 (1996); Re TransAlta Utilities Corp., Alta. P.U.B.,

Decision No. E84116, October 12, 1984; Re Alberta Government Telephones, Alta.

P.U.B., Decision No. E84081, June 29, 1984; Re TransAlta Utilities Corp., Alta. P.U.B.,

Decision No. E84115, October 12, 1984; Re Canadian Western Natural Gas Co., Alta.

P.U.B., Decision No. E84113, October 12, 1984.

Statutes and Regulations Cited

Alberta Energy and Utilities Board Act, R.S.A. 2000, c. A-17, ss. 13, 15, 26(1), (2), 27.

Gas Utilities Act, R.S.A. 2000, c. G-5, ss. 16, 17, 22, 24, 26, 27(1), 36 to 45, 59.

Interpretation Act, R.S.A. 2000, c. I-8, s. 10.

Public Utilities Act, S.A. 1915, c. 6, ss. 21, 23, 24, 29(g).

Public Utilities Board Act, R.S.A. 2000, c. P-45, ss. 36, 37, 80, 85(1), 87, 89 to 95,101(1), (2), 102(1).

Authors Cited

Anisman, Philip, and Robert F. Reid. Administrative Law Issues and Practice.Scarborough, Ont.: Carswell, 1995.

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Black, Alexander J. “Responsible Regulation: Incentive Rates for Natural GasPipelines” (1992), 28 Tulsa L.J. 349.

Blake, Sara. Administrative Law in Canada, 3rd ed. Markham, Ont.: Butterworths,2001.

Brown, David M. Energy Regulation in Ontario. Aurora, Ont.: Canada Law Book,2001 (loose-leaf updated November 2004, release 3).

Brown, Donald J. M., and John M. Evans. Judicial Review of Administrative Action inCanada. Toronto: Canvasback, 1998 (loose-leaf updated July 2005).

Brown-John, C. Lloyd. Canadian Regulatory Agencies: Quis custodiet ipsos custodes?Toronto: Butterworths, 1981.

Canadian Institute of Resources Law. Canada Energy Law Service: Alberta. Edited bySteven A. Kennett. Toronto: Thomson Carswell, 1981 (loose-leaf updated 2005,release 2).

Côté, Pierre-André. The Interpretation of Legislation in Canada, 3rd ed. Scarborough,Ont.: Carswell, 2000.

Cross, Phillip S. “Rate Treatment of Gain on Sale of Land: Ratepayer Indifference, ANew Standard?” (1990), 126 Pub. Util. Fort. 44.

Depoorter, Ben W. F. “Regulation of Natural Monopoly”, in B. Bouckaert and G. DeGeest, eds., Encyclopedia of Law and Economics, vol. III, The Regulation ofContracts. Northampton, Mass.: Edward Elgar, 2000.

Driedger, Elmer A. Construction of Statutes, 2nd ed. Toronto: Butterworths, 1983.

Green, Richard, and Martin Rodriguez Pardina. Resetting Price Controls for PrivatizedUtilities: A Manual for Regulators. Washington, D.C.: World Bank, 1999.

Kahn, Alfred E. The Economics of Regulation: Principles and Institutions, vol. 1,Economic Principles. Cambridge, Mass.: MIT Press, 1988.

MacAvoy, Paul W., and J. Gregory Sidak. “The Efficient Allocation of Proceeds froma Utility’s Sale of Assets” (2001), 22 Energy L.J. 233.

Milner, H. R. “Public Utility Rate Control in Alberta” (1930), 8 Can. Bar Rev. 101.

Mullan, David J. Administrative Law. Toronto: Irwin Law, 2001.

Netz, Janet S. “Price Regulation: A (Non-Technical) Overview”, in B. Bouckaert andG. De Geest, eds., Encyclopedia of Law and Economics, vol. III, The Regulationof Contracts. Northampton, Mass.: Edward Elgar, 2000.

Reid, Robert F., and Hillel David. Administrative Law and Practice, 2nd ed. Toronto:Butterworths, 1978.

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Sullivan, Ruth. Sullivan and Driedger on the Construction of Statutes, 4th ed.Markham, Ont.: Butterworths, 2002.

Trebilcock, Michael J. “The Consumer Interest and Regulatory Reform”, in G. B.Doern, ed., The Regulatory Process in Canada. Toronto: Macmillan of Canada,1978, 94.

APPEAL and CROSS-APPEAL from a judgment of the Alberta Court of

Appeal (Wittmann J.A. and LoVecchio J. (ad hoc)) (2004), 24 Alta. L.R. (4th) 205, 339

A.R. 250, 312 W.A.C. 250, [2004] 4 W.W.R. 239, [2004] A.J. No. 45 (QL), 2004 ABCA

3, reversing a decision of the Alberta Energy and Utilities Board, [2002] A.E.U.B.D. No.

52 (QL). Appeal dismissed and cross-appeal allowed, McLachlin C.J. and Binnie and

Fish JJ. dissenting.

Brian K. O’Ferrall and Daron K. Naffin, for the appellant/respondent on

cross-appeal.

Clifton D. O’Brien, Q.C., Lawrence E. Smith, Q.C., H. Martin Kay, Q.C.,

and Laurie A. Goldbach, for the respondent/appellant on cross-appeal.

J. Richard McKee and Renée Marx, for the intervener the Alberta Energy

and Utilities Board.

Written submissions only by George Vegh and Michael W. Lyle, for the

intervener the Ontario Energy Board.

Written submissions only by J. L. McDougall, Q.C., and Michael D.

Schafler, for the intervener Enbridge Gas Distribution Inc.

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Written submissions only by Michael A. Penny and Susan Kushneryk, for the

intervener Union Gas Limited.

The judgment of Bastarache, LeBel, Deschamps and Charron JJ. was

delivered by

BASTARACHE J. —

1. Introduction

1 At the heart of this appeal is the issue of the jurisdiction of an administrative

board. More specifically, the Court must consider whether, on the appropriate standard

of review, this utility board appropriately set out the limits of its powers and discretion.

2 Few areas of our lives are now untouched by regulation. Telephone, rail,

airline, trucking, foreign investment, insurance, capital markets, broadcasting licences

and content, banking, food, drug and safety standards, are just a few of the objects of

public regulations in Canada: M. J. Trebilcock, “The Consumer Interest and Regulatory

Reform”, in G. B. Doern, ed., The Regulatory Process in Canada (1978), 94. Discretion

is central to the regulatory agency policy process, but this discretion will vary from one

administrative body to another (see C. L. Brown-John, Canadian Regulatory Agencies:

Quis custodiet ipsos custodes? (1981), at p. 29). More importantly, in exercising this

discretion, statutory bodies must respect the confines of their jurisdiction: they cannot

trespass in areas where the legislature has not assigned them authority (see D. J. Mullan,

Administrative Law (2001), at pp. 9-10).

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3 The business of energy and utilities is no exception to this regulatory

framework. The respondent in this case is a public utility in Alberta which delivers

natural gas. This public utility is nothing more than a private corporation subject to

certain regulatory constraints. Fundamentally, it is like any other privately held

company: it obtains the necessary funding from investors through public issues of shares

in stock and bond markets; it is the sole owner of the resources, land and other assets;

it constructs plants, purchases equipment, and contracts with employees to provide the

services; it realizes profits resulting from the application of the rates approved by the

Alberta Energy and Utilities Board (“Board”) (see P. W. MacAvoy and J. G. Sidak, “The

Efficient Allocation of Proceeds from a Utility’s Sale of Assets” (2001), 22 Energy L.J.

233, at p. 234). That said, one cannot ignore the important feature which makes a public

utility so distinct: it must answer to a regulator. Public utilities are typically natural

monopolies: technology and demand are such that fixed costs are lower for a single firm

to supply the market than would be the case where there is duplication of services by

different companies in a competitive environment (see A. E. Kahn, The Economics of

Regulation: Principles and Institutions (1988), vol. 1, at p. 11; B. W. F. Depoorter,

“Regulation of Natural Monopoly”, in B. Bouckaert and G. De Geest, eds., Encyclopedia

of Law and Economics (2000), vol. III, 498; J. S. Netz, “Price Regulation: A (Non-

Technical) Overview”, in B. Bouckaert and G. De Geest, eds., Encyclopedia of Law and

Economics (2000), vol. III, 396, at p. 398; A. J. Black, “Responsible Regulation:

Incentive Rates for Natural Gas Pipelines” (1992), 28 Tulsa L.J. 349, at p. 351).

Efficiency of production is promoted under this model. However, governments have

purported to move away from this theoretical concept and have adopted what can only

be described as a “regulated monopoly”. The utility regulations exist to protect the public

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from monopolistic behaviour and the consequent inelasticity of demand while ensuring

the continued quality of an essential service (see Kahn, at p. 11).

4 As in any business venture, public utilities make business decisions, their

ultimate goal being to maximize the residual benefits to shareholders. However, the

regulator limits the utility’s managerial discretion over key decisions, including prices,

service offerings and the prudency of plant and equipment investment decisions. And

more relevant to this case, the utility, outside the ordinary course of business, is limited

in its right to sell assets it owns: it must obtain authorization from its regulator before

selling an asset previously used to produce regulated services (see MacAvoy and Sidak,

at p. 234).

5 Against this backdrop, the Court is being asked to determine whether the

Board has jurisdiction pursuant to its enabling statutes to allocate a portion of the net

gain on the sale of a now discarded utility asset to the rate-paying customers of the utility

when approving the sale. Subsequently, if this first question is answered affirmatively,

the Court must consider whether the Board’s exercise of its jurisdiction was reasonable

and within the limits of its jurisdiction: was it allowed, in the circumstances of this case,

to allocate a portion of the net gain on the sale of the utility to the rate-paying customers?

6 The customers’ interests are represented in this case by the City of Calgary

(“City”) which argues that the Board can determine how to allocate the proceeds

pursuant to its power to approve the sale and protect the public interest. I find this

position unconvincing.

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7 The interpretation of the Alberta Energy and Utilities Board Act, R.S.A.

2000, c. A-17 (“AEUBA”), the Public Utilities Board Act, R.S.A. 2000, c. P-45

(“PUBA”), and the Gas Utilities Act, R.S.A. 2000, c. G-5 (“GUA”) (see Appendix for

the relevant provisions of these three statutes), can lead to only one conclusion: the

Board does not have the prerogative to decide on the distribution of the net gain from the

sale of assets of a utility. The Board’s seemingly broad powers to make any order and

to impose any additional conditions that are necessary in the public interest has to be

interpreted within the entire context of the statutes which are meant to balance the need

to protect consumers as well as the property rights retained by owners, as recognized in

a free market economy. The limits of the powers of the Board are grounded in its main

function of fixing just and reasonable rates (“rate setting”) and in protecting the integrity

and dependability of the supply system.

1.1 Overview of the Facts

8 ATCO Gas - South (“AGS”), which is a division of ATCO Gas and Pipelines

Ltd. (“ATCO”), filed an application by letter with the Board pursuant to s. 25.1(2) (now

s. 26(2)) of the GUA, for approval of the sale of its properties located in Calgary known

as Calgary Stores Block (the “property”). The property consisted of land and buildings;

however, the main value was in the land, and the purchaser intended to and did

eventually demolish the buildings and redevelop the land. According to AGS, the

property was no longer used or useful for the provision of utility services, and the sale

would not cause any harm to customers. In fact, AGS suggested that the sale would

result in cost savings to customers, by allowing the net book value of the property to be

retired and withdrawn from the rate base, thereby reducing rates. ATCO requested that

the Board approve the sale transaction and the disposition of the sale proceeds to retire

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the remaining book value of the sold assets, to recover the disposition costs, and to

recognize the balance of the profits resulting from the sale of the plant should be paid to

shareholders. The Board dealt with the application in writing, without witnesses or an

oral hearing. Other parties making written submissions to the Board were the City of

Calgary, the Federation of Alberta Gas Co-ops Ltd., Gas Alberta Inc. and the Municipal

Interveners, who all opposed ATCO’s position with respect to the disposition of the sale

proceeds to shareholders.

1.2 Judicial History

1.2.1 Alberta Energy and Utilities Board

1.2.1.1 Decision 2001-78

9 In a first decision, which considered ATCO’s application to approve the sale

of the property, the Board employed a “no-harm” test, assessing the potential impact on

both rates and the level of service to customers and the prudence of the sale transaction,

taking into account the purchaser and tender or sale process followed. The Board was

of the view that the test had been satisfied. It was persuaded that customers would not

be harmed by the sale, given that a prudent lease arrangement to replace the sold facility

had been concluded. The Board was satisfied that there would not be a negative impact

on customers’ rates, at least during the five-year initial term of the lease. In fact, the

Board concluded that there would be cost savings to the customers and that there would

be no impact on the level of service to customers as a result of the sale. It did not make

a finding on the specific impact on future operating costs; for example, it did not

consider the costs of the lease arrangement entered into by ATCO. The Board noted that

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those costs could be reviewed by the Board in a future general rate application brought

by interested parties.

1.2.1.2 Decision 2002-037, [2002] A.E.U.B.D. No. 52 (QL)

10 In a second decision, the Board determined the allocation of net sale

proceeds. It reviewed the regulatory policy and general principles which affected the

decision, although no specific matters are enumerated for consideration in the applicable

legislative provisions. The Board had previously developed a “no-harm” test, and it

reviewed the rationale for the test as summarized in its Decision 2001-65 (Re ATCO

Gas-North): “The Board considers that its power to mitigate or offset potential harm to

customers by allocating part or all of the sale proceeds to them, flows from its very broad

mandate to protect consumers in the public interest” (p. 16).

11 The Board went on to discuss the implications of the Alberta Court of

Appeal decision in TransAlta Utilities Corp. v. Public Utilities Board (Alta.) (1986), 68

A.R. 171, referring to various decisions it had rendered in the past. Quoting from its

Decision 2000-41 (Re TransAlta Utilities Corp.), the Board summarized the “TransAlta

Formula”:

In subsequent decisions, the Board has interpreted the Court of Appeal’sconclusion to mean that where the sale price exceeds the original cost of theassets, shareholders are entitled to net book value (in historical dollars),customers are entitled to the difference between net book value and originalcost, and any appreciation in the value of the assets (i.e. the differencebetween original cost and the sale price) is to be shared by shareholders andcustomers. The amount to be shared by each is determined by multiplyingthe ratio of sale price/original cost to the net book value (for shareholders)and the difference between original cost and net book value (for customers).However, where the sale price does not exceed original cost, customers areentitled to all of the gain on sale. [para. 27]

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The Board also referred to Decision 2001-65, where it had clarified the following:

In the Board’s view, if the TransAlta Formula yields a result greaterthan the no-harm amount, customers are entitled to the greater amount. Ifthe TransAlta Formula yields a result less than the no-harm amount,customers are entitled to the no-harm amount. In the Board’s view, thisapproach is consistent with its historical application of the TransAltaFormula. [para. 28]

12 On the issue of its jurisdiction to allocate the net proceeds of a sale, the

Board in the present case stated:

The fact that a regulated utility must seek Board approval beforedisposing of its assets is sufficient indication of the limitations placed by thelegislature on the property rights of a utility. In appropriate circumstances,the Board clearly has the power to prevent a utility from disposing of itsproperty. In the Board’s view it also follows that the Board can approve adisposition subject to appropriate conditions to protect customer interests.

Regarding AGS’s argument that allocating more than the no-harmamount to customers would amount to retrospective ratemaking, the Boardagain notes the decision in the TransAlta Appeal. The Court of Appealaccepted that the Board could include in the definition of “revenue” anamount payable to customers representing excess depreciation paid by themthrough past rates. In the Board’s view, no question of retrospectiveratemaking arises in cases where previously regulated rate base assets arebeing disposed of out of rate base and the Board applies the TransAltaFormula.

The Board is not persuaded by the Company’s argument that the StoresBlock assets are now ‘non-utility’ by virtue of being ‘no longer required forutility service’. The Board notes that the assets could still be providingservice to regulated customers. In fact, the services formerly provided bythe Stores Block assets continue to be required, but will be provided fromexisting and newly leased facilities. Furthermore, the Board notes that evenwhen an asset and the associated service it was providing to customers is nolonger required the Board has previously allocated more than the no-harmamount to customers where proceeds have exceeded the original cost of theasset. [paras. 47-49]

13 The Board went on to apply the no-harm test to the present facts. It noted

that in its decision on the application for the approval of the sale, it had already

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considered the no-harm test to be satisfied. However, in that first decision, it had not

made a finding with respect to the specific impact on future operating costs, including

the particular lease arrangement being entered into by ATCO.

14 The Board then reviewed the submissions with respect to the allocation of

the net gain and rejected the submission that if the new owner had no use of the buildings

on the land, this should affect the allocation of net proceeds. The Board held that the

buildings did have some present value but did not find it necessary to fix a specific value.

The Board recognized and confirmed that the TransAlta Formula was one whereby the

“windfall” realized when the proceeds of sale exceed the original cost could be shared

between customers and shareholders. It held that it should apply the formula in this case

and that it would consider the gain on the transaction as a whole, not distinguishing

between the proceeds allocated to land separately from the proceeds allocated to

buildings.

15 With respect to allocation of the gain between customers and shareholders

of ATCO, the Board tried to balance the interests of both the customers’ desire for safe

reliable service at a reasonable cost with the provision of a fair return on the investment

made by the company:

To award the entire net gain on the land and buildings to the customers,while beneficial to the customers, could establish an environment that maydeter the process wherein the company continually assesses its operation toidentify, evaluate, and select options that continually increase efficiency andreduce costs.

Conversely, to award the entire net gain to the company may establishan environment where a regulated utility company might be moved tospeculate in non-depreciable property or result in the company beingmotivated to identify and sell existing properties where appreciation hasalready occurred. [paras. 112-13]

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16 The Board went on to conclude that the sharing of the net gain on the sale

of the land and buildings collectively, in accordance with the TransAlta Formula, was

equitable in the circumstances of this application and was consistent with past Board

decisions.

17 The Board determined that from the gross proceeds of $6,550,000, ATCO

should receive $465,000 to cover the cost of disposition ($265,000) and the provision

for environmental remediation ($200,000), the shareholders should receive $2,014,690,

and $4,070,310 should go to the customers. Of the amount credited to shareholders,

$225,245 was to be used to remove the remaining net book value of the property from

ATCO’s accounts. Of the amount allocated to customers, $3,045,813 was allocated to

ATCO Gas - South customers and $1,024,497 to ATCO Pipelines - South customers.

1.2.2 Court of Appeal of Alberta ((2004), 24 Alta. L.R. (4th) 205, 2004 ABCA 3)

18 ATCO appealed the Board’s decision. It argued that the Board did not have

any jurisdiction to allocate the proceeds of sale and that the proceeds should have been

allocated entirely to the shareholders. In its view, allowing customers to share in the

proceeds of sale would result in them benefiting twice, since they had been spared the

costs of renovating the sold assets and would enjoy cost savings from the lease

arrangements. The Court of Appeal of Alberta agreed with ATCO, allowing the appeal

and setting aside the Board’s decision. The matter was referred back to the Board, and

the Board was directed to allocate the entire amount appearing in Line 11 of the

allocation of proceeds, entitled “Remainder to be Shared” to ATCO. For the reasons that

follow, the Court of Appeal’s decision should be upheld, in part; it did not err when it

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held that the Board did not have the jurisdiction to allocate the proceeds of the sale to

ratepayers.

2. Analysis

2.1 Issues

19 There is an appeal and a cross-appeal in this case: an appeal by the City in

which it submits that, contrary to the Court of Appeal’s decision, the Board had

jurisdiction to allocate a portion of the net gain on the sale of a utility asset to the rate-

paying customers, even where no harm to the public was found at the time the Board

approved the sale, and a cross-appeal by ATCO in which it questions the Board’s

jurisdiction to allocate any of ATCO’s proceeds from the sale to customers. In particular,

ATCO contends that the Board has no jurisdiction to make an allocation to rate-paying

customers, equivalent to the accumulated depreciation calculated for prior years. No

matter how the issue is framed, it is evident that the crux of this appeal lies in whether

the Board has the jurisdiction to distribute the gain on the sale of a utility company’s

asset.

20 Given my conclusion on this issue, it is not necessary for me to consider

whether the Board’s allocation of the proceeds in this case was reasonable. Nevertheless,

as I note at para. 82, I will direct my attention briefly to the question of the exercise of

discretion in view of my colleague’s reasons.

2.2 Standard of Review

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21 As this appeal stems from an administrative body’s decision, it is necessary

to determine the appropriate level of deference which must be shown to the body.

Wittmann J.A., writing for the Court of Appeal, concluded that the issue of jurisdiction

of the Board attracted a standard of correctness. ATCO concurs with this conclusion. I

agree. No deference should be shown for the Board’s decision with regard to its

jurisdiction on the allocation of the net gain on sale of assets. An inquiry into the factors

enunciated by this Court in Pushpanathan v. Canada (Minister of Citizenship and

Immigration), [1998] 1 S.C.R. 982, confirms this conclusion, as does the reasoning in

United Taxi Drivers’ Fellowship of Southern Alberta v. Calgary (City), [2004] 1 S.C.R.

485, 2004 SCC 19.

22 Although it is not necessary to conduct a full analysis of the standard of

review in this case, I will address the issue briefly in light of the fact that Binnie J. deals

with the exercise of discretion in his reasons for judgment. The four factors that need to

be canvassed in order to determine the appropriate standard of review of an

administrative tribunal decision are: (1) the existence of a privative clause; (2) the

expertise of the tribunal/board; (3) the purpose of the governing legislation and the

particular provisions; and (4) the nature of the problem (Pushpanathan, at paras. 29-38).

23 In the case at bar, one should avoid a hasty characterizing of the issue as

“jurisdictional” and subsequently be tempted to skip the pragmatic and functional

analysis. A complete examination of the factors is required.

24 First, s. 26(1) of the AEUBA grants a right of appeal, but in a limited way.

Appeals are allowed on a question of jurisdiction or law and only after leave to appeal

is obtained from a judge:

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26(1) Subject to subsection (2), an appeal lies from the Board to the Courtof Appeal on a question of jurisdiction or on a question of law.

(2) Leave to appeal may be obtained from a judge of the Court of Appealonly on an application made

(a) within 30 days from the day that the order, decision or directionsought to be appealed from was made, or

(b) within a further period of time as granted by the judge where thejudge is of the opinion that the circumstances warrant the grantingof that further period of time.

In addition, the AEUBA includes a privative clause which states that every action, order,

ruling or decision of the Board is final and shall not be questioned, reviewed or

restrained by any proceeding in the nature of an application for judicial review or

otherwise in any court (s. 27).

25 The presence of a statutory right of appeal on questions of jurisdiction and

law suggests a more searching standard of review and less deference to the Board on

those questions (see Pushpanathan, at para. 30). However, the presence of the privative

clause and right to appeal are not decisive, and one must proceed with the examination

of the nature of the question to be determined and the relative expertise of the tribunal

in those particular matters.

26 Second, as observed by the Court of Appeal, no one disputes the fact that the

Board is a specialized body with a high level of expertise regarding Alberta’s energy

resources and utilities (see, e.g., Consumers’ Gas Co. v. Ontario (Energy Board), [2001]

O.J. No. 5024 (QL) (Div. Ct.), at para. 2; Coalition of Citizens Impacted by the Caroline

Shell Plant v. Alberta (Energy Utilities Board) (1996), 41 Alta. L.R. (3d) 374 (C.A.), at

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para. 14. In fact, the Board is a permanent tribunal with a long-term regulatory

relationship with the regulated utilities.

27 Nevertheless, the Court is concerned not with the general expertise of the

administrative decision maker, but with its expertise in relation to the specific nature of

the issue before it. Consequently, while normally one would have assumed that the

Board’s expertise is far greater than that of a court, the nature of the problem at bar, to

adopt the language of the Court of Appeal (para. 35), “neutralizes” this deference. As I

will elaborate below, the expertise of the Board is not engaged when deciding the scope

of its powers.

28 Third, the present case is governed by three pieces of legislation: the PUBA,

the GUA and the AEUBA. These statutes give the Board a mandate to safeguard the

public interest in the nature and quality of the service provided to the community by

public utilities: Atco Ltd. v. Calgary Power Ltd., [1982] 2 S.C.R. 557, at p. 576; Dome

Petroleum Ltd. v. Public Utilities Board (Alberta) (1976), 2 A.R. 453 (C.A.), at paras.

20-22, aff’d [1977] 2 S.C.R. 822. The legislative framework at hand has as its main

purpose the proper regulation of a gas utility in the public interest, more specifically the

regulation of a monopoly in the public interest with its primary tool being rate setting,

as I will explain later.

29 The particular provision at issue, s. 26(2)(d)(i) of the GUA, which requires

a utility to obtain the approval of the regulator before it sells an asset, serves to protect

the customers from adverse results brought about by any of the utility’s transactions by

ensuring that the economic benefits to customers are enhanced (MacAvoy and Sidak, at

pp. 234-36).

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30 While at first blush the purposes of the relevant statutes and of the Board can

be conceived as a delicate balancing between different constituencies, i.e., the utility and

the customer, and therefore entail determinations which are polycentric (Pushpanathan,

at para. 36), the interpretation of the enabling statutes and the particular provisions under

review (s. 26(2)(d) of the GUA and s. 15(3)(d) of the AEUBA) is not a polycentric

question, contrary to the conclusion of the Court of Appeal. It is an inquiry into whether

a proper construction of the enabling statutes gives the Board jurisdiction to allocate the

profits realized from the sale of an asset. The Board was not created with the main

purpose of interpreting the AEUBA, the GUA or the PUBA in the abstract, where no

policy consideration is at issue, but rather to ensure that utility rates are always just and

reasonable (see Atco Ltd., at p. 576). In the case at bar, this protective role does not come

into play. Hence, this factor points to a less deferential standard of review.

31 Fourth, the nature of the problem underlying each issue is different. The

parties are in essence asking the Court to answer two questions (as I have set out above),

the first of which is to determine whether the power to dispose of the proceeds of sale

falls within the Board’s statutory mandate. The Board, in its decision, determined that

it had the power to allocate a portion of the proceeds of a sale of utility assets to the

ratepayers; it based its decision on its statutory powers, the equitable principles rooted

in the “regulatory compact” (see para. 63 of these reasons) and previous practice. This

question is undoubtedly one of law and jurisdiction. The Board would arguably have no

greater expertise with regard to this issue than the courts. A court is called upon to

interpret provisions that have no technical aspect, in contrast with the provision disputed

in Barrie Public Utilities v. Canadian Cable Television Assn., [2003] 1 S.C.R. 476, 2003

SCC 28, at para. 86. The interpretation of general concepts such as “public interest” and

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“conditions” (as found in s. 15(3)(d) of the AEUBA) is not foreign to courts and is not

derived from an area where the tribunal has been held to have greater expertise than the

courts. The second question is whether the method and actual allocation in this case were

reasonable. To resolve this issue, one must consider case law, policy justifications and

the practice of other boards, as well as the details of the particular allocation in this case.

The issue here is most likely characterized as one of mixed fact and law.

32 In light of the four factors, I conclude that each question requires a distinct

standard of review. To determine the Board’s power to allocate proceeds from a sale of

utility assets suggests a standard of review of correctness. As expressed by the Court of

Appeal, the focus of this inquiry remains on the particular provisions being invoked and

interpreted by the tribunal (s. 26(2)(d) of the GUA and s. 15(3)(d) of the AEUBA) and

“goes to jurisdiction” (Pushpanathan, at para. 28). Moreover, keeping in mind all the

factors discussed, the generality of the proposition will be an additional factor in favour

of the imposition of a correctness standard, as I stated in Pushpanathan, at para. 38:

. . . the broader the propositions asserted, and the further the implications ofsuch decisions stray from the core expertise of the tribunal, the lesslikelihood that deference will be shown. Without an implied or expresslegislative intent to the contrary as manifested in the criteria above,legislatures should be assumed to have left highly generalized propositionsof law to courts.

33 The second question regarding the Board’s actual method used for the

allocation of proceeds likely attracts a more deferential standard. On the one hand, the

Board’s expertise, particularly in this area, its broad mandate, the technical nature of the

question and the general purposes of the legislation, all suggest a relatively high level

of deference to the Board’s decision. On the other hand, the absence of a privative clause

on questions of jurisdiction and the reference to law needed to answer this question all

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suggest a less deferential standard of review which favours reasonableness. It is not

necessary, however, for me to determine which specific standard would have applied

here.

34 As will be shown in the analysis below, I am of the view that the Court of

Appeal made no error of fact or law when it concluded that the Board acted beyond its

jurisdiction by misapprehending its statutory and common law authority. However, the

Court of Appeal erred when it did not go on to conclude that the Board has no

jurisdiction to allocate any portion of the proceeds of sale of the property to ratepayers.

2.3 Was the Board’s Decision as to Its Jurisdiction Correct?

35 Administrative tribunals or agencies are statutory creations: they cannot

exceed the powers that were granted to them by their enabling statute; they must “adhere

to the confines of their statutory authority or ‘jurisdiction’[; and t]hey cannot trespass in

areas where the legislature has not assigned them authority”: Mullan, at pp. 9-10 (see

also S. Blake, Administrative Law in Canada (3rd ed. 2001), at pp. 183-84).

36 In order to determine whether the Board’s decision that it had the jurisdiction

to allocate proceeds from the sale of a utility’s asset was correct, I am required to

interpret the legislative framework by which the Board derives its powers and actions.

2.3.1 General Principles of Statutory Interpretation

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37 For a number of years now, the Court has adopted E. A. Driedger’s modern

approach as the method to follow for statutory interpretation (Construction of Statutes

(2nd ed. 1983), at p. 87):

Today there is only one principle or approach, namely, the words of anAct are to be read in their entire context and in their grammatical andordinary sense harmoniously with the scheme of the Act, the object of theAct, and the intention of Parliament.

(See, e.g., Rizzo & Rizzo Shoes Ltd. (Re), [1998] 1 S.C.R. 27, at para. 21; Bell ExpressVu

Limited Partnership v. Rex, [2002] 2 S.C.R. 559, 2002 SCC 42, at para. 26; H.L. v.

Canada (Attorney General), [2005] 1 S.C.R. 401, 2005 SCC 25, at paras. 186-87;

Marche v. Halifax Insurance Co., [2005] 1 S.C.R. 47, 2005 SCC 6, at para. 54; Barrie

Public Utilities, at paras. 20 and 86; Contino v. Leonelli-Contino, [2005] 3 S.C.R. 217,

2005 SCC 63, at para. 19.)

38 But more specifically in the area of administrative law, tribunals and boards

obtain their jurisdiction over matters from two sources: (1) express grants of jurisdiction

under various statutes (explicit powers); and (2) the common law, by application of the

doctrine of jurisdiction by necessary implication (implicit powers) (see also D. M.

Brown, Energy Regulation in Ontario (loose-leaf ed.), at p. 2-15).

39 The City submits that it is both implicit and explicit within the express

jurisdiction that has been conferred upon the Board to approve or refuse to approve the

sale of utility assets, that the Board can determine how to allocate the proceeds of the

sale in this case. ATCO retorts that not only is such a power absent from the explicit

language of the legislation, but it cannot be “implied” from the statutory regime as

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necessarily incidental to the explicit powers. I agree with ATCO’s submissions and will

elaborate in this regard.

2.3.2 Explicit Powers: Grammatical and Ordinary Meaning

40 As a preliminary submission, the City argues that given that ATCO applied

to the Board for approval of both the sale transaction and the disposition of the proceeds

of sale, this suggests that ATCO recognized that the Board has authority to allocate the

proceeds as a condition of a proposed sale. This argument does not hold any weight in

my view. First, the application for approval cannot be considered on its own an

admission by ATCO of the jurisdiction of the Board. In any event, an admission of this

nature would not have any bearing on the applicable law. Moreover, knowing that in the

past the Board had decided that it had jurisdiction to allocate the proceeds of a sale of

assets and had acted on this power, one can assume that ATCO was asking for the

approval of the disposition of the proceeds should the Board not accept their argument

on jurisdiction. In fact, a review of past Board decisions on the approval of sales shows

that utility companies have constantly challenged the Board’s jurisdiction to allocate the

net gain on the sale of assets (see, e.g., Re TransAlta Utilities Corp., Alta. E.U.B.,

Decision 2000-41; Re ATCO Gas-North, Alta. E.U.B., Decision 2001-65; Re Alberta

Government Telephones, Alta. P.U.B., Decision No. E84081, June 29, 1984; Re

TransAlta Utilities Corp., Alta. P.U.B., Decision No. E84116, October 12, 1984;

TransAlta Utilities Corp. (Re), [2002] A.E.U.B.D. No. 30 (QL); ATCO Electric Ltd.

(Re), [2003] A.E.U.B.D. No. 92 (QL)).

41 The starting point of the analysis requires that the Court examine the

ordinary meaning of the sections at the centre of the dispute, s. 26(2)(d)(i) of the GUA,

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ss. 15(1) and 15(3)(d) of the AEUBA and s. 37 of the PUBA. For ease of reference, I

reproduce these provisions:

GUA

26. . . .

(2) No owner of a gas utility designated under subsection (1) shall

. . .

(d) without the approval of the Board,

(i) sell, lease, mortgage or otherwise dispose of or encumber itsproperty, franchises, privileges or rights, or any part of it or them

. . .

and a sale, lease, mortgage, disposition, encumbrance, merger orconsolidation made in contravention of this clause is void, but nothingin this clause shall be construed to prevent in any way the sale, lease,mortgage, disposition, encumbrance, merger or consolidation of any ofthe property of an owner of a gas utility designated under subsection (1)in the ordinary course of the owner’s business.

AEUBA

15(1) For the purposes of carrying out its functions, the Board has all thepowers, rights and privileges of the ERCB [Energy Resources ConservationBoard] and the PUB [Public Utilities Board] that are granted or provided forby any enactment or by law.

. . .

(3) Without restricting subsection (1), the Board may do all or any of thefollowing:

. . .

(d) with respect to an order made by the Board, the ERCB or the PUBin respect of matters referred to in clauses (a) to (c), make anyfurther order and impose any additional conditions that the Boardconsiders necessary in the public interest;

. . .

PUBA

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37 In matters within its jurisdiction the Board may order and require anyperson or local authority to do forthwith or within or at a specified time andin any manner prescribed by the Board, so far as it is not inconsistent withthis Act or any other Act conferring jurisdiction, any act, matter or thing thatthe person or local authority is or may be required to do under this Act orunder any other general or special Act, and may forbid the doing orcontinuing of any act, matter or thing that is in contravention of any suchAct or of any regulation, rule, order or direction of the Board.

42 Some of the above provisions are duplicated in the other two statutes (see,

e.g., PUBA, ss. 85(1) and 101(2)(d)(i); GUA, s. 22(1); see Appendix).

43 There is no dispute that s. 26(2) of the GUA contains a prohibition against,

among other things, the owner of a utility selling, leasing, mortgaging or otherwise

disposing of its property outside of the ordinary course of business without the approval

of the Board. As submitted by ATCO, the power conferred is to approve without more.

There is no mention in s. 26 of the grounds for granting or denying approval or of the

ability to grant conditional approval, let alone the power of the Board to allocate the net

profit of an asset sale. I would note in passing that this power is sufficient to alleviate the

fear expressed by the Board that the utility might be tempted to sell assets on which it

might realize a large profit to the detriment of ratepayers if it could reap the benefits of

the sale.

44 It is interesting to note that s. 26(2) does not apply to all types of sales (and

leases, mortgages, dispositions, encumbrances, mergers or consolidations). It excludes

sales in the ordinary course of the owner’s business. If the statutory scheme was such

that the Board had the power to allocate the proceeds of the sale of utility assets, as

argued here, s. 26(2) would naturally apply to all sales of assets or, at a minimum,

exempt only those sales below a certain value. It is apparent that allocation of sale

proceeds to customers is not one of its purposes. In fact, s. 26(2) can only have limited,

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if any, application to non-utility assets not related to utility function (especially when the

sale has passed the “no-harm” test). The provision can only be meant to ensure that the

asset in question is indeed non-utility, so that its loss does not impair the utility function

or quality.

45 Therefore, a simple reading of s. 26(2) of the GUA does permit one to

conclude that the Board does not have the power to allocate the proceeds of an asset sale.

46 The City does not limit its arguments to s. 26(2); it also submits that the

AEUBA, pursuant to s. 15(3), is an express grant of jurisdiction because it authorizes

the Board to impose any condition to any order so long as the condition is necessary in

the public interest. In addition, it relies on the general power in s. 37 of the PUBA for

the proposition that the Board may, in any matter within its jurisdiction, make any order

pertaining to that matter that is not inconsistent with any applicable statute. The intended

meaning of these two provisions, however, is lost when the provisions are simply read

in isolation as proposed by the City: R. Sullivan, Sullivan and Driedger on the

Construction of Statutes (4th ed. 2002), at p. 21; Canadian Pacific Air Lines Ltd. v.

Canadian Air Line Pilots Assn., [1993] 3 S.C.R. 724, at p. 735; Marche, at paras. 59-60;

Bristol-Myers Squibb Co. v. Canada (Attorney General), [2005] 1 S.C.R. 533, 2005 SCC

26, at para. 105. These provisions on their own are vague and open-ended. It would be

absurd to allow the Board an unfettered discretion to attach any condition it wishes to

an order it makes. Furthermore, the concept of “public interest” found in s. 15(3) is very

wide and elastic; the Board cannot be given total discretion over its limitations.

47 While I would conclude that the legislation is silent as to the Board’s power

to deal with sale proceeds after the initial stage in the statutory interpretation analysis,

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because the provisions can nevertheless be said to reveal some ambiguity and

incoherence, I will pursue the inquiry further.

48 This Court has stated on numerous occasions that the grammatical and

ordinary sense of a section is not determinative and does not constitute the end of the

inquiry. The Court is obliged to consider the total context of the provisions to be

interpreted, no matter how plain the disposition may seem upon initial reading (see

Chieu v. Canada (Minister of Citizenship and Immigration), [2002] 1 S.C.R. 84, 2002

SCC 3, at para. 34; Sullivan, at pp. 20-21). I will therefore proceed to examine the

purpose and scheme of the legislation, the legislative intent and the relevant legal norms.

2.3.3 Implicit Powers: Entire Context

49 The provisions at issue are found in statutes which are themselves

components of a larger statutory scheme which cannot be ignored:

As the product of a rational and logical legislature, the statute isconsidered to form a system. Every component contributes to the meaningas a whole, and the whole gives meaning to its parts: “each legal provisionshould be considered in relation to other provisions, as parts of a whole”. . . .

(P.-A. Côté, The Interpretation of Legislation in Canada (3rd ed. 2000), atp. 308)

As in any statutory interpretation exercise, when determining the powers of an

administrative body, courts need to examine the context that colours the words and the

legislative scheme. The ultimate goal is to discover the clear intent of the legislature and

the true purpose of the statute while preserving the harmony, coherence and consistency

of the legislative scheme (Bell ExpressVu, at para. 27; see also Interpretation Act, R.S.A.

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2000, c. I-8, s. 10 (in Appendix)). “[S]tatutory interpretation is the art of finding the

legislative spirit embodied in enactments”: Bristol-Myers Squibb Co., at para. 102.

50 Consequently, a grant of authority to exercise a discretion as found in

s. 15(3) of the AEUBA and s. 37 of the PUBA does not confer unlimited discretion to

the Board. As submitted by ATCO, the Board’s discretion is to be exercised within the

confines of the statutory regime and principles generally applicable to regulatory matters,

for which the legislature is assumed to have had regard in passing that legislation (see

Sullivan, at pp. 154-55). In the same vein, it is useful to refer to the following passage

from Bell Canada v. Canada (Canadian Radio-Television and Telecommunications

Commission), [1989] 1 S.C.R. 1722, at p. 1756:

The powers of any administrative tribunal must of course be stated in itsenabling statute but they may also exist by necessary implication from thewording of the act, its structure and its purpose. Although courts mustrefrain from unduly broadening the powers of such regulatory authoritiesthrough judicial law-making, they must also avoid sterilizing these powersthrough overly technical interpretations of enabling statutes.

51 The mandate of this Court is to determine and apply the intention of the

legislature (Bell ExpressVu, at para. 62) without crossing the line between judicial

interpretation and legislative drafting (see R. v. McIntosh, [1995] 1 S.C.R. 686, at

para. 26; Bristol-Myers Squibb Co., at para. 174). That being said, this rule allows for

the application of the “doctrine of jurisdiction by necessary implication”; the powers

conferred by an enabling statute are construed to include not only those expressly

granted but also, by implication, all powers which are practically necessary for the

accomplishment of the object intended to be secured by the statutory regime created by

the legislature (see Brown, at p. 2-16.2; Bell Canada, at p. 1756). Canadian courts have

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in the past applied the doctrine to ensure that administrative bodies have the necessary

jurisdiction to accomplish their statutory mandate:

When legislation attempts to create a comprehensive regulatory framework,the tribunal must have the powers which by practical necessity andnecessary implication flow from the regulatory authority explicitly conferredupon it.

Re Dow Chemical Canada Inc. and Union Gas Ltd. (1982), 141 D.L.R. (3d) 641 (Ont.

H.C.), at pp. 658-59, aff’d (1983), 42 O.R. (2d) 731 (C.A.) (see also Interprovincial Pipe

Line Ltd. v. National Energy Board, [1978] 1 F.C. 601 (C.A.); Canadian Broadcasting

League v. Canadian Radio-television and Telecommunications Commission, [1983] 1

F.C. 182 (C.A.), aff’d [1985] 1 S.C.R. 174).

52 I understand the City’s arguments to be as follows: (1) the customers acquire

a right to the property of the owner of the utility when they pay for the service and are

therefore entitled to a return on the profits made at the time of the sale of the property;

and (2) the Board has, by necessity, because of its jurisdiction to approve or refuse to

approve the sale of utility assets, the power to allocate the proceeds of the sale as a

condition of its order. The doctrine of jurisdiction by necessary implication is at the heart

of the City’s second argument. I cannot accept either of these arguments which are, in

my view, diametrically contrary to the state of the law. This is revealed when we

scrutinize the entire context which I will now endeavour to do.

53 After a brief review of a few historical facts, I will probe into the main

function of the Board, rate setting, and I will then explore the incidental powers which

can be derived from the context.

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2.3.3.1 Historical Background and Broader Context

54 The history of public utilities regulation in Alberta originated with the

creation in 1915 of the Board of Public Utility Commissioners by The Public Utilities

Act, S.A. 1915, c. 6. This statute was based on similar American legislation:

H. R. Milner, “Public Utility Rate Control in Alberta” (1930), 8 Can. Bar Rev. 101, at

p. 101. While the American jurisprudence and texts in this area should be considered

with caution given that Canada and the United States have very different political and

constitutional-legal regimes, they do shed some light on the issue.

55 Pursuant to The Public Utilities Act, the first public utility board was

established as a three-member tribunal to provide general supervision of all public

utilities (s. 21), to investigate rates (s. 23), to make orders regarding equipment (s. 24),

and to require every public utility to file with it complete schedules of rates (s. 23). Of

interest for our purposes, the 1915 statute also required public utilities to obtain the

approval of the Board of Public Utility Commissioners before selling any property when

outside the ordinary course of their business (s. 29(g)).

56 The Alberta Energy and Utilities Board was created in February 1995 by the

amalgamation of the Energy Resources Conservation Board and the Public Utilities

Board (see Canadian Institute of Resources Law, Canada Energy Law Service: Alberta

(loose-leaf ed.), at p. 30-3101). Since then, all matters under the jurisdiction of the

Energy Resources Conservation Board and the Public Utilities Board have been handled

by the Alberta Energy and Utilities Board and are within its exclusive jurisdiction. The

Board has all of the powers, rights and privileges of its two predecessor boards

(AEUBA, ss. 13, 15(1); GUA, s. 59).

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57 In addition to the powers found in the 1915 statute, which have remained

virtually the same in the present PUBA, the Board now benefits from the following

express powers to:

1. make an order respecting the improvement of the service or commodity

(PUBA, s. 80(b));

2. approve the issue by the public utility of shares, stocks, bonds and other

evidences of indebtedness (GUA, s. 26(2)(a); PUBA, s. 101(2)(a));

3. approve the lease, mortgage, disposition or encumbrance of the public

utility’s property, franchises, privileges or rights (GUA, s. 26(2)(d)(i);

PUBA, s. 101(2)(d)(i));

4. approve the merger or consolidation of the public utility’s property,

franchises, privileges or rights (GUA, s. 26(2)(d)(ii); PUBA, s.

101(2)(d)(ii)); and

5. authorize the sale or permit to be made on the public utility’s book a transfer

of any share of its capital stock to a corporation that would result in the

vesting in that corporation of more than 50 percent of the outstanding capital

stock of the owner of the public utility (GUA, s. 27(1); PUBA, s. 102(1)).

58 It goes without saying that public utilities are very limited in the actions they

can take, as evidenced from the above list. Nowhere is there a mention of the authority

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to allocate proceeds from a sale or the discretion of the Board to interfere with ownership

rights.

59 Even in 1995 when the legislature decided to form the Alberta Energy and

Utilities Board, it did not see fit to modify the PUBA or the GUA to provide the new

Board with the power to allocate the proceeds of a sale even though the controversy

surrounding this issue was full-blown (see, e.g., Re Alberta Government Telephones,

Alta. P.U.B., Decision No. E84081; Re TransAlta Utilities Corp., Alta. P.U.B., Decision

No. E84116). It is a well-established principle that the legislature is presumed to have

a mastery of existing law, both common law and statute law (see Sullivan, at pp. 154-

55). It is also presumed to have known all of the circumstances surrounding the adoption

of new legislation.

60 Although the Board may seem to possess a variety of powers and functions,

it is manifest from a reading of the AEUBA, the PUBA and the GUA that the principal

function of the Board in respect of public utilities is the determination of rates. Its power

to supervise the finances of these companies and their operations, although wide, is in

practice incidental to fixing rates (see Milner, at p. 102; Brown, at p. 2-16.6). Estey J.,

speaking for the majority of this Court in Atco Ltd., at p. 576, echoed this view when he

said:

It is evident from the powers accorded to the Board by the legislaturein both statutes mentioned above that the legislature has given the Board amandate of the widest proportions to safeguard the public interest in thenature and quality of the service provided to the community by the publicutilities. Such an extensive regulatory pattern must, for its effectiveness,include the right to control the combination or, as the legislature says, “theunion” of existing systems and facilities. This no doubt has a directrelationship with the rate-fixing function which ranks high in the authorityand functions assigned to the Board. [Emphasis added.]

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I n f a c t , e v e n t h e B o a r d i t s e l f , o n i t s w e b s i t e

(http://www.eub.gov.ab.ca/BBS/eubinfo/default.htm), describes its functions as follows:

We regulate the safe, responsible, and efficient development ofAlberta’s energy resources: oil, natural gas, oil sands, coal, and electricalenergy; and the pipelines and transmission lines to move the resources tomarket. On the utilities side, we regulate rates and terms of service ofinvestor-owned natural gas, electric, and water utility services, as well as themajor intra-Alberta gas transmission system, to ensure that customersreceive safe and reliable service at just and reasonable rates. [Emphasisadded.]

61 The process by which the Board sets the rates is therefore central and

deserves some attention in order to ascertain the validity of the City’s first argument.

2.3.3.2 Rate Setting

62 Rate regulation serves several aims — sustainability, equity and efficiency

— which underlie the reasoning as to how rates are fixed:

. . . the regulated company must be able to finance its operations, and anyrequired investment, so that it can continue to operate in the future. . . .Equity is related to the distribution of welfare among members of society.The objective of sustainability already implies that shareholders should notreceive “too low” a return (and defines this in terms of the reward necessaryto ensure continued investment in the utility), while equity implies that theirreturns should not be “too high”.

(R. Green and M. Rodriguez Pardina, Resetting Price Controls forPrivatized Utilities: A Manual for Regulators (1999), at p. 5)

63 These goals have resulted in an economic and social arrangement dubbed the

“regulatory compact”, which ensures that all customers have access to the utility at a fair

price — nothing more. As I will further explain, it does not transfer onto the customers

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any property right. Under the regulatory compact, the regulated utilities are given

exclusive rights to sell their services within a specific area at rates that will provide

companies the opportunity to earn a fair return for their investors. In return for this right

of exclusivity, utilities assume a duty to adequately and reliably serve all customers in

their determined territories, and are required to have their rates and certain operations

regulated (see Black, at pp. 356-57; Milner, at p. 101; Atco Ltd., at p. 576; Northwestern

Utilities Ltd. v. City of Edmonton, [1929] S.C.R. 186 (“Northwestern 1929”), at pp. 192-

93).

64 Therefore, when interpreting the broad powers of the Board, one cannot

ignore this well-balanced regulatory arrangement which serves as a backdrop for

contextual interpretation. The object of the statutes is to protect both the customer and

the investor (Milner, at p. 101). The arrangement does not, however, cancel the private

nature of the utility. In essence, the Board is responsible for maintaining a tariff that

enhances the economic benefits to consumers and investors of the utility.

65 The Board derives its power to set rates from both the GUA (ss. 16, 17 and

36 to 45) and the PUBA (ss. 89 to 95). The Board is mandated to fix “just and reasonable

. . . rates” (PUBA, s. 89(a); GUA, s. 36(a)). In the establishment of these rates, the Board

is directed to “determine a rate base for the property of the owner” and “fix a fair return

on the rate base” (GUA, s. 37(1)). This Court, in Northwestern Utilities Ltd. v. City of

Edmonton, [1979] 1 S.C.R. 684 (“Northwestern 1979”), at p. 691, adopted the following

description of the process:

The PUB approves or fixes utility rates which are estimated to coverexpenses plus yield the utility a fair return or profit. This function isgenerally performed in two phases. In Phase I the PUB determines the ratebase, that is the amount of money which has been invested by the company

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in the property, plant and equipment plus an allowance for necessaryworking capital all of which must be determined as being necessary toprovide the utility service. The revenue required to pay all reasonableoperating expenses plus provide a fair return to the utility on its rate base isalso determined in Phase I. The total of the operating expenses plus thereturn is called the revenue requirement. In Phase II rates are set, which,under normal temperature conditions are expected to produce the estimatesof “forecast revenue requirement”. These rates will remain in effect untilchanged as the result of a further application or complaint or the Board’sinitiative. Also in Phase II existing interim rates may be confirmed orreduced and if reduced a refund is ordered.

(See also Re Canadian Western Natural Gas Co., Alta. P.U.B., Decision No. E84113,

October 12, 1984, at p. 23; Re Union Gas Ltd. and Ontario Energy Board (1983), 1

D.L.R. (4th) 698 (Ont. Div. Ct.), at pp. 701-2.)

66 Consequently, when determining the rate base, the Board is to give due

consideration (GUA, s. 37(2)):

(a) to the cost of the property when first devoted to public use and toprudent acquisition cost to the owner of the gas utility, lessdepreciation, amortization or depletion in respect of each, and

(b) to necessary working capital.

67 The fact that the utility is given the opportunity to make a profit on its

services and a fair return on its investment in its assets should not and cannot stop the

utility from benefiting from the profits which follow the sale of assets. Neither is the

utility protected from losses incurred from the sale of assets. In fact, the wording of the

sections quoted above suggests that the ownership of the assets is clearly that of the

utility; ownership of the asset and entitlement to profits or losses upon its realization are

one and the same. The equity investor expects to receive the net revenues after all costs

are paid, equal to the present value of original investment at the time of that investment.

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The disbursement of some portions of the residual amount of net revenue, by after-the-

fact reallocation to rate-paying customers, undermines that investment process:

MacAvoy and Sidak, at p. 244. In fact, speculation would accrue even more often should

the public utility, through its shareholders, not be the one to benefit from the possibility

of a profit, as investors would expect to receive a larger premium for their funds through

the only means left available, the return on their original investment. In addition, they

would be less willing to accept any risk.

68 Thus, can it be said, as alleged by the City, that the customers have a

property interest in the utility? Absolutely not: that cannot be so, as it would mean that

fundamental principles of corporate law would be distorted. Through the rates, the

customers pay an amount for the regulated service that equals the cost of the service and

the necessary resources. They do not by their payment implicitly purchase the asset from

the utility’s investors. The payment does not incorporate acquiring ownership or control

of the utility’s assets. The ratepayer covers the cost of using the service, not the holding

cost of the assets themselves: “A utility’s customers are not its owners, for they are not

residual claimants”: MacAvoy and Sidak, at p. 245 (see also p. 237). Ratepayers have

made no investment. Shareholders have and they assume all risks as the residual

claimants to the utility’s profit. Customers have only “the risk of a price change resulting

from any (authorized) change in the cost of service. This change is determined only

periodically in a tariff review by the regulator” (MacAvoy and Sidak, at p. 245).

69 In this regard, I agree with ATCO when it asserts in its factum, at para. 38:

The property in question is as fully the private property of the owner of theutility as any other asset it owns. Deployment of the asset in utility servicedoes not create or transfer any legal or equitable rights in that property for

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ratepayers. Absent any such interest, any taking such as ordered by theBoard is confiscatory . . . .

Wittmann J.A., at the Court of Appeal, said it best when he stated:

Consumers of utilities pay for a service, but by such payment, do notreceive a proprietary right in the assets of the utility company. Where thecalculated rates represent the fee for the service provided in the relevantperiod of time, ratepayers do not gain equitable or legal rights to non-depreciable assets when they have paid only for the use of those assets.[Emphasis added; para. 64.]

I fully adopt this conclusion. The Board misdirected itself by confusing the interests of

the customers in obtaining safe and efficient utility service with an interest in the

underlying assets owned only by the utility. While the utility has been compensated for

the services provided, the customers have provided no compensation for receiving the

benefits of the subject property. The argument that assets purchased are reflected in the

rate base should not cloud the issue of determining who is the appropriate owner and risk

bearer. Assets are indeed considered in rate setting, as a factor, and utilities cannot sell

an asset used in the service to create a profit and thereby restrict the quality or increase

the price of service. Despite the consideration of utility assets in the rate-setting process,

shareholders are the ones solely affected when the actual profits or losses of such a sale

are realized; the utility absorbs losses and gains, increases and decreases in the value of

assets, based on economic conditions and occasional unexpected technical difficulties,

but continues to provide certainty in service both with regard to price and quality. There

can be a default risk affecting ratepayers, but this does not make ratepayers residual

claimants. While I do not wish to unduly rely on American jurisprudence, I would note

that the leading U.S. case on this point is Duquesne Light Co. v. Barasch, 488 U.S. 299

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(1989), which relies on the same principle as was adopted in Market St. Ry. Co. v.

Railroad Commission of State of California, 324 U.S. 548 (1945).

70 Furthermore, one has to recognize that utilities are not Crown entities,

fraternal societies or cooperatives, or mutual companies, although they have a “public

interest” aspect which is to supply the public with a necessary service (in the present

case, the provision of natural gas). The capital invested is not provided by the public

purse or by the customers; it is injected into the business by private parties who expect

as large a return on the capital invested in the enterprise as they would receive if they

were investing in other securities possessing equal features of attractiveness, stability and

certainty (see Northwestern 1929, at p. 192). This prospect will necessarily include any

gain or loss that is made if the company divests itself of some of its assets, i.e., land,

buildings, etc.

71 From my discussion above regarding the property interest, the Board was in

no position to proceed with an implicit refund by allocating to ratepayers the profits from

the asset sale because it considered ratepayers had paid excessive rates for services in

the past. As such, the City’s first argument must fail. The Board was seeking to rectify

what it perceived as a historic over-compensation to the utility by ratepayers. There is

no power granted in the various statutes for the Board to execute such a refund in respect

of an erroneous perception of past over-compensation. It is well established throughout

the various provinces that utilities boards do not have the authority to retroactively

change rates (Northwestern 1979, at p. 691; Re Coseka Resources Ltd. and Saratoga

Processing Co. (1981), 126 D.L.R. (3d) 705 (Alta. C.A.), at p. 715, leave to appeal

refused, [1981] 2 S.C.R. vii; Re Dow Chemical Canada Inc. (C.A.), at pp. 734-35). But

more importantly, it cannot even be said that there was over-compensation: the rate-

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setting process is a speculative procedure in which both the ratepayers and the

shareholders jointly carry their share of the risk related to the business of the utility (see

MacAvoy and Sidak, at pp. 238-39).

2.3.3.3 The Power to Attach Conditions

72 As its second argument, the City submits that the power to allocate the

proceeds from the sale of the utility’s assets is necessarily incidental to the express

powers conferred on the Board by the AEUBA, the GUA and the PUBA. It argues that

the Board must necessarily have the power to allocate sale proceeds as part of its

discretionary power to approve or refuse to approve a sale of assets. It submits that this

results from the fact that the Board is allowed to attach any condition to an order it

makes approving such a sale. I disagree.

73 The City seems to assume that the doctrine of jurisdiction by necessary

implication applies to “broadly drawn powers” as it does for “narrowly drawn powers”;

this cannot be. The Ontario Energy Board in its decision in Re Consumers’ Gas Co.,

E.B.R.O. 410-II/411-II/412-II, March 23, 1987, at para. 4.73, enumerated the

circumstances when the doctrine of jurisdiction by necessary implication may be applied:

* [when] the jurisdiction sought is necessary to accomplish the objectivesof the legislative scheme and is essential to the Board fulfilling itsmandate;

* [when] the enabling act fails to explicitly grant the power to accomplishthe legislative objective;

* [when] the mandate of the Board is sufficiently broad to suggest alegislative intention to implicitly confer jurisdiction;

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* [when] the jurisdiction sought must not be one which the Board hasdealt with through use of expressly granted powers, thereby showing anabsence of necessity; and

* [when] the Legislature did not address its mind to the issue and decideagainst conferring the power upon the Board.

(See also Brown, at p. 2-16.3.)

74 In light of the above, it is clear that the doctrine of jurisdiction by necessary

implication will be of less help in the case of broadly drawn powers than for narrowly

drawn ones. Broadly drawn powers will necessarily be limited to only what is rationally

related to the purpose of the regulatory framework. This is explained by Professor

Sullivan, at p. 228:

In practice, however, purposive analysis makes the powers conferred onadministrative bodies almost infinitely elastic. Narrowly drawn powers canbe understood to include “by necessary implication” all that is needed toenable the official or agency to achieve the purpose for which the power wasgranted. Conversely, broadly drawn powers are understood to include onlywhat is rationally related to the purpose of the power. In this way the scopeof the power expands or contracts as needed, in keeping with the purpose.[Emphasis added.]

75 In the case at bar, s. 15 of the AEUBA, which allows the Board to impose

additional conditions when making an order, appears at first glance to be a power having

infinitely elastic scope. However, in my opinion, the attempt by the City to use it to

augment the powers of the Board in s. 26(2) of the GUA must fail. The Court must

construe s. 15(3) of the AEUBA in accordance with the purpose of s. 26(2).

76 MacAvoy and Sidak, in their article, at pp. 234-36, suggest three broad

reasons for the requirement that a sale must be approved by the Board:

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1. It prevents the utility from degrading the quality, or reducing the quantity,

of the regulated service so as to harm consumers;

2. It ensures that the utility maximizes the aggregate economic benefits of its

operations, and not merely the benefits flowing to some interest group or

stakeholder; and

3. It specifically seeks to prevent favoritism toward investors.

77 Consequently, in order to impute jurisdiction to a regulatory body to allocate

proceeds of a sale, there must be evidence that the exercise of that power is a practical

necessity for the regulatory body to accomplish the objects prescribed by the legislature,

something which is absent in this case (see National Energy Board Act (Can.) (Re),

[1986] 3 F.C. 275 (C.A.)). In order to meet these three goals, it is not necessary for the

Board to have control over which party should benefit from the sale proceeds. The public

interest component cannot be said to be sufficient to impute to the Board the power to

allocate all the profits pursuant to the sale of assets. In fact, it is not necessary for the

Board in carrying out its mandate to order the utility to surrender the bulk of the

proceeds from a sale of its property in order for that utility to obtain approval for a sale.

The Board has other options within its jurisdiction which do not involve the

appropriation of the sale proceeds, the most obvious one being to refuse to approve a sale

that will, in the Board’s view, affect the quality and/or quantity of the service offered by

the utility or create additional operating costs for the future. This is not to say that the

Board can never attach a condition to the approval of sale. For example, the Board could

approve the sale of the assets on the condition that the utility company gives

undertakings regarding the replacement of the assets and their profitability. It could also

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require as a condition that the utility reinvest part of the sale proceeds back into the

company in order to maintain a modern operating system that achieves the optimal

growth of the system.

78 In my view, allowing the Board to confiscate the net gain of the sale under

the pretence of protecting rate-paying customers and acting in the “public interest”

would be a serious misconception of the powers of the Board to approve a sale; to do so

would completely disregard the economic rationale of rate setting, as I explained earlier

in these reasons. Such an attempt by the Board to appropriate a utility’s excess net

revenues for ratepayers would be highly sophisticated opportunism and would, in the

end, simply increase the utility’s capital costs (MacAvoy and Sidak, at p. 246). At the

risk of repeating myself, a public utility is first and foremost a private business venture

which has as its goal the making of profits. This is not contrary to the legislative scheme,

even though the regulatory compact modifies the normal principles of economics with

various restrictions explicitly provided for in the various enabling statutes. None of the

three statutes applicable here provides the Board with the power to allocate the proceeds

of a sale and therefore affect the property interests of the public utility.

79 It is well established that potentially confiscatory legislative provision ought

to be construed cautiously so as not to strip interested parties of their rights without the

clear intention of the legislation (see Sullivan, at pp. 400-403; Côté, at pp. 482-86;

Pacific National Investments Ltd. v. Victoria (City), [2000] 2 S.C.R. 919, 2000 SCC 64,

at para. 26; Leiriao v. Val-Bélair (Town), [1991] 3 S.C.R. 349, at p. 357; Hongkong Bank

of Canada v. Wheeler Holdings Ltd., [1993] 1 S.C.R. 167, at p. 197). Not only is the

authority to attach a condition to allocate the proceeds of a sale to a particular party

unnecessary for the Board to accomplish its role, but deciding otherwise would lead to

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the conclusion that a broadly drawn power can be interpreted so as to encroach on the

economic freedom of the utility, depriving it of its rights. This would go against the

above principles of interpretation.

80 If the Alberta legislature wishes to confer on ratepayers the economic

benefits resulting from the sale of utility assets, it can expressly provide for this in the

legislation, as was done by some states in the United States (e.g., Connecticut).

2.4 Other Considerations

81 Under the regulatory compact, customers are protected through the rate-

setting process, under which the Board is required to make a well-balanced

determination. The record shows that the City did not submit to the Board a general rate

review application in response to ATCO’s application requesting approval for the sale

of the property at issue in this case. Nonetheless, if it chose to do so, this would not have

stopped the Board, on its own initiative, from convening a hearing of the interested

parties in order to modify and fix just and reasonable rates to give due consideration to

any new economic data anticipated as a result of the sale (PUBA, s. 89(a); GUA, ss. 24,

36(a), 37(3), 40) (see Appendix).

2.5 If Jurisdiction Had Been Found, Was the Board’s Allocation Reasonable?

82 In light of my conclusion with regard to jurisdiction, it is not necessary to

determine whether the Board’s exercise of discretion by allocating the sale proceeds as

it did was reasonable. Nonetheless, given the reasons of my colleague Binnie J., I will

address the issue very briefly. Had I not concluded that the Board lacked jurisdiction, my

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disposition of this case would have been the same, as I do not believe the Board met a

reasonable standard when it exercised its power.

83 I am not certain how one could conclude that the Board’s allocation was

reasonable when it wrongly assumed that ratepayers had acquired a proprietary interest

in the utility’s assets because assets were a factor in the rate-setting process, and,

moreover, when it explicitly concluded that no harm would ensue to customers from the

sale of the asset. In my opinion, when reviewing the substance of the Board’s decision,

a court must conduct a two-step analysis: first, it must determine whether the order was

warranted given the role of the Board to protect the customers (i.e., was the order

necessary in the public interest?); and second, if the first question is answered in the

affirmative, a court must then examine the validity of the Board’s application of the

TransAlta Formula (see para. 12 of these reasons), which refers to the difference

between net book value and original cost, on the one hand, and appreciation in the value

of the asset on the other. For the purposes of this analysis, I view the second step as a

mathematical calculation and nothing more. I do not believe it provides the criteria

which guides the Board to determine if it should allocate part of the sale proceeds to

ratepayers. Rather, it merely guides the Board on what to allocate and how to allocate

it (if it should do so in the first place). It is also interesting to note that there is no

discussion of the fact that the book value used in the calculation must be referable solely

to the financial statements of the utility.

84 In my view, as I have already stated, the power of the Board to allocate

proceeds does not even arise in this case. Even by the Board’s own reasoning, it should

only exercise its discretion to act in the public interest when customers would be harmed

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or would face some risk of harm. But the Board was clear: there was no harm or risk of

harm in the present situation:

With the continuation of the same level of service at other locations andthe acceptance by customers regarding the relocation, the Board isconvinced there should be no impact on the level of service to customers asa result of the Sale. In any event, the Board considers that the service levelto customers is a matter that can be addressed and remedied in a futureproceeding if necessary.

(Decision 2002-037, at para. 54)

After declaring that the customers would not, on balance, be harmed, the Board

maintained that, on the basis of the evidence filed, there appeared to be a cost savings

to the customers. There was no legitimate customer interest which could or needed to be

protected by denying approval of the sale, or by making approval conditional on a

particular allocation of the proceeds. Even if the Board had found a possible adverse

effect arising from the sale, how could it allocate proceeds now based on an unquantified

future potential loss? Moreover, in the absence of any factual basis to support it, I am

also concerned with the presumption of bad faith on the part of ATCO that appears to

underlie the Board’s determination to protect the public from some possible future

menace. In any case, as mentioned earlier in these reasons, this determination to protect

the public interest is also difficult to reconcile with the actual power of the Board to

prevent harm to ratepayers from occurring by simply refusing to approve the sale of a

utility’s asset. To that, I would add that the Board has considerable discretion in the

setting of future rates in order to protect the public interest, as I have already stated.

85 In consequence, I am of the view that, in the present case, the Board did not

identify any public interest which required protection and there was, therefore, nothing

to trigger the exercise of the discretion to allocate the proceeds of sale. Hence,

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notwithstanding my conclusion on the first issue regarding the Board’s jurisdiction, I

would conclude that the Board’s decision to exercise its discretion to protect the public

interest did not meet a reasonable standard.

3. Conclusion

86 This Court’s role in this case has been one of interpreting the enabling

statutes using the appropriate interpretive tools, i.e., context, legislative intention and

objective. Going further than required by reading in unnecessary powers of an

administrative agency under the guise of statutory interpretation is not consistent with

the rules of statutory interpretation. It is particularly dangerous to adopt such an

approach when property rights are at stake.

87 The Board did not have the jurisdiction to allocate the proceeds of the sale

of the utility’s asset; its decision did not meet the correctness standard. Thus, I would

dismiss the City’s appeal and allow ATCO’s cross-appeal, both with costs. I would also

set aside the Board’s decision and refer the matter back to the Board to approve the sale

of the property belonging to ATCO, recognizing that the proceeds of the sale belong to

ATCO.

The reasons of McLachlin C.J. and Binnie and Fish JJ. were delivered by

88 BINNIE J. (dissenting) — The respondent ATCO Gas and Pipelines Ltd.

(“ATCO”) is part of a large entrepreneurial company that directly and through various

subsidiaries operates both regulated businesses and unregulated businesses. The Alberta

Energy and Utilities Board (“Board”) believes it not to be in the public interest to

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encourage utility companies to mix together the two types of undertakings. In particular,

the Board has adopted policies to discourage utilities from using their regulated

businesses as a platform to engage in land speculation to increase their return on

investment outside the regulatory framework. By awarding part of the profit to the

utility (and its shareholders), the Board rewards utilities for diligence in divesting

themselves of assets that are no longer productive, or that could be more productively

employed elsewhere. However, by crediting part of the profit on the sale of such

property to the utility’s rate base (i.e. as a set-off to other costs), the Board seeks to

dampen any incentive for utilities to skew decisions in their regulated business to favour

such profit taking unduly. Such a balance, in the Board’s view, is necessary in the

interest of the public which allows ATCO to operate its utility business as a monopoly.

In pursuit of this balance, the Board approved ATCO’s application to sell land and

warehousing facilities in downtown Calgary, but denied ATCO’s application to keep for

its shareholders the entire profit resulting from appreciation in the value of the land,

whose cost of acquisition had formed part of the rate base on which gas rates had been

calculated since 1922. The Board ordered the profit on the sale to be allocated one third

to ATCO and two thirds as a credit to its cost base, thereby helping keep utility rates

down, and to that extent benefiting ratepayers.

89 I have read with interest the reasons of my colleague Bastarache J. but, with

respect, I do not agree with his conclusion. As will be seen, the Board has authority

under s. 15(3) of the Alberta Energy and Utilities Board Act, R.S.A. 2000, c. A-17

(“AEUBA”), to impose on the sale “any additional conditions that the Board considers

necessary in the public interest”. Whether or not the conditions of approval imposed by

the Board were necessary in the public interest was for the Board to decide. The Alberta

Court of Appeal overruled the Board but, with respect, the Board is in a better position

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to assess necessity in this field for the protection of the public interest than either that

court or this Court. I would allow the appeal and restore the Board’s decision.

I. Analysis

90 ATCO’s argument boils down to the proposition announced at the outset of

its factum:

In the absence of any property right or interest and of any harm to thecustomers arising from the withdrawal from utility service, there was noproper ground for reaching into the pocket of the utility. In essence this caseis about property rights.

(Respondent’s factum, at para. 2)

91 For the reasons which follow I do not believe the case is about property

rights. ATCO chose to make its investment in a regulated industry. The return on

investment in the regulated gas industry is fixed by the Board, not the free market. In

my view, the essential issue is whether the Alberta Court of Appeal was justified in

limiting what the Board is allowed to “conside[r] necessary in the public interest”.

A. The Board’s Statutory Authority

92 The first question is one of jurisdiction. What gives the Board the authority

to make the order ATCO complains about? The Board’s answer is threefold. Section

22(1) of the Gas Utilities Act, R.S.A. 2000, c. G-5 (“GUA”), provides in part that “[t]he

Board shall exercise a general supervision over all gas utilities, and the owners of them

. . .”. This, the Board says, gives it a broad jurisdiction to set policies that go beyond its

specific powers in relation to specific applications, such as rate setting. Of more

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immediate pertinence, s. 26(2)(d)(i) of the same Act prohibits the regulated utility from

selling, leasing or otherwise encumbering any of its property without the Board’s

approval. (To the same effect, see s. 101(2)(d)(i) of the Public Utilities Board Act,

R.S.A. 2000, c. P-45.) It is common ground that this restraint on alienation of property

applies to the proposed sale of ATCO’s land and warehouse facilities in downtown

Calgary, and that the Board could, in appropriate circumstances, simply have denied

ATCO’s application for approval of the sale. However, the Board was of the view to

allow the sale subject to conditions. The Board ruled that the greater power (i.e. to deny

the sale) must include the lesser (i.e. to allow the sale, subject to conditions):

In appropriate circumstances, the Board clearly has the power to prevent autility from disposing of its property. In the Board’s view it also followsthat the Board can approve a disposition subject to appropriate conditionsto protect customer interests.

(Decision 2002-037, [2002] A.E.U.B.D. No. 52 (QL), at para. 47)

There is no need to rely on any such implicit power to impose conditions, however. As

stated, the Board’s explicit power to impose conditions is found in s. 15(3) of the

AEUBA, which authorizes the Board to “make any further order and impose any

additional conditions that the Board considers necessary in the public interest”. In Atco

Ltd. v. Calgary Power Ltd., [1982] 2 S.C.R. 557, at p. 576, Estey J., for the majority,

stated:

It is evident from the powers accorded to the Board by the legislaturein both statutes mentioned above that the legislature has given the Board amandate of the widest proportions to safeguard the public interest in thenature and quality of the service provided to the community by the publicutilities. [Emphasis added.]

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The legislature says in s. 15(3) that the conditions are to be what the Board considers

necessary. Of course, the discretionary power to impose conditions thus granted is not

unlimited. It must be exercised in good faith for its intended purpose: C.U.P.E. v.

Ontario (Minister of Labour), [2003] 1 S.C.R. 539, 2003 SCC 29. ATCO says the Board

overstepped even these generous limits. In ATCO’s submission:

Deployment of the asset in utility service does not create or transfer anylegal or equitable rights in that property for ratepayers. Absent any suchinterest, any taking such as ordered by the Board is confiscatory . . . .

(Respondent’s factum, at para. 38)

In my view, however, the issue before the Board was how much profit ATCO was

entitled to earn on its investment in a regulated utility.

93 ATCO argues in the alternative that the Board engaged in impermissible

“retroactive rate making”. But Alberta is an “original cost” jurisdiction, and no one

suggests that the Board’s original cost rate making during the 80-plus years this

investment has been reflected in ATCO’s ratebase was wrong. The Board proposed to

apply a portion of the expected profit to future rate making. The effect of the order is

prospective, not retroactive. Fixing the going-forward rate of return as well as general

supervision of “all gas utilities, and the owners of them” were matters squarely within

the Board’s statutory mandate.

B. The Board’s Decision

94 ATCO argues that the Board’s decision should be seen as a stand-alone

decision divorced from its rate-making responsibilities. However, I do not agree that the

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hearing under s. 26 of the GUA can be isolated in this way from the Board’s general

regulatory responsibilities. ATCO argues in its factum that

the subject application by [ATCO] to the Board did not concern or relate toa rate application, and the Board was not engaged in fixing rates (if thatcould provide any justification, which is denied).

(Respondent’s factum, at para. 98)

95 It seems the Board proceeded with the s. 26 approval hearing separately from

a rate setting hearing firstly because ATCO framed the proceeding in that way and

secondly because this is the procedure approved by the Alberta Court of Appeal in

TransAlta Utilities Corp. v. Public Utilities Board (Alta.) (1986), 68 A.R. 171. That case

(which I will refer to as TransAlta (1986)) is a leading Alberta authority dealing with the

allocation of the gain on the disposal of utility assets and the source of what is called the

TransAlta Formula applied by the Board in this case. Kerans J.A. had this to say, at p.

174:

I observe parenthetically that I now appreciate that it suits the convenienceof everybody involved to resolve issues of this sort, if possible, before ageneral rate hearing so as to lessen the burden on that already complexprocedure.

96 Given this encouragement from the Alberta Court of Appeal, I would place

little significance on ATCO’s procedural point. As will be seen, the Board’s ruling is

directly tied into the setting of general rates because two thirds of the profit is taken into

account as an offset to ATCO’s costs from which its revenue requirement is ultimately

derived. As stated, ATCO’s profit on the sale of the Calgary property will be a current

(not historical) receipt and, if the Board has its way, two thirds of it will be applied to

future (not retroactive) rate making.

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97 The s. 26 hearing proceeded in two phases. The Board first determined that

it would not deny its approval to the proposed sale as it met a “no-harm test” devised

over the years by Board practice (it is not to be found in the statutes) (Decision 2001-78).

However, the Board linked its approval to subsequent consideration of the financial

ramifications, as the Board itself noted:

The Board approved the Sale in Decision 2001-78 based on evidence thatcustomers did not object to the Sale [and] would not suffer a reduction inservices nor would they be exposed to the risk of financial harm as a resultof the Sale that could not be examined in a future proceeding. On that basisthe Board determined that the no-harm test had been satisfied and that theSale could proceed. [Underlining and italics added.]

(Decision 2002-037, at para. 13)

98 In effect, ATCO ignores the italicized words. It argues that the Board was

functus after the first phase of its hearing. However, ATCO itself had agreed to the two-

phase procedure, and indeed the second phase was devoted to ATCO’s own application

for an allocation of the profits on the sale.

99 In the second phase of the s. 26 approval hearing, the Board allocated one

third of the net gain to ATCO and two thirds to the rate base (which would benefit

ratepayers). The Board spelled out why it considered these conditions to be necessary

in the public interest. The Board explained that it was necessary to balance the interests

of both shareholders and ratepayers within the framework of what it called “the

regulatory compact” (Decision 2002-037, at para. 44). In the Board’s view:

(a) there ought to be a balancing of the interests of the ratepayers and the

owners of the utility;

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(b) decisions made about the utility should be driven by both parties’

interests;

(c) to award the entire gain to the ratepayers would deny the utility an

incentive to increase its efficiency and reduce its costs; and

(d) to award the entire gain to the utility might encourage speculation in

non-depreciable property or motivate the utility to identify and dispose of

properties which have appreciated for reasons other than the best interest of

the regulated business.

100 For purposes of this appeal, it is important to set out the Board’s policy

reasons in its own words:

To award the entire net gain on the land and buildings to the customers,while beneficial to the customers, could establish an environment that maydeter the process wherein the company continually assesses its operation toidentify, evaluate, and select options that continually increase efficiency andreduce costs.

Conversely, to award the entire net gain to the company may establishan environment where a regulated utility company might be moved tospeculate in non-depreciable property or result in the company beingmotivated to identify and sell existing properties where appreciation hasalready occurred.

The Board believes that some method of balancing both parties’interests will result in optimization of business objectives for both thecustomer and the company. Therefore, the Board considers that sharing ofthe net gain on the sale of the land and buildings collectively in accordancewith the TransAlta Formula is equitable in the circumstances of thisapplication and is consistent with past Board decisions. [Emphasis added;paras. 112-14.]

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101 The Court was advised that the two-third share allocated to ratepayers would

be included in ATCO’s rate calculation to set off against the costs included in the rate

base and amortized over a number of years.

C. Standard of Review

102 The Court’s modern approach to this vexed question was recently set out by

McLachlin C.J. in Dr. Q v. College of Physicians and Surgeons of British Columbia,

[2003] 1 S.C.R. 226, 2003 SCC 19, at para. 26:

In the pragmatic and functional approach, the standard of review isdetermined by considering four contextual factors — the presence orabsence of a privative clause or statutory right of appeal; the expertise of thetribunal relative to that of the reviewing court on the issue in question; thepurposes of the legislation and the provision in particular; and, the nature ofthe question — law, fact, or mixed law and fact. The factors may overlap.The overall aim is to discern legislative intent, keeping in mind theconstitutional role of the courts in maintaining the rule of law.

103 I do not propose to cover the ground already set out in the reasons of my

colleague Bastarache J. We agree that the standard of review on matters of jurisdiction

is correctness. We also agree that the Board’s exercise of its jurisdiction calls for greater

judicial deference. Appeals from the Board are limited to questions of law or

jurisdiction. The Board knows a great deal more than the courts about gas utilities, and

what limits it is necessary to impose “in the public interest” on their dealings with assets

whose cost is included in the rate base. Moreover, it is difficult to think of a broader

discretion than that conferred on the Board to “impose any additional conditions that the

Board considers necessary in the public interest” (s. 15(3)(d) of the AEUBA). The

identification of a subjective discretion in the decision maker (“the Board considers

necessary”), the expertise of that decision maker and the nature of the decision to be

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made (“in the public interest”), in my view, call for the most deferential standard, patent

unreasonableness.

104 As to the phrase “the Board considers necessary”, Martland J. stated in

Calgary Power Ltd. v. Copithorne, [1959] S.C.R. 24, at p. 34:

The question as to whether or not the respondent’s lands were“necessary” is not one to be determined by the Courts in this case. Thequestion is whether the Minister “deemed” them to be necessary.

See also D. J. M. Brown and J. M. Evans, Judicial Review of Administrative Action in

Canada (loose-leaf ed.), vol. 1, at para. 14:2622: “‘Objective’ and ‘Subjective’ Grants

of Discretion”.

105 The expert qualifications of a regulatory Board are of “utmost importance

in determining the intention of the legislator with respect to the degree of deference to

be shown to a tribunal’s decision in the absence of a full privative clause”, as stated by

Sopinka J. in United Brotherhood of Carpenters and Joiners of America, Local 579 v.

Bradco Construction Ltd., [1993] 2 S.C.R. 316, at p. 335. He continued:

Even where the tribunal’s enabling statute provides explicitly for appellatereview, as was the case in Bell Canada [v. Canada (Canadian Radio-Television and Telecommunications Commission), [1989] 1 S.C.R. 1722],it has been stressed that deference should be shown by the appellate tribunalto the opinions of the specialized lower tribunal on matters squarely withinits jurisdiction.

(This dictum was cited with approval in Pezim v. British Columbia (Superintendent of

Brokers), [1994] 2 S.C.R. 557, at p. 592.)

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106 A regulatory power to be exercised “in the public interest” necessarily

involves accommodation of conflicting economic interests. It has long been recognized

that what is “in the public interest” is not really a question of law or fact but is an

opinion. In TransAlta (1986), the Alberta Court of Appeal (at para. 24) drew a parallel

between the scope of the words “public interest” and the well-known phrase “public

convenience and necessity” in its citation of Memorial Gardens Association (Canada)

Ltd. v. Colwood Cemetery Co., [1958] S.C.R. 353, where this Court stated, at p. 357:

[T]he question whether public convenience and necessity requires a certainaction is not one of fact. It is predominantly the formulation of an opinion.Facts must, of course, be established to justify a decision by the Commissionbut that decision is one which cannot be made without a substantial exerciseof administrative discretion. In delegating this administrative discretion tothe Commission the Legislature has delegated to that body the responsibilityof deciding, in the public interest . . . . [Emphasis added.]

107 This passage reiterated the dictum of Rand J. in Union Gas Co. of Canada

Ltd. v. Sydenham Gas and Petroleum Co., [1957] S.C.R. 185, at p. 190:

It was argued, and it seems to have been the view of the Court, that thedetermination of public convenience and necessity was itself a question offact, but with that I am unable to agree: it is not an objective existence to beascertained; the determination is the formulation of an opinion, in this case,the opinion of the Board and of the Board only. [Emphasis added.]

108 Of course even such a broad power is not untrammelled. But to say that such

a power is capable of abuse does not lead to the conclusion that it should be truncated.

I agree on this point with Reid J. (co-author of R. F. Reid and H. David, Administrative

Law and Practice (2nd ed. 1978), and co-editor of P. Anisman and R. F. Reid,

Administrative Law Issues and Practice (1995)), who wrote in Re C.T.C. Dealer

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Holdings Ltd. and Ontario Securities Commission (1987), 59 O.R. (2d) 79 (Div. Ct.),

in relation to the powers of the Ontario Securities Commission, at p. 97:

. . . when the Commission has acted bona fide, with an obvious and honestconcern for the public interest, and with evidence to support its opinion, theprospect that the breadth of its discretion might someday tempt it to placeitself above the law by misusing that discretion is not something that makesthe existence of the discretion bad per se, and requires the decision to bestruck down.

(The C.T.C. Dealer Holdings decision was referred to with apparent approval by this

Court in Committee for the Equal Treatment of Asbestos Minority Shareholders v.

Ontario (Securities Commission), [2001] 2 S.C.R. 132, 2001 SCC 37, at para. 42.)

109 “Patent unreasonableness” is a highly deferential standard:

A correctness approach means that there is only one proper answer. Apatently unreasonable one means that there could have been manyappropriate answers, but not the one reached by the decision maker.

(C.U.P.E., at para. 164)

110 Having said all that, in my view nothing much turns on the result on whether

the proper standard in that regard is patent unreasonableness (as I view it) or simple

reasonableness (as my colleague sees it). As will be seen, the Board’s response is well

within the range of established regulatory opinions. Hence, even if the Board’s

conditions were subject to the less deferential standard, I would find no cause for the

Court to interfere.

D. Did the Board Have Jurisdiction to Impose the Conditions It Did on the ApprovalOrder “In the Public Interest”?

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111 ATCO says the Board had no jurisdiction to impose conditions that are

“confiscatory”. Framing the question in this way, however, assumes the point in issue.

The correct point of departure is not to assume that ATCO is entitled to the net gain and

then ask if the Board can confiscate it. ATCO’s investment of $83,000 was added in

increments to its regulatory cost base as the land was acquired from time to time between

1922 and 1965. It is in the nature of a regulated industry that the question of what is a

just and equitable return is determined by a board and not by the vagaries of the

speculative property market.

112 I do not think the legal debate is assisted by talk of “confiscation”. ATCO

is prohibited by statute from disposing of the asset without Board approval, and the

Board has statutory authority to impose conditions on its approval. The issue thus

necessarily turns not on the existence of the jurisdiction but on the exercise of the

Board’s jurisdiction to impose the conditions that it did, and in particular to impose a

shared allocation of the net gain.

E. Did the Board Improperly Exercise the Jurisdiction It Possessed to ImposeConditions the Board Considered “Necessary in the Public Interest”?

113 There is no doubt that there are many approaches to “the public interest”.

Which approach the Board adopts is largely (and inherently) a matter of opinion and

discretion. While the statutory framework of utilities regulation varies from jurisdiction

to jurisdiction, and practice in the United States must be read in light of the constitutional

protection of property rights in that country, nevertheless Alberta’s grant of authority to

its Board is more generous than most. ATCO concedes that its “property” claim would

have to give way to a contrary legislative intent, but ATCO says such intent cannot be

found in the statutes.

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114 Most if not all regulators face the problem of how to allocate gains on

property whose original cost is included in the rate base but is no longer required to

provide the service. There is a wealth of regulatory experience in many jurisdictions that

the Board is entitled to (and does) have regard to in formulating its policies. Striking the

correct balance in the allocation of gains between ratepayers and investors is a common

preoccupation of comparable boards and agencies:

First, it prevents the utility from degrading the quality, or reducing thequantity, of the regulated service so as to harm consumers. Second, itensures that the utility maximizes the aggregate economic benefits of itsoperations, and not merely the benefits flowing to some interest group orstakeholder. Third, it specifically seeks to prevent favoritism towardinvestors to the detriment of ratepayers affected by the transaction.

(P. W. MacAvoy and J. G. Sidak, “The Efficient Allocation of Proceedsfrom a Utility’s Sale of Assets” (2001), 22 Energy L.J. 233, at p. 234)

115 The concern with which Canadian regulators view utilities under their

jurisdiction that are speculating in land is not new. In Re Consumers’ Gas Co., E.B.R.O.

341-I, June 30, 1976, the Ontario Energy Board considered how to deal with a real estate

profit on land which was disposed of at an after-tax profit of over $2 million. The Board

stated:

The Station “B” property was not purchased by Consumers’ for landspeculation but was acquired for utility purposes. This investment, whilenon-depreciable, was subject to interest charges and risk paid for throughrevenues and, until the gas manufacturing plant became obsolete, disposalof the land was not a feasible option. If, in such circumstances, the Boardwere to permit real estate profit to accrue to the shareholders only, it wouldtend to encourage real estate speculation with utility capital. In the Board’sopinion, the shareholders and the ratepayers should share the benefits ofsuch capital gains. [Emphasis added; para. 326.]

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116 Some U.S. regulators also consider it good regulatory policy to allocate part

or all of the profit to offset costs in the rate base. In Re Boston Gas Co., 49 P.U.R. 4th

1 (Mass. D.P.U. 1982), the regulator allocated a gain on the sale of land to ratepayers,

stating:

The company and its shareholders have received a return on the use ofthese parcels while they have been included in rate base, and are not entitledto any additional return as a result of their sale. To hold otherwise would beto find that a regulated utility company may speculate in nondepreciableutility property and, despite earning a reasonable rate of return from itscustomers on that property, may also accumulate a windfall through its sale.We find this to be an uncharacteristic risk/reward situation for a regulatedutility to be in with respect to its plant in service. [Emphasis added; p. 26.]

117 Canadian regulators other than the Board are also concerned with the

prospect that decisions of utilities in their regulated business may be skewed under the

undue influence of prospective profits on land sales. In Re Consumers’ Gas Co.,

E.B.R.O. 465, March 1, 1991, the Ontario Energy Board determined that a $1.9 million

gain on sale of land should be divided equally between shareholders and ratepayers. It

held that

the allocation of 100 percent of the profit from land sales to either theshareholders or the ratepayers might diminish the recognition of the validconcerns of the excluded party. For example, the timing and intensity ofland purchase and sales negotiations could be skewed to favour or disregardthe ultimate beneficiary. [para. 3.3.8]

118 The Board’s principle of dividing the gain between investors and ratepayers

is consistent, as well, with Re Natural Resource Gas Ltd., RP-2002-0147, EB-2002-

0446, June 27, 2003, in which the Ontario Energy Board addressed the allocation of a

profit on the sale of land and buildings and again stated:

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The Board finds that it is reasonable in the circumstances that the capitalgains be shared equally between the Company and its customers. In makingthis finding the Board has considered the non-recurring nature of thistransaction. [para. 45]

119 The wide variety of regulatory treatment of such gains was noted by Kerans

J.A. in TransAlta (1986), at pp. 175-76, including Re Boston Gas Co. mentioned earlier.

In TransAlta (1986), the Board characterized TransAlta’s gain on the disposal of land

and buildings included in its Edmonton “franchise” as “revenue” within the meaning of

the Hydro and Electric Energy Act, R.S.A. 1980, c. H-13. (The case therefore did not

deal with the power to impose conditions “the Board considers necessary in the public

interest”.) Kerans J.A. said (at p. 176):

I do not agree with the Board’s decision for reasons later expressed, butit would be fatuous to deny that its interpretation [of the word “revenue”] isone which the word can reasonably bear.

Kerans J.A. went on to find that in that case “[t]he compensation was, for all practical

purposes, compensation for loss of franchise” (p. 180) and on that basis the gain in these

“unique circumstances” (p. 179) could not, as a matter of law, be characterized as

revenue, i.e. applying a correctness standard. The range of regulatory practice on the

“gains on sale” issue was similarly noted by Goldie J.A. in Yukon Energy Corp. v.

Utilities Board (1996), 74 B.C.A.C. 58 (Y.C.A.), at para. 85.

120 A survey of recent regulatory experience in the United States reveals the

wide variety of treatment in that country of gains on the sale of undepreciated land. The

range includes proponents of ATCO’s preferred allocation as well as proponents of the

solution adopted by the Board in this case:

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Some jurisdictions have concluded that as a matter of equity,shareholders alone should benefit from any gain realized on appreciated realestate, because ratepayers generally pay only for taxes on the land and donot contribute to the cost of acquiring the property and pay no depreciationexpenses. Under this analysis, ratepayers assume no risk for losses andacquire no legal or equitable interest in the property, but rather pay only forthe use of the land in utility service.

Other jurisdictions claim that ratepayers should retain some of thebenefits associated with the sale of property dedicated to utility service.Those jurisdictions that have adopted an equitable sharing approach agreethat a review of regulatory and judicial decisions on the issue does not revealany general principle that requires the allocation of benefits solely toshareholders; rather, the cases show only a general prohibition againstsharing benefits on the sale property that has never been reflected in utilityrates.

(P. S. Cross, “Rate Treatment of Gain on Sale of Land: RatepayerIndifference, A New Standard?” (1990), 126 Pub. Util. Fort. 44, at p. 44)

Regulatory opinion in the United States favourable to the solution adopted here by the

Board is illustrated by Re Arizona Public Service Co., 91 P.U.R. 4th 337 (Ariz. C.C.

1988), at p. 361:

To the extent any general principles can be gleaned from the decisions inother jurisdictions they are: (1) the utility’s stockholders are notautomatically entitled to the gains from all sales of utility property; and (2)ratepayers are not entitled to all or any part of a gain from the sale ofproperty which has never been reflected in the utility’s rates. [Emphasis inoriginal.]

121 Assets purchased with capital reflected in the rate base come and go, but the

utility itself endures. What was done by the Board in this case is quite consistent with

the “enduring enterprise” theory espoused, for example, in Re Southern California Water

Co., 43 C.P.U.C. 2d 596 (1992). In that case, Southern California Water had asked for

approval to sell an old headquarters building and the issue was how to allocate its profits

on the sale. The Commission held:

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Working from the principle of the “enduring enterprise”, the gain-on-salefrom this transaction should remain within the utility’s operations ratherthan being distributed in the short run directly to either ratepayers orshareholders.

The “enduring enterprise” principle, is neither novel nor radical. It wasclearly articulated by the Commission in its seminal 1989 policy decision onthe issue of gain-on-sale, D.89-07-016, 32 Cal. P.U.C.2d 233 (Redding).Simply stated, to the extent that a utility realizes a gain-on-sale from theliquidation of an asset and replaces it with another asset or obligation whileat the same time its responsibility to serve its customers is neither relievednor reduced, then any gain-on-sale should remain within the utility’soperation. [p. 604]

122 In my view, neither the Alberta statutes nor regulatory practice in Alberta

and elsewhere dictates the answer to the problems confronting the Board. It would have

been open to the Board to allow ATCO’s application for the entire profit. But the

solution it adopted was quite within its statutory authority and does not call for judicial

intervention.

F. ATCO’s Arguments

123 Most of ATCO’s principal submissions have already been touched on but

I will repeat them here for convenience. ATCO does not really dispute the Board’s

ability to impose conditions on the sale of land. Rather, ATCO says that what the Board

did here violates a number of basic legal protections and principles. It asks the Court to

clip the Board’s wings.

124 Firstly, ATCO says that customers do not acquire any proprietary right in the

company’s assets. ATCO, rather than its customers, originally purchased the property,

held title to it, and therefore was entitled to any gain on its sale. An allocation of profit

to the customers would amount to a confiscation of the corporation’s property.

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125 Secondly, ATCO says its retention of 100 percent of the gain has nothing to

do with the so-called “regulatory compact”. The gas customers paid what the Board

regarded over the years as a fair price for safe and reliable service. That is what the

ratepayers got and that is all they were entitled to. The Board’s allocation of part of the

profit to the ratepayers amounts to impermissible “retroactive” rate setting.

126 Thirdly, utilities are not entitled to include in the rate base an amount for

depreciation on land and ratepayers have therefore not repaid ATCO any part of

ATCO’s original cost, let alone the present value. The treatment accorded gain on sales

of depreciated property therefore does not apply.

127 Fourthly, ATCO complains that the Board’s solution is asymmetrical.

Ratepayers are given part of the benefit of an increase in land values without, in a falling

market, bearing any part of the burden of losses on the disposition of land.

128 In my view, these are all arguments that should be (and were) properly

directed to the Board. There are indeed precedents in the regulatory field for what

ATCO proposes, just as there are precedents for what the ratepayers proposed. It was

for the Board to decide what conditions in these particular circumstances were necessary

in the public interest. The Board’s solution in this case is well within the range of

reasonable options, as I will endeavour to demonstrate.

1. The Confiscation Issue

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129 In its factum, ATCO says that “[t]he property belonged to the owner of the

utility and the Board’s proposed distribution cannot be characterized otherwise than as

being confiscatory” (respondent’s factum, at para. 6). ATCO’s argument overlooks the

obvious difference between investment in an unregulated business and investment in a

regulated utility where the regulator sets the return on investment, not the marketplace.

In Re Southern California Gas Co., 118 P.U.R. 4th 81 (C.P.U.C. 1990) (“SoCalGas”),

the regulator pointed out:

In the non-utility private sector, investors are not guaranteed to earn a fairreturn on such sunk investment. Although shareholders and bondholdersprovide the initial capital investment, the ratepayers pay the taxes,maintenance, and other costs of carrying utility property in rate base over theyears, and thus insulate utility investors from the risk of having to pay thosecosts. Ratepayers also pay the utility a fair return on property (includingland) while it is in rate base, compensate the utility for the diminishment ofthe value of its depreciable property over time through depreciationaccounting, and bear the risk that they must pay depreciation and a return onprematurely retired rate base property. [p. 103]

(It is understood, of course, that the Board does not appropriate the actual proceeds of

sale. What happens is that an amount equivalent to two-thirds of the profit is included

in the calculation of ATCO’s current cost base for rate-making purposes. In that way,

there is a notional distribution of the benefit of the gain amongst the competing

stakeholders.)

130 ATCO’s argument is frequently asserted in the United States under the flag

of constitutional protection for “property”. Constitutional protection has not however

prevented allocation of all or part of such gains to the U.S. ratepayers. One of the

leading U.S. authorities is Democratic Central Committee of the District of Columbia

v. Washington Metropolitan Area Transit Commission, 485 F.2d 786 (D.C. Cir. 1973).

In that case, the assets at issue were parcels of real estate which had been employed in

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mass transit operations but which were no longer needed when the transit system

converted to buses. The regulator awarded the profit on the appreciated land values to

the shareholders but the Court of Appeals reversed the decision, using language directly

applicable to ATCO’s “confiscation” argument:

We perceive no impediment, constitutional or otherwise, to recognitionof a ratemaking principle enabling ratepayers to benefit from appreciationsin value of utility properties accruing while in service. We believe thedoctrinal consideration upon which pronouncements to the contrary haveprimarily rested has lost all present-day vitality. Underlying thesepronouncements is a basic legal and economic thesis — sometimesarticulated, sometimes implicit — that utility assets, though dedicated to thepublic service, remain exclusively the property of the utility’s investors, andthat growth in value is an inseparable and inviolate incident of that propertyinterest. The precept of private ownership historically pervading ourjurisprudence led naturally to such a thesis, and early decisions in theratemaking field lent some support to it; if still viable, it strengthens theinvestor’s claim. We think, however, after careful exploration, that thefoundations for that approach, and the conclusion it seemed to indicate, havelong since eroded away. [p. 800]

The court’s reference to “pronouncements” which have “lost all present-day vitality”

likely includes Board of Public Utility Commissioners v. New York Telephone Co., 271

U.S. 23 (1976), a decision relied upon in this case by ATCO. In that case, the Supreme

Court of the United States said:

Customers pay for service, not for the property used to render it. Theirpayments are not contributions to depreciation or other operating expensesor to capital of the company. By paying bills for service they do not acquireany interest, legal or equitable, in the property used for their convenience orin the funds of the company. Property paid for out of moneys received forservice belongs to the company just as does that purchased out of proceedsof its bonds and stock. [p. 32]

In that case, the regulator belatedly concluded that the level of depreciation allowed the

New York Telephone Company had been excessive in past years and sought to remedy

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the situation in the current year by retroactively adjusting the cost base. The court held

that the regulator had no power to re-open past rates. The financial fruits of the

regulator’s errors in past years now belonged to the company. That is not this case. No

one contends that the Board’s prior rates, based on ATCO’s original investment, were

wrong. In 2001, when the matter came before the Board, the Board had jurisdiction to

approve or not approve the proposed sale. It was not a done deal. The receipt of any

profit by ATCO was prospective only. As explained in Re Arizona Public Service Co.:

In New York Telephone, the issue presented was whether a stateregulatory commission could use excessive depreciation accruals from prioryears to reduce rates for future service and thereby set rates which did notyield a just return. . . . [T]he Court simply reiterated and provided thereasons for a ratemaking truism: rates must be designed to produce enoughrevenue to pay current (reasonable) operating expenses and provide a fairreturn to the utility’s investors. If it turns out that, for whatever reason,existing rates have produced too much or too little income, the past is past.Rates are raised or lowered to reflect current conditions; they are notdesigned to pay back past excessive profits or recoup past operating losses.In contrast, the issue in this proceeding is whether for ratemaking purposesa utility’s test year income from sales of utility service can include itsincome from sales of utility property. The United States Supreme Court’sdecision in New York Telephone does not address that issue. [Emphasisadded; p. 361.]

131 More recently, the allocation of gain on sale was addressed by the California

Public Utilities Commission in SoCalGas. In that case, as here, the utility (SoCalGas)

wished to sell land and buildings located (in that case) in downtown Los Angeles. The

Commission apportioned the gain on sale between the shareholders and the ratepayers,

concluding that:

We believe that the issue of who owns the utility property providingutility service has become a red herring in this case, and that ownershipalone does not determine who is entitled to the gain on the sale of theproperty providing utility service when it is removed from rate base andsold. [p. 100]

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132 ATCO argues in its factum that ratepayers “do not acquire any interest, legal

or equitable, in the property used to provide the service or in the funds of the owner of

the utility” (para. 2). In SoCalGas, the regulator disposed of this point as follows:

No one seriously argues that ratepayers acquire title to the physical propertyassets used to provide utility service; DRA [Division of RatepayerAdvocates] argues that the gain on sale should reduce future revenuerequirements not because ratepayers own the property, but rather becausethey paid the costs and faced the risks associated with that property while itwas in rate base providing public service. [p. 100]

This “risk” theory applies in Alberta as well. Over the last 80 years, there have been

wild swings in Alberta real estate, yet through it all, in bad times and good, the

ratepayers have guaranteed ATCO a just and equitable return on its investment in this

land and these buildings.

133 The notion that the division of risk justifies a division of the net gain was

also adopted by the regulator in SoCalGas:

Although the shareholders and bondholders provided the initial capitalinvestment, the ratepayers paid the taxes, maintenance, and other costs ofcarrying the land and buildings in rate base over the years, and paid theutility a fair return on its unamortized investment in the land and buildingswhile they were in rate base. [p. 110]

In other words, even in the United States, where property rights are constitutionally

protected, ATCO’s “confiscation” point is rejected as an oversimplification.

134 My point is not that the Board’s allocation in this case is necessarily correct

in all circumstances. Other regulators have determined that the public interest requires

a different allocation. The Board proceeds on a “case-by-case” basis. My point simply

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is that the Board’s response in this case cannot be considered “confiscatory” in any

proper use of the term, and is well within the range of what are regarded in comparable

jurisdictions as appropriate regulatory responses to the allocation of the gain on sale of

land whose original investment has been included by the utility itself in its rate base.

The Board’s decision is protected by a deferential standard of review and in my view it

should not have been set aside.

2. The Regulatory Compact

135 The Board referred in its decision to the “regulatory compact” which is a

loose expression suggesting that in exchange for a statutory monopoly and receipt of

revenue on a cost plus basis, the utility accepts limitations on its rate of return and its

freedom to do as it wishes with property whose cost is reflected in its rate base. This was

expressed in the Washington Metropolitan Area Transit case by the U.S. Court of

Appeals for the District of Columbia Circuit as follows:

The ratemaking process involves fundamentally “a balancing of theinvestor and the consumer interests”. The investor’s interest lies in theintegrity of his investment and a fair opportunity for a reasonable returnthereon. The consumer’s interest lies in governmental protection againstunreasonable charges for the monopolistic service to which he subscribes.In terms of property value appreciations, the balance is best struck at thepoint at which the interests of both groups receive maximumaccommodation. [p. 806]

136 ATCO considers that the Board’s allocation of profit violated the regulatory

compact not only because it is confiscatory but because it amounts to “retroactive rate

making”. In Northwestern Utilities Ltd. v. City of Edmonton, [1979] 1 S.C.R. 684, Estey

J. stated, at p. 691:

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It is clear from many provisions of The Gas Utilities Act that the Board mustact prospectively and may not award rates which will recover expensesincurred in the past and not recovered under rates established for pastperiods.

137 As stated earlier, the Board in this case was addressing a prospective receipt

and allocated two thirds of it to a prospective (not retroactive) rate-making exercise.

This is consistent with regulatory practice, as is illustrated by New York Water Service

Corp. v. Public Service Commission, 208 N.Y.S.2d 857 (1960). In that case, a utility

commission ruled that gains on the sale of real estate should be taken into account to

reduce rates annually over the following period of 17 years :

If land is sold at a profit, it is required that the profit be added to, i.e.,“credited to”, the depreciation reserve, so that there is a correspondingreduction of the rate base and resulting return. [p. 864]

The regulator’s order was upheld by the New York State Supreme Court (Appellate

Division).

138 More recently, in Re Compliance with the Energy Policy Act of 1992, 62

C.P.U.C. 2d 517 (1995), the regulator commented:

. . . we found it appropriate to allocate the principal amount of the gain tooffset future costs of headquarters facilities, because ratepayers had bornethe burden of risks and expenses while the property was in ratebase. At thesame time, we found that it was equitable to allocate a portion of the benefitsfrom the gain-on-sale to shareholders in order to provide a reasonableincentive to the utility to maximize the proceeds from selling such propertyand compensate shareholders for any risks borne in connection with holdingthe former property. [p. 529]

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139 The emphasis in all these cases is on balancing the interests of the

shareholders and the ratepayers. This is perfectly consistent with the “regulatory

compact” approach reflected in the Board doing what it did in this case.

3. Land as a Non-Depreciable Asset

140 The Alberta Court of Appeal drew a distinction between gains on sale of

land, whose original cost is not depreciated (and thus is not repaid in increments through

the rate base) and depreciated property such as buildings where the rate base does

include a measure of capital repayment and which in that sense the ratepayers have “paid

for”. The Alberta Court of Appeal held that the Board was correct to credit the rate base

with an amount equivalent to the depreciation paid in respect of the buildings (this is the

subject matter of ATCO’s cross-appeal). Thus, in this case, the land was still carried on

ATCO’s books at its original price of $83,720 whereas the original $596,591 cost of the

buildings had been depreciated through the rates charged customers to a net book value

of $141,525.

141 Regulatory practice shows that many (not all) regulators also do not accept

the distinction (for this purpose) between depreciable and non-depreciable assets. In Re

Boston Gas Co. for example (cited in TransAlta (1986), at p. 176), the regulator held:

. . . the company’s ratepayers have been paying a return on this land as wellas all other costs associated with its use. The fact that land is anondepreciable asset because its useful value is not ordinarily diminishedthrough use is, we find, irrelevant to the question of who is entitled to theproceeds on the sales of this land. [p. 26]

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142 In SoCalGas, as well, the Commission declined to make a distinction

between the gain on sale of depreciable, as compared to non-depreciable, property,

stating: “We see little reason why land sales should be treated differently” (p. 107). The

decision continued:

In short, whether an asset is depreciated for ratemaking purposes or not,ratepayers commit to paying a return on its book value for as long as it isused and useful. Depreciation simply recognizes the fact that certain assetsare consumed over a period of utility service while others are not. The basicrelationship between the utility and its ratepayers is the same for depreciableand non-depreciable assets. [Emphasis added; p. 107.]

143 In Re California Water Service Co., 66 C.P.U.C. 2d 100 (1996), the regulator

commented that:

Our decisions generally find no reason to treat gain on the sale ofnondepreciable property, such as bare land, different[ly] than gains on thesale of depreciable rate base assets and land in PHFU [plant held for futureuse]. [p. 105]

144 Again, my point is not that the regulator must reject any distinction between

depreciable and non-depreciable property. Simply, my point is that the distinction does

not have the controlling weight as contended by ATCO. In Alberta, it is up to the Board

to determine what allocations are necessary in the public interest as conditions of the

approval of sale. ATCO’s attempt to limit the Board’s discretion by reference to various

doctrine is not consistent with the broad statutory language used by the Alberta

legislature and should be rejected.

4. Lack of Reciprocity

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145 ATCO argues that the customers should not profit from a rising market

because if the land loses value it is ATCO, and not the ratepayers, that will absorb the

loss. However, the material put before the Court suggests that the Board takes into

account both gains and losses. In the following decisions the Board stated, repeated, and

repeated again its “general rule” that

the Board considers that any profit or loss (being the difference between thenet book value of the assets and the sale price of those assets) resulting fromthe disposal of utility assets should accrue to the customers of the utility andnot to the owner of the utility. [Emphasis added.]

(See Re TransAlta Utilities Corp., Alta. P.U.B., Decision No. E84116, October 12, 1984,

at p. 17; Re TransAlta Utilities Corp., Alta. P.U.B., Decision No. E84115, October 12,

1984, at p. 12; Re Canadian Western Natural Gas Co., Alta. P.U.B., Decision No.

E84113, October 12, 1984, at p. 23.)

146 In Re Alberta Government Telephones, Alta. P.U.B., Decision No. E84081,

June 29, 1984, the Board reviewed a number of regulatory approaches (including Re

Boston Gas Co., previously mentioned) with respect to gains on sale and concluded with

respect to its own practice, at p. 12:

The Board is aware that it has not applied any consistent formula or rulewhich would automatically determine the accounting procedure to befollowed in the treatment of gains or losses on the disposition of utilityassets. The reason for this is that the Board’s determination of what is fairand reasonable rests on the merits or facts of each case.

147 ATCO’s contention that it alone is burdened with the risk on land that

declines in value overlooks the fact that in a falling market the utility continues to be

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entitled to a rate of return on its original investment, even if the market value at the time

is substantially less than its original investment. As pointed out in SoCalGas:

If the land actually does depreciate in value below its original cost, then oneview could be that the steady rate of return [the ratepayers] have paid for theland over time has actually overcompensated investors. Thus, there issymmetry of risk and reward associated with rate base land just as there iswith regard to depreciable rate base property. [p. 107]

II. Conclusion

148 In summary, s. 15(3) of the AEUBA authorized the Board in dealing with

ATCO’s application to approve the sale of the subject land and buildings to “impose any

additional conditions that the Board considers necessary in the public interest”. In the

exercise of that authority, and having regard to the Board’s “general supervision over all

gas utilities, and the owners of them” (GUA, s. 22(1)), the Board made an allocation of

the net gain for the public policy reasons which it articulated in its decision. Perhaps not

every regulator and not every jurisdiction would exercise the power in the same way, but

the allocation of the gain on an asset ATCO sought to withdraw from the rate base was

a decision the Board was mandated to make. It is not for the Court to substitute its own

view of what is “necessary in the public interest”.

III. Disposition

149 I would allow the appeal, set aside the decision of the Alberta Court of

Appeal, and restore the decision of the Board, with costs to the City of Calgary both in

this Court and in the court below. ATCO’s cross-appeal should be dismissed with costs.

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APPENDIX

Alberta Energy and Utilities Board Act, R.S.A. 2000, c. A-17

Jurisdiction

13 All matters that may be dealt with by the ERCB or the PUB under anyenactment or as otherwise provided by law shall be dealt with by the Boardand are within the exclusive jurisdiction of the Board.

Powers of the Board

15(1) For the purposes of carrying out its functions, the Board has all thepowers, rights and privileges of the ERCB and the PUB that are granted orprovided for by any enactment or by law.

(2) In any case where the ERCB, the PUB or the Board may act in responseto an application, complaint, direction, referral or request, the Board may acton its own initiative or motion.

(3) Without restricting subsection (1), the Board may do all or any of thefollowing:

(a) make any order that the ERCB or the PUB may make under anyenactment;

(b) with the approval of the Lieutenant Governor in Council, makeany order that the ERCB may, with the approval of the LieutenantGovernor in Council, make under any enactment;

(c) with the approval of the Lieutenant Governor in Council, makeany order that the PUB may, with the approval of the LieutenantGovernor in Council, make under any enactment;

(d) with respect to an order made by the Board, the ERCB or thePUB in respect of matters referred to in clauses (a) to (c), makeany further order and impose any additional conditions that theBoard considers necessary in the public interest;

(e) make an order granting the whole or part only of the reliefapplied for;

(f) where it appears to the Board to be just and proper, grant partial,further or other relief in addition to, or in substitution for, thatapplied for as fully and in all respects as if the application ormatter had been for that partial, further or other relief.

Appeals

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26(1) Subject to subsection (2), an appeal lies from the Board to the Courtof Appeal on a question of jurisdiction or on a question of law.

(2) Leave to appeal may be obtained from a judge of the Court of Appealonly on an application made

(a) within 30 days from the day that the order, decision or directionsought to be appealed from was made, or

(b) within a further period of time as granted by the judge where thejudge is of the opinion that the circumstances warrant thegranting of that further period of time.

. . .

Exclusion of prerogative writs

27 Subject to section 26, every action, order, ruling or decision of theBoard or the person exercising the powers or performing the duties of theBoard is final and shall not be questioned, reviewed or restrained by anyproceeding in the nature of an application for judicial review or otherwisein any court.

Gas Utilities Act, R.S.A. 2000, c. G-5

Supervision

22(1) The Board shall exercise a general supervision over all gas utilities,and the owners of them, and may make any orders regarding equipment,appliances, extensions of works or systems, reporting and other matters, thatare necessary for the convenience of the public or for the proper carrying outof any contract, charter or franchise involving the use of public property orrights.

(2) The Board shall conduct all inquiries necessary for the obtaining ofcomplete information as to the manner in which owners of gas utilitiescomply with the law, or as to any other matter or thing within thejurisdiction of the Board under this Act.

Investigation of gas utility

24(1) The Board, on its own initiative or on the application of a personhaving an interest, may investigate any matter concerning a gas utility.

. . .

Designated gas utilities

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26(1) The Lieutenant Governor in Council may by regulation designatethose owners of gas utilities to which this section and section 27 apply.

(2) No owner of a gas utility designated under subsection (1) shall

(a) issue any

(i) of its shares or stock, or

(ii) bonds or other evidences of indebtedness, payable in morethan one year from the date of them,

unless it has first satisfied the Board that the proposed issue is tobe made in accordance with law and has obtained the approval ofthe Board for the purposes of the issue and an order of the Boardauthorizing the issue,

(b) capitalize

(i) its right to exist as a corporation,

(ii) a right, franchise or privilege in excess of the amountactually paid to the Government or a municipality as theconsideration for it, exclusive of any tax or annual charge, or

(iii) a contract for consolidation, amalgamation or merger,

(c) without the approval of the Board, capitalize any lease, or

(d) without the approval of the Board,

(i) sell, lease, mortgage or otherwise dispose of or encumber itsproperty, franchises, privileges or rights, or any part of it orthem, or

(ii) merge or consolidate its property, franchises, privileges orrights, or any part of it or them,

and a sale, lease, mortgage, disposition, encumbrance, merger orconsolidation made in contravention of this clause is void, butnothing in this clause shall be construed to prevent in any way thesale, lease, mortgage, disposition, encumbrance, merger orconsolidation of any of the property of an owner of a gas utilitydesignated under subsection (1) in the ordinary course of theowner’s business.

. . .

Prohibited share transactions

27(1) Unless authorized to do so by an order of the Board, the owner of agas utility designated under section 26(1) shall not sell or make or permit to

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be made on its books any transfer of any share or shares of its capital stockto a corporation, however incorporated, if the sale or transfer, by itself or inconnection with previous sales or transfers, would result in the vesting inthat corporation of more than 50% of the outstanding capital stock of theowner of the gas utility.

. . .

Powers of Board

36 The Board, on its own initiative or on the application of a person havingan interest, may by order in writing, which is to be made after giving noticeto and hearing the parties interested,

(a) fix just and reasonable individual rates, joint rates, tolls orcharges or schedules of them, as well as commutation and otherspecial rates, which shall be imposed, observed and followedafterwards by the owner of the gas utility,

(b) fix proper and adequate rates and methods of depreciation,amortization or depletion in respect of the property of any ownerof a gas utility, who shall make the owner’s depreciation,amortization or depletion accounts conform to the rates andmethods fixed by the Board,

(c) fix just and reasonable standards, classifications, regulations,practices, measurements or service, which shall be furnished,imposed, observed and followed thereafter by the owner of thegas utility,

(d) require an owner of a gas utility to establish, construct, maintainand operate, but in compliance with this and any other Actrelating to it, any reasonable extension of the owner’s existingfacilities when in the judgment of the Board the extension isreasonable and practical and will furnish sufficient business tojustify its construction and maintenance, and when the financialposition of the owner of the gas utility reasonably warrants theoriginal expenditure required in making and operating theextension, and

(e) require an owner of a gas utility to supply and deliver gas to thepersons, for the purposes, at the rates, prices and charges and onthe terms and conditions that the Board directs, fixes or imposes.

Rate base

37(1) In fixing just and reasonable rates, tolls or charges, or schedules ofthem, to be imposed, observed and followed afterwards by an owner of a gasutility, the Board shall determine a rate base for the property of the ownerof the gas utility used or required to be used to provide service to the publicwithin Alberta and on determining a rate base it shall fix a fair return on therate base.

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(2) In determining a rate base under this section, the Board shall give dueconsideration

(a) to the cost of the property when first devoted to public use and toprudent acquisition cost to the owner of the gas utility, lessdepreciation, amortization or depletion in respect of each, and

(b) to necessary working capital.

(3) In fixing the fair return that an owner of a gas utility is entitled to earnon the rate base, the Board shall give due consideration to all facts that in itsopinion are relevant.

Excess revenues or losses

40 In fixing just and reasonable rates, tolls or charges, or schedules ofthem, to be imposed, observed and followed afterwards by an owner of a gasutility,

(a) the Board may consider all revenues and costs of the owner thatare in the Board’s opinion applicable to a period consisting of

(i) the whole of the fiscal year of the owner in which aproceeding is initiated for the fixing of rates, tolls or charges,or schedules of them,

(ii) a subsequent fiscal year of the owner, or

(iii) 2 or more of the fiscal years of the owner referred to insubclauses (i) and (ii) if they are consecutive,

and need not consider the allocation of those revenues and coststo any part of that period,

(b) the Board may give effect to that part of any excess revenuereceived or any revenue deficiency incurred by the owner that isin the Board’s opinion applicable to the whole of the fiscal yearof the owner in which a proceeding is initiated for the fixing ofrates, tolls or charges, or schedules of them, that the Boarddetermines is just and reasonable,

(c) the Board may give effect to that part of any excess revenuereceived or any revenue deficiency incurred by the owner afterthe date on which a proceeding is initiated for the fixing of rates,tolls or charges, or schedules of them, that the Board determineshas been due to undue delay in the hearing and determining of thematter, and

(d) the Board shall by order approve

(i) the method by which, and

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(ii) the period, including any subsequent fiscal period, duringwhich,

any excess revenue received or any revenue deficiency incurred, asdetermined pursuant to clause (b) or (c), is to be used or dealt with.

General powers of Board

59 For the purposes of this Act, the Board has the same powers in respectof the plant, premises, equipment, service and organization for theproduction, distribution and sale of gas in Alberta, and in respect of thebusiness of an owner of a gas utility and in respect of an owner of a gasutility, that are by the Public Utilities Board Act conferred on the Board inthe case of a public utility under that Act.

Public Utilities Board Act, R.S.A. 2000, c. P-45

Jurisdiction and powers

36(1) The Board has all the necessary jurisdiction and power

(a) to deal with public utilities and the owners of them as providedin this Act;

(b) to deal with public utilities and related matters as they concernsuburban areas adjacent to a city, as provided in this Act.

(2) In addition to the jurisdiction and powers mentioned in subsection (1),the Board has all necessary jurisdiction and powers to perform any dutiesthat are assigned to it by statute or pursuant to statutory authority.

(3) The Board has, and is deemed at all times to have had, jurisdiction to fixand settle, on application, the price and terms of purchase by a council of amunicipality pursuant to section 47 of the Municipal Government Act

(a) before the exercise by the council under that provision of its rightto purchase and without binding the council to purchase, or

(b) when an application is made under that provision for the Board’sconsent to the purchase, before hearing or determining theapplication for its consent.

General power

37 In matters within its jurisdiction the Board may order and require anyperson or local authority to do forthwith or within or at a specified time andin any manner prescribed by the Board, so far as it is not inconsistent withthis Act or any other Act conferring jurisdiction, any act, matter or thing that

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the person or local authority is or may be required to do under this Act orunder any other general or special Act, and may forbid the doing orcontinuing of any act, matter or thing that is in contravention of any suchAct or of any regulation, rule, order or direction of the Board.

Investigation of utilities and rates

80 When it is made to appear to the Board, on the application of an ownerof a public utility or of a municipality or person having an interest, presentor contingent, in the matter in respect of which the application is made, thatthere is reason to believe that the tolls demanded by an owner of a publicutility exceed what is just and reasonable, having regard to the nature andquality of the service rendered or of the commodity supplied, the Board

(a) may proceed to hold any investigation that it thinks fit into allmatters relating to the nature and quality of the service or thecommodity in question, or to the performance of the service andthe tolls or charges demanded for it,

(b) may make any order respecting the improvement of the service orcommodity and as to the tolls or charges demanded, that seemsto it to be just and reasonable, and

(c) may disallow or change, as it thinks reasonable, any such tolls orcharges that, in its opinion, are excessive, unjust or unreasonableor unjustly discriminate between different persons or differentmunicipalities, but subject however to any provisions of anycontract existing between the owner of the public utility and amunicipality at the time the application is made that the Boardconsiders fair and reasonable.

Supervision by Board

85(1) The Board shall exercise a general supervision over all publicutilities, and the owners of them, and may make any orders regardingextension of works or systems, reporting and other matters, that arenecessary for the convenience of the public or for the proper carrying out ofany contract, charter or franchise involving the use of public property orrights.

. . .

Investigation of public utility

87(1) The Board may, on its own initiative, or on the application of aperson having an interest, investigate any matter concerning a public utility.

(2) When in the opinion of the Board it is necessary to investigate a publicutility or the affairs of its owner, the Board shall be given access to and mayuse any books, documents or records with respect to the public utility andin the possession of any owner of the public utility or municipality or underthe control of a board, commission or department of the Government.

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(3) A person who directly or indirectly controls the business of an ownerof a public utility within Alberta and any company controlled by that personshall give the Board or its agent access to any of the books, documents andrecords that relate to the business of the owner or shall furnish anyinformation in respect of it required by the Board.

Fixing of rates

89 The Board, either on its own initiative or on the application of a personhaving an interest, may by order in writing, which is to be made after givingnotice to and hearing the parties interested,

(a) fix just and reasonable individual rates, joint rates, tolls orcharges, or schedules of them, as well as commutation, mileageor kilometre rate and other special rates, which shall be imposed,observed and followed subsequently by the owner of the publicutility;

(b) fix proper and adequate rates and methods of depreciation,amortization or depletion in respect of the property of any ownerof a public utility, who shall make the owner’s depreciation,amortization or depletion accounts conform to the rates andmethods fixed by the Board;

(c) fix just and reasonable standards, classifications, regulations,practices, measurements or service, which shall be furnished,imposed, observed and followed subsequently by the owner ofthe public utility;

(d) repealed;

(e) require an owner of a public utility to establish, construct,maintain and operate, but in compliance with other provisions ofthis or any other Act relating to it, any reasonable extension ofthe owner’s existing facilities when in the judgment of the Boardthe extension is reasonable and practical and will furnishsufficient business to justify its construction and maintenance,and when the financial position of the owner of the public utilityreasonably warrants the original expenditure required in makingand operating the extension.

Determining rate base

90(1) In fixing just and reasonable rates, tolls or charges, or schedules ofthem, to be imposed, observed and followed subsequently by an owner ofa public utility, the Board shall determine a rate base for the property of theowner of a public utility used or required to be used to provide service to thepublic within Alberta and on determining a rate base it shall fix a fair returnon the rate base.

(2) In determining a rate base under this section, the Board shall give dueconsideration

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(a) to the cost of the property when first devoted to public use and toprudent acquisition cost to the owner of the public utility, lessdepreciation, amortization or depletion in respect of each, and

(b) to necessary working capital.

(3) In fixing the fair return that an owner of a public utility is entitled toearn on the rate base, the Board shall give due consideration to all thosefacts that, in the Board’s opinion, are relevant.

Revenue and costs considered

91(1) In fixing just and reasonable rates, tolls or charges, or schedules ofthem, to be imposed, observed and followed by an owner of a public utility,

(a) the Board may consider all revenues and costs of the owner thatare in the Board’s opinion applicable to a period consisting of

(i) the whole of the fiscal year of the owner in which aproceeding is initiated for the fixing of rates, tolls or charges,or schedules of them,

(ii) a subsequent fiscal year of the owner, or

(iii) 2 or more of the fiscal years of the owner referred to insubclauses (i) and (ii) if they are consecutive,

and need not consider the allocation of those revenues and coststo any part of such a period,

(b) the Board shall consider the effect of the Small Power Researchand Development Act on the revenues and costs of the owner withrespect to the generation, transmission and distribution of electricenergy,

(c) the Board may give effect to that part of any excess revenuereceived or any revenue deficiency incurred by the owner that isin the Board’s opinion applicable to the whole of the fiscal yearof the owner in which a proceeding is initiated for the fixing ofrates, tolls or charges, or schedules of them, as the Boarddetermines is just and reasonable,

(d) the Board may give effect to such part of any excess revenuereceived or any revenue deficiency incurred by the owner afterthe date on which a proceeding is initiated for the fixing of rates,tolls or charges, or schedules of them, as the Board determineshas been due to undue delay in the hearing and determining of thematter, and

(e) the Board shall by order approve the method by which, and theperiod (including any subsequent fiscal period) during which, anyexcess revenue received or any revenue deficiency incurred, as

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determined pursuant to clause (c) or (d), is to be used or dealtwith.

Designated public utilities

101(1) The Lieutenant Governor in Council may by regulation designatethose owners of public utilities to which this section and section 102 apply.

(2) No owner of a public utility designated under subsection (1) shall

(a) issue any

(i) of its shares or stock, or

(ii) bonds or other evidences of indebtedness, payable in morethan one year from the date of them,

unless it has first satisfied the Board that the proposed issue is tobe made in accordance with law and has obtained the approval ofthe Board for the purposes of the issue and an order of the Boardauthorizing the issue,

(b) capitalize

(i) its right to exist as a corporation,

(ii) a right, franchise or privilege in excess of the amountactually paid to the Government or a municipality as theconsideration for it, exclusive of any tax or annual charge, or

(iii) a contract for consolidation, amalgamation or merger,

(c) without the approval of the Board, capitalize any lease, or

(d) without the approval of the Board,

(i) sell, lease, mortgage or otherwise dispose of or encumber itsproperty, franchises, privileges or rights, or any part of them,or

(ii) merge or consolidate its property, franchises, privileges orrights, or any part of them,

and a sale, lease, mortgage, disposition, encumbrance, merger orconsolidation made in contravention of this clause is void, butnothing in this clause shall be construed to prevent in any way thesale, lease, mortgage, disposition, encumbrance, merger orconsolidation of any of the property of an owner of a publicutility designated under subsection (1) in the ordinary course ofthe owner’s business.

. . .

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Prohibited share transaction

102(1) Unless authorized to do so by an order of the Board, the owner ofa public utility designated under section 101(1) shall not sell or make orpermit to be made on its books a transfer of any share of its capital stock toa corporation, however incorporated, if the sale or transfer, in itself or inconnection with previous sales or transfers, would result in the vesting inthat corporation of more than 50% of the outstanding capital stock of theowner of the public utility.

. . .

Interpretation Act, R.S.A. 2000, c. I-8

Enactments remedial

10 An enactment shall be construed as being remedial, and shall be giventhe fair, large and liberal construction and interpretation that best ensures theattainment of its objects.

Appeal dismissed with costs and cross-appeal allowed with costs,

MCLACHLIN C.J. and BINNIE and FISH JJ. dissenting.

Solicitors for the appellant/respondent on cross-appeal: McLennan Ross,

Calgary.

Solicitors for the respondent/appellant on cross-appeal: Bennett Jones,

Calgary.

Solicitor for the intervener the Alberta Energy and Utilities

Board: J. Richard McKee, Calgary.

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Solicitor for the intervener the Ontario Energy Board: Ontario Energy

Board, Toronto.

Solicitors for the intervener Enbridge Gas Distribution Inc.: Fraser Milner

Casgrain, Toronto.

Solicitors for the intervener Union Gas Limited: Torys, Toronto. 2006

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Page 1

1996 CarswellBC 352, 36 Admin. L.R. (2d) 249, 20 B.C.L.R. (3d) 106, 71 B.C.A.C. 271, 117 W.A.C. 271, [1996] B.C.W.L.D. 847, 61 A.C.W.S. (3d) 390

© 2011 Thomson Reuters. No Claim to Orig. Govt. Works

1996 CarswellBC 352, 36 Admin. L.R. (2d) 249, 20 B.C.L.R. (3d) 106, 71 B.C.A.C. 271, 117 W.A.C. 271, [1996] B.C.W.L.D. 847, 61 A.C.W.S. (3d) 390

British Columbia Hydro & Power Authority v. British Columbia (Utilities Commission)

BRITISH COLUMBIA HYDRO AND POWER AUTHORITY v. BRITISH COLUMBIA UTILITIES COMMIS-SION, BRITISH COLUMBIA ENERGY COALITION, CONSUMER'S ASSOCIATION OF CANADA (B.C. BRANCH) ET AL., COUNCIL OF FOREST INDUSTRIES, WEST KOOTENAY POWER LTD., B.C. GAS

UTILITY LTD., ISCA MANAGEMENT LTD. and RICK BERRY

British Columbia Court of Appeal

Goldie, Prowse and Newbury JJ.A.

Heard: February 15, 1996Judgment: February 23, 1996

Docket: Doc. Vancouver CA019726

© Thomson Reuters Canada Limited or its Licensors (excluding individual court documents). All rights reserved.

Counsel: Chris Sanderson, J. Christian, and A.M. Dobson-Mack, for appellant.

Mark M. Moseley, for respondent British Columbia Utilities Commission.

Carol Reardon, for respondent/intervenor British Columbia Energy Coalition.

Michael P. Doherty, for respondent/intervenor Consumer's Association of Canada (B.C. Branch) et al.

D.W. Bursey, for respondent/intervenor Council of Forest Industries et al.

Subject: Public; Civil Practice and Procedure

Public Utilities --- Regulatory boards — Practice and procedure — Statutory appeals — Grounds for appeal — Lack of jurisdiction.

Practice --- Practice on appeal — Staying of proceedings pending appeal.

Public utilities — Regulatory boards — Practice and procedure — Judicial review — Jurisdiction of board — Utili-ties commission purporting to order that appellant utility comply with resource planning guidelines issued by com-mission — Court finding that directions in order being beyond statutory powers of commission and accordingly un-enforceable.

Page 2

1996 CarswellBC 352, 36 Admin. L.R. (2d) 249, 20 B.C.L.R. (3d) 106, 71 B.C.A.C. 271, 117 W.A.C. 271, [1996] B.C.W.L.D. 847, 61 A.C.W.S. (3d) 390

© 2011 Thomson Reuters. No Claim to Orig. Govt. Works

The appellant was a publicly owned utility generating, transmitting and distributing electrical energy. Its rates were subject to approval by the respondent commission under the provisions of the Utilities Commission Act. The com-mission issued a document entitled "Integrated Resource Planning Guidelines." The document was intended to pro-vide guidance on the commission's expectations of the planning processes developed by utilities. The appellant ap-plied for a rate increase. In its order denying the application, the commission ordered that the appellant comply with several directions relating to the integrated resource planning guidelines. The appellant appealed from that part of the order, objecting to the manner in which the commission purported to give the guidelines the force of a commis-sion order.

Held:

Appeal allowed.

No section of the Act expressly enabled the commission to impose by order its chosen form of controlling planning at the stage selected by it. Taken as a whole, the Act, viewed in the purposive sense required, did not reflect any intention on the part of the legislature to confer upon the commission a jurisdiction to determine, punishable on de-fault by sanctions, the manner in which the directors of a public utility managed its affairs. Where a regulator issues a statement or guideline that is non-binding and intended to inform and guide those subject to regulation, the state-ment is within the authority of the regulator. However, where the statement or guideline imposes mandatory re-quirements enforceable by sanction, the statement requires statutory authority. A regulator cannot issue de facto laws disguised as guidelines. The issue of non-mandatory guidelines was not a question before the court. The com-mission explicitly purported to enforce the application of its directions with the threat of sanctions. Thus, the appel-lant was entitled to a declaration that the directions in the order relating to the integrated resource planning guide-lines were beyond the statutory powers of the commission and were accordingly unenforceable.

Cases considered:

Ainsley Financial Corp. v. Ontario (Securities Commission) (1994), 18 O.S.C.B. 43, 6 C.C.L.S. 241, 21 O.R. (3d) 104, 28 Admin. L.R. (2d) 1, 121 D.L.R. (4th) 79, 77 O.A.C. 155 (C.A.) — applied

British Columbia Electric Railway v. British Columbia Public Utilities Commission, [1960] S.C.R. 837, 33 W.W.R. 97, 82 C.R.T.C. 32, 25 D.L.R. (2d) 689 — considered

Memorial Gardens Assn. (Canada) Ltd. v. Colwood Cemetery Co., [1958] S.C.R. 353, 13 D.L.R. (2d) 97, 76 C.R.T.C. 319 — considered

Pezim v. British Columbia (Superintendent of Brokers), [1994] 2 S.C.R. 557, 4 C.C.L.S. 117, [1994] 7 W.W.R. 1, 92 B.C.L.R. (2d) 145, 14 B.L.R. (2d) 217, 22 Admin. L.R. (2d) 1, 114 D.L.R. (4th) 385, (sub nom. Pezim v. British Columbia (Securities Commission)) 168 N.R. 321, 46 B.C.A.C. 1, 75 W.A.C. 1 — considered

Syndicat national des employés de la commission scolaire régionale de l'Outaouais v. U.E.S., Local 298, (subnom. U.E.S., local 298 v. Bibeault) [1988] 2 S.C.R. 1048, 35 Admin. L.R. 153, 95 N.R. 161, 89 C.L.L.C. 14,045, 24 Q.A.C. 244 — applied

Statutes considered:

Hydro and Power Authority Act, R.S.B.C. 1979, c. 188

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s. 5considered

Utilities Commission Act, S.B.C. 1980, c. 60

Pt. 2referred to

Pt. 3referred to

Pt. 9considered

s. 3.1 [en. 1989, c. 45, s. 13]considered

s. 28considered

s. 29considered

s. 44considered

s. 49considered

s. 51considered

s. 57considered

s. 59considered

s. 62(1)referred to

ss. 64-66considered

s. 66referred to

s. 112considered

s. 121referred to

s. 141(4)considered

Appeal from order of respondent British Columbia Utilities Commission.

The judgment of the court was delivered by Goldie J.A.:

1 This is an appeal, by leave, from Order G-89-94 of the British Columbia Utilities Commission (the "Commis-sion") with reasons for the decision attached. I refer to these reasons as the "Decision" and to Order G-89-94 as the "Order".

2 After a public hearing the Commission released the Decision on 24 November 1994. Notice of an application

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for leave to appeal to this Court was filed by B.C. Hydro on 22 December 1994. Leave was granted 15 December 1995, the day the application was heard. The delay occurred when the Commission acceded to B.C. Hydro's applica-tion that it reconsider the Order and Decision. The reasons denying reconsideration were released on 17 October 1995. These proceedings accounted for much of the delay between the filing of the notice of application for leave to appeal and the granting of leave.

3 The issue, as stated by the appellant British Columbia Hydro and Power Authority ("B.C. Hydro"), is whether the Commission exceeded its jurisdiction in respect of certain directions in the Decision given the force of a Com-mission order. While it is common ground the standard of review in respect of jurisdiction is that the Commission must be correct in its interpretation of its constituent statute, the respondents contend the Commission acted within its jurisdiction and the appeal should be dismissed as no palpable and overriding error has been demonstrated that would permit this Court's intervention.

Background — General

4 B.C. Hydro is a publicly owned utility generating, transmitting and distributing electrical energy. With few exceptions its service area is province wide. Its rates are subject to approval by the Commission under the provisions of the Utilities Commission Act, S.B.C. 1980, c. 60, as amended (the "Utilities Act"). Under s. 3.1 of the Utilities Actthe Lieutenant Governor in Council may issue a direction to the Commission specifying the factors, criteria and guidelines the Commission is to observe in respect of B.C. Hydro. Such a direction, Special Direction No. 8, was in force at the time material to this appeal.

5 By virtue of the Hydro and Power Authority Act, R.S.B.C. 1979, c. 188, as amended (the "Authority Act"),B.C. Hydro is for all its purposes an agent of the Queen in Right of the Province; is deemed to have been granted an energy operation certificate for the purposes of the Utilities Act in respect of its works existing on 11 September 1980; and is not bound by any statute or statutory provision of the Province except what is made applicable to it by Order in Council. The Minister of Finance is its fiscal agent. The Utilities Act is among those ordered to be applica-ble to B.C. Hydro except sections dealing with one aspect of reserve funds; one enforcement provision and those requiring Commission approval of security issues and property disposition.

6 Section 5 of the Authority Act provides that the directors of B.C. Hydro, appointed by the Lieutenant Gover-nor in Council, shall manage its affairs. The powers of B.C. Hydro include the generation, manufacture, distribution and supply of power and the development of power sites and power plants. The exercise of these powers is subject to the approval of the Lieutenant Governor in Council. A further distinction between B.C. Hydro and investor-owned utilities is that B.C. Hydro's sole "shareholder" and not its directors determines when and in what amounts "dividends" will be paid.

7 Under s-s. 4 of s. 141 of the Utilities Act, which came into force 11 September 1980, the rates of B.C. Hydro then in effect became its lawful, enforceable and collectible rates.

8 Prior to 30 June 1995 Part 2 of the Utilities Act provided an approval process of generating and transmission facilities by the Lieutenant Governor in Council which could, at the latter's discretion, bypass the Commission. In this event the Commission might be called upon to approve rates reflecting the capital costs of large scale projects without the opportunity to pass upon the adequacy of the information justifying the construction of such projects as contemplated by the requirement under s. 51(1) of the Utilities Act requiring a certificate of public convenience and necessity prior to embarking upon construction. This provision is of some importance and I set it out here:

51. (1) Except as otherwise provided, no person shall, after this section comes into force, begin the construction or operation of a public utility plant or system, or an extension of either, without first obtaining from the com-mission a certificate that public convenience and necessity require or will require the construction or operation.

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9 This prospect has been removed by amendments, primarily to Part 2 of the Utilities Act, and with it any justi-fication for concern over multi million dollar additions to the property devoted to public service without prior regu-latory scrutiny.

Background — "Integrated Resource Plan Guidelines"

10 In February, 1993 the Commission issued a 12-page document, to which I will refer as the "Guidelines", entitled "Integrated Resource Planning ("IRP") Guidelines". The following is the Definition section of the Guide-lines:

II Definition

IRP is a utility planning process which requires consideration of all known resources for meeting the demand for a utility's product, including those which focus on traditional supply sources and those which focus on con-servation and the management of demand[FN1]. The process results in the selection of that mix of resources which yields the preferred[FN2] outcome of expected impacts and risks for society over the long run. The IRP process plays a role in defining and assessing costs, as these can be expected to include not just costs and bene-fits as they appear in the market but also other monetizable and non-monetizable social and environmental ef-fects. The IRP process is associated with efforts to augment traditional regulatory review of completed utility plans with cooperative mechanisms of consensus seeking in the preparation and evaluation of utility plans. The IRP process also provides a framework that helps to focus public hearings on utility rates and energy project applications.

11 In the Purpose section the Commission stated the Guidelines were:

... intended to provide general guidance regarding BCUC expectations of the process and methods utilities fol-low in developing an IRP. It is expected that the general rather than detailed nature of the proposed guidelines will allow utilities to formulate plans which reflect their specific circumstances.

12 The Commission's identification of the objectives of this process was stated in these words:

1. Identification of the objectives of the plan

Objectives include but are not limited to: adequate and reliable service; economic efficiency; preservation of the financial integrity of the utility; equal consideration of DSM and supply resources; minimization of risks; con-sideration of environmental impacts; consideration of other social principles of ratemaking3, coherency with government regulations and stated policies.

Footnote 3 provides in part:

... The general implication is that because of social and environmental objectives, the rates charged by utilities may be allowed to diverge from those that would result from a rate determination based exclusively on financial least cost. The social principles to be addressed may be identified by the utility intervenors or government.

13 In Part III of the Guidelines defining the relationship between regulated utilities and the Commission under the Integrated Resource Plan Process the following sentences occur:

IRP does not change the fundamental regulatory relationship between the utilities and the BCUC. Thus IRP

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guidelines issued by the BCUC do not mandate a specific outcome to the planning process nor do they mandate specific investment decisions. ... Under IRP, utility management continues to have full responsibility for mak-ing decisions and for accepting the consequences of those decisions. ... Consistency with IRP guidelines and the filed IRP plan will be an additional factor that the BCUC will consider in judging the prudency of investments and rate applications, although inconsistency may be warranted by changed circumstances or new evidence.

14 We are not called upon to determine whether the Guidelines, as defined above, are an appropriate exercise of the Commission's regulatory powers under the Utilities Act nor is there an appeal from any part of the Order dispos-ing of B.C. Hydro's application to vary its rates.

15 What is objected to is the manner in which the Commission has purported to give the Guidelines the force of a Commission order. It is convenient at this point to set out the substantive part of Order G-89-94:

NOW THEREFORE the Commission, for reasons stated in the Decision, orders as follows;

1. The applied for 2.8 percent increase in rates is denied and the interim increase authorized by Order No. G-18-94 effective April 1, 1994 is to be refunded, with interest calculated at the average prime rate of the principal bank with which B.C. Hydro conducts its business. B.C. Hydro is to provide the Commission with a detailed reconciliation schedule verifying the refund.

2. Rate design changes required by the Decision are to be implemented.

3. An Integrated Resource Plan and Action Plan are to be filed for approval by June 30, 1995.

4. The Commission will accept, subject to timely filing by B.C. Hydro, amended Electric Tariff Rate Schedules which conform to the terms of the Commission's Decision. B.C. Hydro will provide all custom-ers, by way of an information notice and media publication, with the Executive Summary of the Commis-sion's Decision.

4. (sic)B.C. Hydro will comply with all other directions contained in the Decision accompanying this Or-der.

(emphasis added)

16 I shall refer to the directions identified in the last paragraph as the "Directions". And it is paragraph 4 (sic) of the Order that is in issue here. Counsel for B.C. Hydro says there are 15 Directions related to the Guidelines covered by this paragraph.

17 The principal relief sought, as stated in B.C. Hydro's factum, includes a declaration "... that the IRP related aspects of Order G-89-94 and of the November Decision are void and of no effect".

18 In my view, the Direction best illustrating the issue raised by B.C. Hydro is that which requires it to establish what is called a collaborative committee (the "Committee") together with those Directions determining the part this Committee is to play in B.C. Hydro's performance of its statutory obligation under s. 44 of the Utilities Act to pro-vide service to the public.

Discussion

19 Mr. Moseley on behalf of the Commission asserted it was doing no more than obtaining information it was

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entitled to, in a format it could by law determine, all at a time it was authorized to stipulate.

20 There can be little doubt, from the nature of B.C. Hydro's business, the magnitude of financial resources re-quired and the variety of other resources directly or indirectly committed or affected that virtually every person in the Province will have an interest in the management of that business.

21 The Direction in question follows a finding that B.C. Hydro had not complied with the Guidelines "... which require an explicit decision-making process which includes public involvement." B.C. Hydro had in place a public consultation program but this was considered inadequate as being "after the fact" rather than participatory in the planning process. The membership of the Committee was determined by the Commission, apparently on the princi-ple that the planning process is enhanced by the participation of interest groups. This appears from the following observation in the Decision:

Determination of the appropriate trade-offs between resources requires that the values the public attaches to these costs and benefits must be determined and factored into the decision in an explicit and transparent way.

The Commission has made it clear that such values are best determined through the direct participation of rep-resentative interest groups.

Exclusive reliance on the B.C. Hydro staff, managers and Board of Directors for resource selection is also unac-ceptable for another reason. A closed, in-house process has the appearance of, and real potential for, bias in de-cision making that favors the interests of the bureaucracy within the Utility.

The Committee as constituted following the Order and Decision consisted of two representatives of B.C. Hydro and 11 representing a variety of interests. Each of the 11 spoke for his or her group. Some were regional, others repre-sented classes of customers. One or two represented people who wished to do business with B.C. Hydro.

22 Seven Directions state in detail what B.C. Hydro is to provide the Committee. One includes the following:

Finally, the Commission directs B.C. Hydro to institute with the IRP consultative committee a multi-attribute trade-off analysis for the purposes of portfolio development and selection.

This process is defined in the Commission's glossary of terms:

Multi-Attribute Analysis

A method which allows for comparison of options in terms of all attributes which are of relevance to the deci-sion maker(s). In IRP, common attributes are financial cost, environmental impact, social impact and risk.

23 This requires B.C. Hydro to appraise future projects which it may never implement because of, for instance, financial constraints imposed by the Minister of Finance or by virtue of a special direction under s. 3.1 of the Utili-ties Act.

24 There is evidence supporting the following assertion in the appellant's factum:

The bulk of the IRP Directives can be characterized as requiring BCH to put BCH's resource planning initia-tives and analyses to the Consultative Committee and be guided by the views and information provided by the members of the Consultative Committee in undertaking its resource planning responsibilities.

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25 It cannot be seriously questioned that the Commission requires compliance with its Guidelines: at p. 66 of the reasons the Commission concludes a direction denying recovery of a portion of B.C. Hydro's Resource Planning Unit expenditures with these words:

Should the Utility continue to fail to implement the Commission's directions respecting IRP, the Commission will consider the circumstances and may invoke its powers under Part 9 of the Act.

26 Part 9 of the Utilities Act, to which I will later refer, includes a list of offences under the Utilities Act.

27 B.C. Hydro filed with the Commission on 8 November 1996 what it called its integrated electricity plan which it asserted complied with the Directions in the Decision. The Commission has ordered a public hearing into the integrated electricity plan in February 1996.

28 I restate the question before us. It is whether there is statutory authority for the Commission's imposition of the Guidelines to the extent required by the relevant Directions in the Decision on what is essentially an internal process for which the directors of B.C. Hydro have the ultimate responsibility, both in respect of the process and for the selection of the product of the process.

29 Mr. Sanderson's first point on behalf of B.C. Hydro is that nowhere in the Utilities Act is reference made to planning. In answer, Mr. Mosely referred us to s. 51(3) which requires a public utility to file annually with the Commission a statement in a prescribed form "... of the extensions to its facilities that it plans to construct". This describes a result at the conclusion of the relevant planning process. In the context of s. 51(2) it refers to the con-struction of facilities for which separate certificates of public convenience and necessity may not be required.

30 In my view, s. 51(3) has little relevance to the case at bar. It appears B.C. Hydro routinely files the statement referred to. The amounts in question may be in the aggregate substantial but one would expect many of the expendi-tures for individual components would not be, as they, would relate to the routine reinforcement of transformation and distribution facilities required to meet load growth or to maintain the reliability and adequacy of service.

31 Section 28 of the Utilities Act is also relied upon by the respondents. In full, it provides:

General supervision of public utilities

28. (1) The commission has general supervision of all public utilities and may make orders about equipment, appliances, safety devices, extension of works or systems, filing of rate schedules, reporting and other matters it considers necessary or advisable for the safety, convenience or service of the public or for the proper carrying out of this Act or of a contract, charter or franchise involving use of public property or rights.

(2) Subject to this Act, the commission may make regulations requiring a public utility to conduct its operations in a way that does not unnecessarily interfere with, or cause unnecessary damage or inconvenience to, the pub-lic.

32 Two observations can be made of this section: the first is that the class of matters referred to in s-s. (1) re-lates to the existing service provided the public as distinct from future service. The second is that s-s. (2) also refers to present service, that is to say, the conduct of operations in relation to the public. Neither of these subsections re-fers to the utility's plans for the future.

33 Section 29 of the Utilities Act has some relevance to the contention that the IRP process comprises in one bundle the exercise of individual powers granted the Commission. It directs the Commission to make examinations

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and conduct inquiries necessary to keep itself informed about, amongst other things, the conduct of public utility business. It does not authorize the Commission to direct how that business is conducted.

34 The Commission is supplied with B.C. Hydro's load forecasts as is apparent from its comments in the Deci-sion. These dictate the response a utility must make to meet its statutory obligation to provide service as well as to maintain compliance with the terms of existing certificates of public convenience and necessity. It is within this part of the process that the Commission has decided, in its words, to make the IRP the "... driving force behind the estab-lishment of a utility action plan approved by senior management."

35 It appears reasonable to assume the purpose of the Guidelines is to look beyond a simplistic view of utility planning as one limited to selecting the resources needed to meet anticipated demand and in doing so, to reject an equally simplistic view of regulation as ensuring that service is provided at the least cost to the consumer. It has been evident for some years now that environmental considerations are important in the formulation of the opinion represented by the phrase "public convenience and necessity". To the same effect, conservation and management of energy use is now recognized in what is known as demand side management. The wisdom of all this does not appear to be an issue.

36 The Commission's order directs when and how these factors are to be taken into account in the sequence of B.C. Hydro's planning processes.

37 The Commission in its factum asserts the IRP process is designed to accomplish two objectives:

1. It provides information to the Commission as to the resource selection choice being made by a utility; and

2. Following a review of the IRP plan for the Commission "... it provides guidance to utility management in the form of an advance indication as to the approach the Commission is likely to apply when it subsequently assesses the pru-dency of the expenditures made by the utility."

38 It will be noted the first objective refers to choices being made while the second refers to expenditures al-ready made.

39 This dichotomy between present planning and past expenditures is said by the Commission to require regula-tory control at the planning stage to avoid the dilemma of disallowing substantial incurred expenditures at the rate review stage. The examples given by the Commission in its reconsideration reasons were a nuclear plant and a large hydro electric dam.

40 Section 51 of the Utilities Act avoids this Hobson's choice. It does so by requiring a certificate of public con-venience and necessity before the utility begins construction. It is not suggested the Commission has been demon-strably ineffectual in discharging its responsibilities at the certification stage.

41 Other provisions in the Act relied upon by the Commission are as follows:

1. Section 49 which requires a utility to furnish information to the Commission and answer its questions. This does not require that the utility create information for the purpose of a consultative committee nor to respond to the re-quests of a consultative committee — both of which have been directed by the Commission.

2. Sections 64-66 which deal with the Commission's jurisdiction over rates. To the extent these are relevant I have dealt with them in my comment on s. 51 of the Utilities Act.

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42 I am of the view no section of the Utilities Act expressly enables the Commission to impose by order its cho-sen form of controlling planning at the stage selected by it.

43 In this I rely upon the literal meaning of each of the sections in the Act which have appeared to me to have any relevant significance.

44 These are, however, to be construed in relation to the Utilities Act as a whole. I refer to what Mr. Justice Beetz said in Syndicat national des employés de la commission scolaire régionale de l'Outaouais v. U.E.S., Local 298, (sub nom. U.E.S., local 298 v. Bibeault) [1988] 2 S.C.R. 1048 at 1088, as the initial stage in a pragmatic or functional analysis:

At this stage, the Court examines not only the wording of the enactment conferring jurisdiction on the adminis-trative tribunal, but the purpose of the statute creating the tribunal, the reason for its existence, the area of exper-tise of its members and the nature of the problem before the tribunal.

45 The premise of such an analysis is that it focuses on jurisdiction: did the legislature intend the question in issue to be answered by the courts or by the tribunal? It is a matter of statutory interpretation with the emphasis on purpose.

46 In this light the Utilities Act is a current example of the means adopted in North America, firstly in the United States, to achieve a balance in the public interest between monopoly, where monopoly is accepted as neces-sary, and protection to the consumer provided by competition. The grant of monopoly through certification of public convenience and necessity was accompanied by the correlative burden on the monopoly of supplying service at ap-proved rates to all within the area from which competition was excluded.

47 It is self-evident this process cannot be undertaken on a day to day basis by legislature or government. Hence, the creation of public utilities commissions. In the United States a constitutionally acceptable formula was evolved to protect the grantee of a certificate of public convenience and necessity from rates so low they constituted piece-meal confiscation of property without due compensation. The form this took was adopted in Canada. A brief historical sketch, relevant to this province, is found in the concurring judgment of Mr. Justice Locke in British Co-lumbia Electric Railway v. British Columbia Public Utilities Commission, [1960] S.C.R. 837 at 842-845. The Utili-ties Act contains many expressions linking it with its legislative antecedents.

48 The certification process is at the heart of the regulatory function delegated to the Commission by the legisla-ture. In Memorial Gardens Assn. (Canada) Ltd. v. Colwood Cemetery Co., [1958] S.C.R. 353, Mr. Justice Abbott, after referring to the American origin of the phrase, said at 357:

As this Court held in the Union Gas case, supra, the question whether public convenience and necessity re-quires a certain action is not one of fact. It is predominantly the formulation of an opinion. Facts must, of course, be established to justify a decision by the Commission but that decision is one which cannot be made without a substantial exercise of administrative discretion. In delegating this administrative discretion to the Commission the Legislature has delegated to that body the responsibility of deciding, in the public interest, the need and desirability of additional cemetery facilities, and in reaching that decision the degree of need and of desirability is left to the discretion of the Commission.

49 The other function the legislature has entrusted to the regulatory tribunal is the supervision of the utility's use of property dedicated to service as a result of the certification process. Unless so certified, or exempted from certifi-cation by the Commission, such property is not part of the appraised value of the utility company under s. 62(1) which is the basis for fixing a rate under s. 66. In respect of such property the supervisory powers of the Commis-sion, principally found in Part 3 of the Utilities Act, enable it to oversee the statutory obligation in s. 44 to furnish

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service imposed upon every public utility, namely:

44. Every public utility shall maintain its property and equipment in a condition to enable it to furnish, and it shall furnish, a service to the public that the commission considers is in all respects adequate, safe, efficient, just and reasonable.

50 It is not without some significance that the Commission found in the Decision the following:

From the evidence, the Commission recognizes that B.C. Hydro is generally maintaining a safe, secure and highly reliable generation, transmission and distribution service. Given this high level of reliability, the Com-mission has focused on cost control as an issue at this time.

51 The Utilities Act runs to over 140 sections. The administration of the jurisdiction conferred upon the Com-mission is amply delineated by express terms. There is no need to imply terms for this purpose.

52 I have already described the reason for the existence of the tribunal. The expertise or skills of its members vary. Experience has demonstrated skills associated with accounting, economics, finance and engineering have been frequently utilized. Unlike labour relations tribunals where past experience in the field of labour relations is a virtual prerequisite, past experience in the regulatory field is not necessary. A similar observation may be made with respect to securities commissions. Both labour relations tribunals and securities commissions are expressly conferred with policy making powers. None such are conferred on the Commission.

53 In considering the nature of the problem before the tribunal I will first deal with the Utilities Act as a law of general application. I will then consider whether the provisions of the Utilities Act which relate only to B.C. Hydro affect my conclusions.

54 I earlier referred to the characterization of the issue. Counsel for the Commission contended it merely related to the enforcement of the information gathering power conferred on the Commission.

55 I am unable to agree with that characterization as in my opinion the IRP process is specific to the planning phase of the utility's response to its statutory obligations and its enforcement by order is an exercise of management as it relates neither to the certification process as such nor to the supervision of the utility's use of its property de-voted to the provision of service.

56 It is only under s. 112 of the Utilities Act that the Commission is authorized to assume the management of a public utility. Otherwise the management of a public utility remains the responsibility of those who by statute or the incorporating instruments are charged with that responsibility.

57 One of the primary responsibilities and functions of the directors of a corporation is the formulation of plans for its future. In the case of a public utility these plans must of necessity extend many years into the future and be constantly revised to meet changing conditions. In the case at bar the effect of the Commission's directions is to place a group, whose interests are disparate, in a superior position in the sequence of planning and to require the directors to justify a deviation from the product of the IRP process in the exercise of their responsibilities.

58 Taken as a whole the Utilities Act, viewed in the purposive sense required, does not reflect any intention on the part of the legislature to confer upon the Commission a jurisdiction so to determine, punishable on default by sanctions, the manner in which the directors of a public utility manage its affairs.

59 When the Utilities Act is examined in light of the provisions applicable to B.C. Hydro alone, this conclusion

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is reinforced. I have mentioned s. 3.1. This authorizes the Lieutenant Governor in Council to issue a direction to the Commission specifying "factors, criteria and guidelines" to be used or not used by the Commission in regulating and fixing rates for B.C. Hydro. There is no comparable mandatory power conferred on the Commission to issue such directions to B.C. Hydro. From my examination of the Utilities Act this is the only reference to guidelines. A further important exclusion from the jurisdiction of the Commission is its approval of the issue of securities under s. 57. Moreover, under s. 59 B.C. Hydro may dispose of its property without obtaining the Commission's approval.

60 I have mentioned sanctions and the Commission's threat to resort to Part 9 of the Utilities Act. Part 9 lists as an offence on the part of individual officers directors and managers of utility in the failure to comply with a Com-mission order.

61 Tested in terms of general principles I am of the view the observations of the Ontario Court of Appeal in Ainsley Financial Corp. v. Ontario (Securities Commission) (1994), 21 O.R. (3d) 104 (C.A.), are relevant. In that case the Ontario Securities Commission ("OSC") issued a draft policy statement, subsequently adopted with minor modifications after the action in question had been commenced.

62 This policy statement purported to be a guide to those engaged in the marketing and selling of penny stocks as to business practices the OSC regarded as appropriate. As was set out in greater detail in Pezim v. British Colum-bia (Superintendent of Brokers), [1994] 2 S.C.R. 557 [92 B.C.L.R. (2d) 145], major securities commissions such as the OSC have a policy role in the regulation of capital markets in the public interest as well as an adjudicative func-tion in applying sanctions in specific cases. The following headnote from Ainsley is, I think, relevant to the point before us.

The validity of the policy statement turned on its proper characterization. If the statement was a non-binding statement or guideline intended to inform and guide those subject to regulation, the statement was valid and within the authority of the OSC; guidelines of this nature do not require specific statutory authority and such guidelines are not invalid merely because they regulate in the sense that they affect the conduct of those at whom they, are directed. If, however, the statement imposed mandatory requirements enforceable by sanction, then the statement required statutory authority; a regulator cannot issue de facto laws disguised as guidelines.

63 The issue of non-mandatory guidelines is not a question before us. Here, I repeat, the Commission has ex-plicitly purported to enforce the application of its directions with the threat of sanctions.

64 In my view, the appellant is entitled to a declaration that the Directions in the reasons for Decision for Order G-89-94 issued 24 November 1994 which ordered the application of the Integrated Resource Plan to British Colum-bia Hydro and Power Authority are beyond the statutory powers of the Commission and are accordingly unenforce-able.

65 I would make no order as to costs.

Pursuant to s. 121 of the Utilities Commission Act, the foregoing will be certified as the opinion of the Court to the Commission.

Appeal allowed.

FN1 Referred to as Demand-Side Management (DSM).

FN2 The term preferred is chosen to imply that society has used some process to elicit social preferences in selecting among energy resource options. Unfortunately, there is rarely agreement on the best process for eliciting social pref-erences. Candidate processes in a democracy include public ownership with direction from cabinet or a ministry,

Page 13

1996 CarswellBC 352, 36 Admin. L.R. (2d) 249, 20 B.C.L.R. (3d) 106, 71 B.C.A.C. 271, 117 W.A.C. 271, [1996] B.C.W.L.D. 847, 61 A.C.W.S. (3d) 390

© 2011 Thomson Reuters. No Claim to Orig. Govt. Works

regulation by a public tribunal, referendum, and various alternate dispute resolution methods (e.g. consensus seeking stakeholder collaboratives).

END OF DOCUMENT

Negotiated Settlement Process

Policy, Procedures and Guidelines

January 2001

British Columbia Utilities CommissionSixth Floor, 900 Howe Street, Box 250

Vancouver, British Columbia, Canada V6Z 2N3

Telephone (604) 660-4700; Facsimile (604) 660-1102B.C. Toll Free: 1-800-663-1385

Internet Email: commission.secretary@bcuc.comWeb Site: http://www.bcuc.com

Negotiated Settlement Process

TABLE OF CONTENTS

PAGE NO.

I POLICY STATEMENT 1

II BACKGROUND 1

III WHEN IS THE NEGOTIATED SETTLEMENTPROCEDURE APPROPRIATE? 2

IV PROCEDURES FOR THE NEGOTIATED SETTLEMENT PROCESS 2

1. Initiation of the Process 2

2. The Right to Participate 3

3. Steps in the Negotiated Settlement Process 4

4. Discussions Without Prejudice and Confidential 5

5. Authority to Act 6

6. The Right to Dissent 6

7. The Appointment of a Facilitator 6

8. The Role of the Facilitator 7

9. The Role of Commission Staff in the Negotiations 7

10. Commission Panel’s Evaluation of Settlements 8

11. The Effect of a Settlement Agreement 9

V GUIDELINES FOR THE NEGOTIATED SETTLEMENT PROCESS 10

VI CONFIDENTIALITY AGREEMENT OF PARTICIPANTSTO THE NEGOTIATED SETTLEMENT PROCESS 11

British Columbia Utilities Commission

1

Negotiated Settlement Process

NEGOTIATED SETTLEMENT PROCESS

Policy, Procedures and Guidelinesof the British Columbia Utilities Commission

I POLICY STATEMENT

The Commission’s policy is to use the negotiated settlement process judiciously to save time and

reduce the cost of utility regulation while achieving sound regulatory decisions. The Commission

is committed to public participation in its processes and to transparency in its decision making. It is

in the spirit of these values that this policy will be implemented.

II BACKGROUND

To improve the effectiveness and efficiency of energy regulation in British Columbia, the British

Columbia Utilities Commission (the “Commission”) is adopting processes that are alternative or

complementary to its traditional regulatory process. For example, the Commission is using

technical workshops, issues meetings, and discussion groups to encourage regulatory participants

to discuss issues in an open, flexible and informal manner. On a number of occasions, the

Commission has used a negotiated settlement process to seek agreements among regulatory

participants about matters before the Commission.

There are a number of issues associated with the use of such alternative dispute resolution

processes in a quasi-judicial, decision-making environment, particularly in the context of energy

utility regulation. To address these issues the Commission initially issued discussion papers and

received useful comments from interested parties, and this procedure was repeated in a subsequent

review of the process.

Negotiated settlements can offer significant benefits to the regulatory process; however, realizing

those benefits, while maintaining fundamental principles of natural justice and fairness, requires that

certain principles and process attributes be present, including the appropriate participation of

Commission staff. If participants are not satisfied with a negotiated settlement process they are

free, at any time, to choose not to participate and to use the traditional hearing process to resolve

their concerns. The flexible nature of the negotiated settlement process allows it to adapt to

problems as they arise.

British Columbia Utilities Commission

2

Negotiated Settlement Process

A negotiated settlement process may not always be appropriate or successful. The first question to

be considered by potential participants is what, if any, of the issues are amenable to the negotiated

settlement process. Considerations to be taken into account are listed in section III.

The negotiated settlement process is a tool that complements the traditional regulatory process. The

Commission continues to administer its responsibilities under the Utilities Commission Act and

cannot delegate decision-making power to others; however, the negotiated settlement process is a

tool that provides considerable flexibility to the Commission and participants.

III WHEN IS THE NEGOTIATED SETTLEMENT PROCEDUREAPPROPRIATE?

To assist in determining when to use the negotiated settlement process, all or portions of an

application should be evaluated in light of certain considerations.

i) Will customer classes or other groups that are likely to be affected by the agreement

be participants in the negotiating sessions? It may be necessary to exercise

judgement as to the significance of any settlement agreement for parties that will not

be active participants.

ii) Will the application pose policy issues about which there is no established

Commission precedent? If so, all or portions of the application may not be suitably

addressed by negotiation.

iii) Has the set of issues posed by the application been subject to a public hearing

within a reasonable interval? This consideration derives from the need to maintain

an adequate public record and to avoid systematic lack of representation by any

affected customer class or group.

IV PROCEDURES FOR THE NEGOTIATED SETTLEMENT PROCESS

1. Initiation of the Process

The decision to initiate the negotiated settlement process that is outlined in section IV.3, will

be made by the Commission and confirmed by order, after consideration of the application,

the preference of the applicant, and likely interests of affected parties.

British Columbia Utilities Commission

3

Negotiated Settlement Process

Participation in negotiations is voluntary. While unanimous support is preferred before

attempting a settlement process, there may be situations where general agreement is

sufficient.

2. The Right to Participate

The right to participate in settlements is recognized by the Commission. The Commission

does not exclude or prohibit participation unless the party in question has no reasonable

interest in the subject matter of the settlement discussions.

It may also be the case that, in some circumstances, too large a number of interested parties

could preclude an effective settlement process. When this occurs, either a settlement will

not be attempted, the application will be divided into sub-issues to reduce the number of

participants at any one discussion, or participants representing similar issues may be

encouraged to work together.

Interested parties cannot be forced to participate in a settlement process. A decision not to

participate will not abrogate the right of the party to comment, for the Commission’s

consideration, on a resulting settlement agreement.

Proper notice is important to ensuring that all parties have the opportunity to participate in

settlement discussions. Notice requirements will be the same as for a public hearing before

the Commission.

Sufficient information will be available to registered intervenors so that issues can be

assessed and the negotiated settlement process can begin. In most cases this will mean

filing of the application, information requests, and responses to those requests.

Negotiated Settlement Processes are considered “proceedings” for the purpose of cost

awards under section 118 of the Utilities Commission Act. Awards may be granted even if

a settlement cannot be reached, but will be granted according to the same conditions, where

appropriate, as for costs awarded on account of a full public hearing.

British Columbia Utilities Commission

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Negotiated Settlement Process

3. Steps in the Negotiated Settlement Process

Before settlement discussions begin, the Commission will establish various pre-settlement

processes, including workshops and issues meetings. The purpose of workshops is to

assist all parties to understand specific aspects, policies or concepts in an application

through informal presentations and discussions. Once the pre-settlement processes are

established, a division of the Commission (“panel”) will be designated.

The negotiated settlement process may include technical workshops and pre-hearing

conferences but will usually include the following stages:

i) At the outset of the negotiated settlement process, meetings of interested parties and

Commission staff will normally take place at which participants will be invited to

identify issues arising from the application to be addressed through negotiation.

ii) Commission staff will advise the Commission panel of the appropriateness of

referring all, or portions of, an application to negotiation, making reference to the

criteria listed in section III. The panel will determine whether all, or selected

portions, of the application will be negotiated. The panel will also identify those

issues of particular concern to it, and this information will be passed on to the

participants in written form.

iii) The negotiated settlement process timetable, and opportunities for information

requests and responses from the utility, will be specified by the Commission panel

prior to the start of negotiations.

iv) Intervenors who intend to participate in the negotiations will be required to confirm

that they will adhere to the terms and conditions of the process, as set out in sections

V and VI, as a precondition of their participation.

v) During the negotiation meetings, participants will present their positions on each

issue.

vi) The participants will seek a consensus resolution of each issue. Any proposed

settlement agreement will allow dissenting participants to pursue their position

directly with the Commission panel as set out in paragraph 6 below.

British Columbia Utilities Commission

5

Negotiated Settlement Process

It is the responsibility of the negotiation participants to ensure that the proposed

settlement agreement contains sufficient evidence to support the proposal. In

particular, provisions of the proposed settlement agreement that relate to issues

identified by the Commission panel, or any other matters that may affect the public

or non-participant parties, must be supported by explicit rationales.

vii) The proposed settlement agreement will be circulated amongst the participants and

upon the written concurrence of the participants will then be distributed to all other

interested parties and to the Commission panel. Normally a member of staff who

has not been present in the settlement proceedings will review the proposed

settlement agreement prior to the Commission panel's deliberations. This function

is intended to provide support for the panel as to the impact of the proposed

settlement agreement on all parties, whether or not they were participants in the

negotiations.

viii) Any party who does not agree with the settlement will be expected to provide written

reasons to the Commission panel. All responses will be transmitted to the

Commission panel for its consideration.

4. Discussions Without Prejudice and Confidential

To foster open, frank, and innovative settlement discussions, bargaining positions presented

during the settlement discussions will be without prejudice and confidential. The without

prejudice and confidential nature of the discussions requires each participant to disclose

whether they are participating in their own right or on behalf of some client(s). This

disclosure will ordinarily appear in the Notice of Intervention, but if it does not, the

participant must disclose the identity of the party for whom the participant is acting.

Information that would have become available independently of the negotiated settlement

process remains public information. The parties must agree to the confidentiality agreement

set out in section VI below, or they will not be permitted to participate in the negotiated

settlement process. The confidentiality agreement will be made at the start of the first issues

meeting or, in any event, before the commencement of negotiations.

British Columbia Utilities Commission

6

Negotiated Settlement Process

5. Authority to Act

The Commission panel will require representatives to be able to speak to the concerns of

their group or client during negotiations. Further, the Commission panel will require that

representatives who sign a proposed settlement agreement have been given the authority to

do so by their group or client.

6. The Right to Dissent

The right of parties to dissent from a proposed agreement is explicitly recognized by the

Commission. If a party dissents, it can submit a written argument to the Commission panel.

If the Commission panel is of the view that the dissent is reasonable and material, it may

request written rebuttal argument or, where the settlement review process is to occur at an

oral hearing, request argument at the oral hearing. If the dissent is determined to be

reasonable and material, the dissenting party retains the right to present evidence and to

cross-examine or to rebut the evidence of others if there is a written hearing.

7. The Appointment of a Facilitator

The Commission will normally provide a facilitator from staff. However, if any active

participant in a negotiated settlement process requests someone other than Commission

staff to facilitate or chair the negotiating sessions, that request, with supporting reasons,

should be submitted in writing to the Commission panel. The requester must also submit

the name and credentials of an alternate facilitator. The other active participants in the

negotiated settlement process will be given an opportunity to comment on the request.

The Commission panel will approve the selection or advise the participants why the

proposed facilitator is unacceptable.

British Columbia Utilities Commission

7

Negotiated Settlement Process

8. The Role of the Facilitator

In conducting the settlement process the facilitator will:

• help to foster an environment of cooperation and trust among participants;

• ensure that all participants have an opportunity to express their views on each issue;

• facilitate the preparation of a proposed settlement agreement which contains all therequired components; and

• guide the preparation of a list of outstanding issues.

The facilitator in the negotiated settlement process has authority to bring about a resolution

of issues by any reasonable means, and in particular by:

• clarifying and summarizing a party's position;

• making explicit any differences in the positions taken by the respective parties;

• recognizing the possible concerns of unrepresented parties;

• encouraging a party to evaluate its own position in relation to other parties byintroducing objective standards; and

• identifying settlement options or approaches that have not yet been considered.

In summary, the function of the facilitator is twofold: a) to oversee the manner in which the

settlement process is carried out; and b) to ensure that the full range of issues is effectively

addressed. Parties to the negotiation are responsible for the substance of the proposed

settlement and the supporting rationales.

9. The Role of Commission Staff in the Negotiations

Staff participation in settlement discussions, and alternative dispute resolution generally, is

important to the effectiveness of the process. Staff provide certain skills, knowledge and

experience that may otherwise not be available to all participants.

British Columbia Utilities Commission

8

Negotiated Settlement Process

The responsibilities of staff present in the negotiations include:

• supplying factual information that may otherwise not have been brought to theattention of the participants;

• describing possible implications of settlement proposals for unrepresented parties;

• advising the participants of any precedents recognized by the Commission; and

• ensuring that the participants are aware of concerns of the Commission panelinsofar as they are known.

In summary, the responsibility of staff is to ensure that the interests of all affected parties

are taken into account, while refraining from endorsing a particular position. Staff who

attend settlement discussions will not disclose to the Commission any positions or offers

presented during the settlement discussions without the consent of all participants.

10. Commission Panel’s Evaluation of Settlements

While the Commission strongly supports the development of the negotiated settlement

process in British Columbia, it has a statutory duty to regulate in the public interest.

Therefore, the Commission panel will not accept a proposed settlement unless it is

persuaded that the settlement agreement is in the public interest and consistent with the

requirements of the Utilities Commission Act.

The Commission panel may approve agreements as “packages” rather than line-by-line.

At the same time, the Commission panel will not accept individual terms that, in its

judgment, contravene the Commission’s obligations under the Utilities Commission Act.

If the Commission panel wishes to amend a portion of a settlement and that amendment

would have a material effect on one or more interests, the Commission will provide the

necessary time for staff to contact all the signatories to the settlement to determine if they

will agree to the changes. A final meeting of the participants to the negotiated settlement

process to address the changes may be scheduled.

If the Commission panel rejects the settlement agreement, then where possible, an entirely

new panel will be constituted to decide the application through a public hearing.

British Columbia Utilities Commission

9

Negotiated Settlement Process

It is important that the Commission panel has sufficient information on the public record to

evaluate a settlement agreement. In most cases, the following minimum information will be

available: the terms of the agreement, the application and information responses, and a list of

the participants who agree to the terms of the settlement. The Commission panel may

require participants to submit additional information, either orally or in writing. Always, the

onus of ensuring that sufficient information is on the record will rest with the proponents of

the agreement.

The Commission panel may evaluate settlements through either an oral or a written public

hearing. The responses of participants and interested parties will be distributed to all

registered intervenors before a settlement hearing begins. The Commission panel may

approve the settlement agreement provided the Commission panel believes the settlement

satisfies the public interest.

11. The Effect of a Settlement Agreement

The benefits of the negotiated settlement process will only be realized if participants are

bound to the terms of the agreement. There are, however, circumstances where the proposed

settlement agreement may require amendment.

i) The Commission panel will normally accept or reject the entire settlement package

but if the Commission panel decides to suggest changes to the settlement it will give

registered intervenors full opportunity to address any proposed change, including

sufficient time to make submissions on the impact of any change to the validity of

the overall settlement;

ii) One or more participants may become aware of important new information that was

not reasonably available to them at the time of the settlement discussions and which

has a significant bearing on the assumptions upon which the settlement was reached;

or

iii) All participants may decide to opt out of the proposed settlement agreement pending

an acceptable amendment.

Amendments will not be made once the Commission panel has reviewed and accepted the terms of a

settlement.

British Columbia Utilities Commission

10

Negotiated Settlement Process

When participants sign off a proposed settlement they agree to provide their support to the

agreement and agree to waive their right to present evidence and cross-examine on matters dealt

with by the agreement.

V GUIDELINES FOR THE NEGOTIATED SETTLEMENT PROCESS

1. All negotiations are on a without prejudice basis for each issue until that issue has been

signed off.

2. Once an issue has been signed off, the participants signing off agree not to dispute that

issue at a hearing on the settlement agreement (settlement hearing) unless new material

information becomes available that was not reasonably available at the time of the

negotiations.

3. Participants dissenting from a proposed agreement may submit a written argument to the

Commission panel. If the Commission panel is of the view that the dissent is reasonable

and material, it may request written rebuttal argument or, where the settlement review

process is to occur at an oral hearing, request argument at the oral hearing. If the dissent is

determined to be reasonable and material, the dissenting party retains the right to cross-

examine, call evidence, and make final argument on the issue at a settlement hearing without

prejudice to any positions that they may or may not have taken during the negotiations. In

such an instance, no reference will be made to any positions taken by any other participant

during the negotiations. In like manner participants that do sign off, preserve the right to

cross-examine, call evidence, and make final argument on the issue raised by dissenting

participants.

4. Participants to the negotiations agree that they will not raise at a settlement hearing any

position taken by other participants during the negotiations.

5. Participants to the negotiations agree that they will not communicate the positions taken at

the negotiations to third parties unless all the participants to the negotiations agree.

6. Once the negotiations are completed, and all issues are signed off, the proposed settlement

agreement will be circulated to all other interested parties whether or not they were present at

the negotiations in order to advise them of the negotiations and to obtain the positions of

those not present.

British Columbia Utilities Commission

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Negotiated Settlement Process

7. The Commission panel will be provided with the proposed settlement agreement and

supporting information at the time it is circulated to all other interested parties. The

Commission panel will also be provided with any comments submitted by interested parties.

8. The Commission panel will not be provided with any information about the negotiations per

se unless the participants to the negotiations agree.

VI CONFIDENTIALITY AGREEMENT OF PARTICIPANTSTO THE NEGOTIATED SETTLEMENT PROCESS

As discussed in section IV, paragraph 4 above, “Discussions Without Prejudice and Confidential”,

bargaining positions presented during the settlement discussions will be without prejudice and

confidential. All parties in attendance during settlement negotiations must agree to the

confidentiality agreement set out below and comply with the confidentiality agreement, or they will

not be permitted to attend the negotiated settlement process.

We, on behalf of ourselves, and/or on behalf of our clients, as the case may be, will

not disclose any positions taken either orally or in writing during the course of the

negotiated settlement process to any parties not subject to this confidentiality

agreement without the consent of all participants to the negotiations.

Without restricting the generality of the foregoing, we acknowledge that this

confidentiality agreement will prevent us, or our clients, from cross-examination on

those positions at any public hearing held in this matter and further prevent us from

making use of those positions against the proponent of the positions in any

argument at such hearing. Similarly, we undertake not to cross-examine witnesses

about any positions taken in the negotiated settlement process.

We further acknowledge that we have fully read and now agree to conduct our

attendance and negotiations according to the Negotiated Settlement Process - Policy,

Procedures and Guidelines as set out by the Commission.

aRetail Markets

Downstreamof the Utility Meter

Guidelines

APRIL, 1997

TABLE OF CONTENTS

Page No.

1 . 0 INTRODUCTION 1

2 . 0 THE RETAIL MARKET DOWNSTREAM OF THE UTILITY METER 2

3 . 0 ROLE OF THE COMMISSION IN THE NEW MARKET PLACE 5

4 . 0 STAFF PROPOSAL: POSITIONS OF PARTIES 8

4.1 Commission Objectives 94.2 Choosing a Corporate Structure: Criteria 104.3 Choosing a Corporate Structure: Principles 134.4 Transfer Pricing Policy 154.5 Code of Conduct 174.6 Other Issues 21

5 . 0 COMMISSION GUIDELINES WITH RESPECT TO UTILITYOR NRB PARTICIPATION IN DOWNSTREAM RETAIL MARKETS 2 1

5.1 Use of Utility Assets and Services in the Downstream Retail Market 21

5.1.1 Jurisdiction 215.1.2 Objectives 225.1.3 Criteria 235.1.4 Principles 24

5.2 Transfer Pricing Policy 245.3 The Code of Conduct 265.4 Other Issues 27

APPENDIX 1

1

1 . 0 INTRODUCTION

On July 10, 1996, the Commission announced a process for the review of the retail market downstream of

the utility meter. In particular the Commission sought to examine the forces which are causing utilities to

wish to expand the number and kinds of services which they offer and to determine if, and to what extent,

utilities and/or their affiliated non-regulated businesses ("NRBs") should be allowed to participate in

downstream retail markets.

As an initial step in the review process, the Commission held a workshop on October 16, 1996 at which a

variety of parties were given the opportunity to present their views. In addition, the Commission called

for written submissions by October 31, 1996, including advice as to what future processes were required

to address the issue. Submissions were received from many parties, including utilities, marketers,

independent contractors, and customers. After reviewing all the submissions, the Commission determined

that this matter could best proceed through a written process. Accordingly, the Commission instructed

staff to prepare a position paper on this topic which could then be circulated for discussion by interested

parties.

The staff paper, which was released December 16, 1996, reviewed the traditional role of utilities and

emerging pressures for changes to this role, provided staff's interpretation of the Commission's

jurisdiction with respect to utility or utility-affiliated NRB participation in the downstream market, and

summarized the issues and concerns regarding utility participation which had been presented to the

Commission. Based on the above, staff concluded that there were likely to be circumstances in which

utility participation in the downstream market, either directly or through an NRB using some utility

facilities or services ("related-NRB"), would be desirable and other circumstances in which participation

should be limited to self-financing, stand-alone, arm's length NRBs using no resources of the utility.

Accordingly, the staff position paper proposed a set of principles and guidelines for the Commission to

use to assess individual utility proposals to determine which proposals should be pursued using stand-

alone NRBs and which could be pursued either by the utility directly or through a related-NRB.

Initial comments to the Commission on the position paper were requested by January 31, 1997. In

addition, the process allowed parties to respond to the initial comments of other parties by supplying reply

comments to the Commission by February 21, 1997. The Commission received initial comments from

24 parties and replies to the initial comments from six parties. A list of parties providing comments is

attached as Appendix 1.

This document summarizes the submissions made with respect to the staff position paper and concludes

with the findings of the Commission with respect to the participation of utilities and their NRBs in the

retail market downstream of the utility meter.

2

2 . 0 THE RETAIL MARKET DOWNSTREAM OF THE UTILITY METER

As discussed in the staff position paper, utilities are generally established in response to natural monopoly

conditions. A natural monopoly is said to occur if the provision of a good or service can be provided at

lowest cost by a single firm, rather than by two or more firms; i.e., there exist substantial economies of

scale. Utilities may also be asked to provide an associated product if its provision by the utility leads to

economies of scope; i.e., a single firm is able to produce two or more joint products at a lower unit cost

than single firms each producing just one of these products. However, because the provision of the good

or service by a single firm leads to the potential of monopoly pricing, utilities are generally regulated with

respect to price and service quality. A very broad definition of a public utility is provided in the Utilities

Commission Act ("the Act") for the purposes of regulation under Part 3 of the Act. The definition has

remained unchanged since the 1970s.

Since the mid-1980s, both natural gas and electricity utilities have found that at least some of the services

which they have traditionally provided, including commodity sales and energy-efficiency services, can be

provided by other non-regulated market participants. As a result, the breadth of true natural monopoly

services has decreased even though the range of regulated utility options has greatly expanded to

accommodate competitive markets upstream of the utility. This has led to the deregulation of certain

commodity components of traditional utility services and reliance for their provision on the competitive

market. As well, it has prompted requests for further deregulation of other services still provided by the

utility.

One consequence of the growing deregulation of natural gas and electricity utilities has been a movement

towards convergence between the markets for natural gas and electricity. One response to this

convergence has been the emergence of 'mega-marketers', that is, firms which offer customers a full menu

of energy services, including provision of both the natural gas and the electricity commodity, commodity

contract marketing, equipment sales, rentals and servicing, and energy efficiency marketing. For those

customers who have the technical capability, the emergence of mega-marketers allows them to switch more

easily between natural gas, electricity and efficiency measures as prices dictate. For all customers, the

emergence of mega-marketers can mean increased convenience through 'one-stop shopping'.

The reduction in the size of the traditional utility domain, as certain services become available from non-

regulated suppliers and as mega-marketers become more prominent, has led some utilities to re-evaluate

their traditional service offerings. For some utilities, this is leading to a desire to offer services not

previously offered by utilities and to move into downstream retail markets not traditionally served by

utilities. For others, it is leading to a desire to change the way in which services are offered, notably to

offer certain services on a non-regulated basis in the downstream retail market rather than as a regulated

tariff item.

3

The retail market downstream of the utility meter can generally be described as consisting of those goods

and services which are related to or support the delivery and/or use of the energy commodity. Figure 1

identifies many of the energy and energy-related products and services contained in the retail market

downstream of the utility meter.

Figure 1: Potential Goods and Services Downstream of the Utility Meter

Burner Tip/End-Use Services Billing and Metering1

- Repair and Maintenance Meter Services- Equipment Sales/Rentals Safety and Security Services

DSM Investments - Carbon Monoxide Detectors

Financing - Call Dispatch

Warranties Heating Insurance Services

Energy Management Systems Commodity Sales

In general, the total range of goods and services potentially provided by energy utilities can be categorized

as belonging to one of three areas. Figure 2 depicts these areas as part of the question of determining the

proper domain of the utility. These areas are: goods and services which still clearly are defined as core

monopoly products (e.g., wires and pipes), competitive products which could best be produced by a

variety of players operating within a competitive market (e.g., appliance sales), and debatable/transitional

products, i.e., those which are associated with the monopoly core and which may or may not be

considered true monopoly activities depending on one's assessment at any given time (e.g., billing/meter

information). For example, these products might be provided by the utility as they emerge, later be

produced by a mix of utility and unregulated providers as the market grows and eventually be provided

solely by the competitive market when the market is mature (e.g., natural gas vehicle conversions). Core

monopoly products result primarily from economies of scale or scope and are expected to decrease as a

result of advances in technology reducing these economies, competitors' demands for access to the market

for these products, customers' demands for more choice and the success of deregulation elsewhere.

1. Some parties argue that the meter/regulator assembly and meter reading information to customers may also become a

competitive service. However, in the near term, the utility will require basic meters in its control to verify the quantitiesof energy transported by the monopoly pipes or wires.

4

Figure 2

The Domain of the Utility

Competitive Products

e.g., Appliance Sales

CoreMonopolyProducts

e.g., pipes, wires

Debatable / Transitional Productse.g., billing / meter information

5

Figure 3: Goods and Services Providers Downstream of the Utility Meter

Heating/Cooling/Plumbing and Electrical Contractors

Mega-Box Stores

Appliance Retailers

Energy Service Companies ("ESCOs") Telecom/Cable Companies

Energy Consultants Financial Institutions

Security Companies Software Developers

Home Service Retailers Call/Dispatch Centres

Home Inspectors B.C. Utilities and NRBs

Hardware/Lumber Stores Non-B.C. Utilities and NRBs

Figure 3 identifies current and potential service providers of goods and services downstream of the utility

meter. These parties vary substantially in size and specialization. Other market participants include

traditional customers and other parties such as water/sewer service providers and emergency response

providers that might be able to use services which the utility provides 'in-house', (e.g., meter reading,

dispatch services).

3 . 0 ROLE OF THE COMMISSION IN THE NEW MARKET PLACE

In British Columbia, regulation of natural gas and electricity utilities is undertaken by the British Columbia

Utilities Commission ("BCUC", "the Commission") under the authority of the Act. The Commission’s

powers include oversight of utility rates and the utility expenditures responsible for those rates. The staff

position paper concluded that these powers give the Commission the ability to define the utility's domain,

that is to determine which goods and services the utility will provide, since the utility would be unlikely to

offer services for which it cannot recover the costs. As a result, the paper suggested that the Commission

has the power to influence the corporate structure under which utility shareholders will participate in the

unregulated market.

Four corporate structures, under which retail products and services could potentially be provided, were

identified in the staff position paper: i) through the utility as a regulated tariff product; ii) through the utility

as a non-regulated product; iii) through an NRB affiliated with the utility either as a subsidiary or through a

parent company and using some utility facilities and services; or iv) through an NRB but using no utility

facilities or services. These structures are differentiated primarily by the extent to which utility assets and

services are used to provide goods and services into the downstream retail market. These four corporate

structures are presented in Figure 4.

6

Figure 4

Potential Corporate Structures

1The utility is the sole

corporate entity, providing downstream products

through a regulated tariff.

2The utility is the sole

corporate entity, providing downstream products on an unregulated basis, perhaps

through a division.

Utility Utility

ParentCompany

ParentCompany

Utility RelatedNRB

Utility Stand-AloneNRB

3Unregulated retail products

provided by related NRB using some utility facilities

and services.

4Unregulated retail products

provided by stand-alone NRB using no utility facilities or

services.

Unregulatedproductsdivision

7

Although the paper suggested that the Commission can determine how the utility or its affiliates participate

in the unregulated market, it indicated that the Commission does not have the power to control the activities

or to determine what services an NRB will provide if the NRB is a self-financing, stand-alone, arm's

length affiliate using no resources of the utility. However, where the NRB is not a completely stand-alone

entity, the paper suggested that the Commission can exercise control over funding, manpower or other

services that may be provided by the utility to the NRB, including the use of shared offices, shared

services and manpower charge-out rates.

In either case, the paper stated that the power to oversee utility rates and expenditures confers on the

Commission the power to oversee the relationship between the utility and any related-NRB to ensure that

no NRB costs are passed on to utility customers. Specifically, the Commission has a duty to ensure that

utility ratepayers are, at the very least, not negatively affected by the activities of NRBs. However, the

paper indicated that it is less clear whether the Commission has the power to ensure that NRBs receive no

benefit from being affiliated to a utility, even if no costs accrue to the utility customers from the affiliation.

As expected, the Commission received a variety of comments concerning the views expressed in the staff

position paper. Generally, the utilities argued that the Commission had limited jurisdiction with respect to

the issue of utility participation, either directly or indirectly, in downstream retail markets. For example,

the British Columbia Hydro and Power Authority ("B.C. Hydro") argued that the Act does not grant

jurisdiction to the Commission to regulate competition in downstream retail markets, to restrict a utility in

any way from entering the downstream retail market, nor to exercise any sort of jurisdiction over the

activities of a stand-alone NRB.

BC Gas Utility Ltd. ("BC Gas") argued that the Commission has the jurisdiction to oversee the prudency

of the provision of resources by the utility to an NRB but has no jurisdiction to constrain an NRB from

obtaining resources from the utility or any other market provider. This seems to imply that in BC Gas'

view the Commission has responsibility to minimize potential negative impacts on ratepayers but cannot

determine what benefits, if any, NRBs or other participants receive from the utility as long as there is no

risk of cross-subsidization from ratepayers. In addition, BC Gas stated that the Commission has no

jurisdiction to determine the appropriate degree of competition in the market place.

Westcoast Energy Inc. ("Westcoast") also argued that the regulator does not have jurisdiction over the

activities of the NRB even if the NRB purchases some support services from the utility. Westcoast stated

that the regulator is limited to ensuring that the utility does not, by its behavior or structure, abuse its

monopoly position to prevent the development or continuation of a competitive market for those products

and services that are not regulated. Westcoast stated that this implies that there should be no cross-

subsidization and that NRBs should not be given information which would interfere with fair competition.

8

Enron Capital and Trade Resources Corp. ("Enron") took a broader view of the Commission's powers,

stating that the Commission's powers include the ability to restrict a utility from entering the downstream

retail market and to regulate the relationship between the utility and NRBs. In Enron's view, this includes

the power to ensure that NRBs receive no benefit from their affiliation with a utility, even if no costs

accrue to the utility customer. In this view they were supported by the Heating, Ventilating and Cooling

Industry Association ("HVCI").

In response to these submissions, the Commission staff sought a legal opinion on the issue of the

Commission's jurisdiction with respect to downstream retail markets. In summary, the opinion stated the

following:

1. The Commission does not have the jurisdiction to directly regulate an NRB unless the NRB isitself a public utility, a common carrier, or a common processor.

2. The Commission has the jurisdiction to regulate the relationship between a public utility and anaffiliated NRB to the extent that the relationship affects ratepayers. For example, the Commissionhas the jurisdiction to ensure that an NRB is not 'subsidized' by a public utility to the detriment ofratepayers.

3. The Commission does not, however, have the jurisdiction to regulate the relationship between apublic utility and an NRB so as to ensure the relationship does not affect the competitive retailmarket downstream of the meter. The Commission's jurisdiction is limited to consideration of theeffects of the relationship on ratepayers.

4. The Commission has the jurisdiction to regulate retail market downstream of the utility meter("RMDM") activities by a public utility, but only to the extent that such activities affect ratepayers.Similarly, the Commission has the jurisdiction to prohibit a public utility from participating inRMDM if prohibition is the only reasonable and effective means by which the Commission canmitigate or alleviate any negative effects on ratepayers.

5. Ratepayers do not own a public utility's corporate name. The corporate name is goodwill which isowned by the company. The shareholders have a right to share in the assets of a company,including the corporate name, if the company is dissolved.1

4 . 0 STAFF PROPOSAL: POSITIONS OF PARTIES

This section contains a summary of the views presented in the submissions regarding the staff paper. The

Commission's determinations on these issues are provided in Section 5. This allows for a consolidated

statement of Commission policy that may be used as a working document for future discussions.

1. Opinion Letter from Boughton, Peterson Yang Anderson dated March 10, 1997.

9

4 . 1 Commission Objectives

The Commission staff position paper proposed a set of principles and guidelines to help the Commission

make determinations regarding utility and related-NRB participation in the retail market downstream of the

utility meter. As a starting point, the paper identified four objectives which staff suggested should guide

any determinations the Commission made. These are presented in Figure 5.

Figure 5: Suggested Commission Objectives

There must be no subsidy of unregulated business activities, whether undertaken bythe utility or its NRB, by utility ratepayers.

The risks associated with participation in the unregulated market must be borneentirely by the unregulated business activity, that is the risks must have no impact onutility ratepayers.

The most economically efficient allocation of goods and resources should be sought.

Customer choice should be maximized.

These objectives were not seen to be completely mutually achievable in all cases so that it was expected

that trade-offs between objectives would need to be made. Further, staff expected that the extent to which

the achievement of one objective would preclude the achievement of another would depend on the

individual circumstances associated with a proposal. As a result, staff suggested that any proposal by a

utility to enter the downstream retail market, either directly or through a related-NRB, should be evaluated

by the Commission on a product and utility specific basis.

All parties seemed to be in agreement with the first two objectives identified in the staff position paper,

although Pacific Northern Gas Ltd. ("PNG") stated that there should be symmetry between risk and

reward so that, if the NRB bore all the risk of the unregulated enterprise, it should also receive all the

reward.

However, several parties took issue with the third and fourth objectives identified in the paper. The

Consulting Engineers of British Columbia ("CEBC") suggested that the Commission did not have the

jurisdiction to pursue either the third or fourth objectives. This was echoed by HVCI who argued that the

Commission did not have a mandate to influence the market in any way. In particular, they argued that the

Commission's mandate did not extend to exploiting economies of scale or scope, even if their exploitation

benefited ratepayers, nor did it extend to the maximization of customer choice. The Mechanical

10

Contractors Association of British Columbia ("MCABC") suggested that the objectives were unclear while

PNG indicated that economic efficiency was difficult to measure objectively.

In contrast, the Consumers Association of Canada (B.C. Branch) et al. ("CACBC (B.C.) et al.") agreed

with all four objectives and indicated that priority should be given to maximizing customer choice.

Westcoast also appeared to support all four objectives, arguing that customers should be free to choose

what they want and that their choice should determine market structure. Westcoast stated that the rights of

customers and shareholders to capitalize on potential efficiency gains should also be recognized. PNG

also supported the objective of customer choice and noted that a key aspect of customer choice is the

quality of service provided, not just the number of providers.

Enron also supported all four objectives but indicated that a fifth objective should be added, namely, the

preservation and enhancement of robust competition in downstream markets. Enron argued that

preservation and enhancement of robust competition would support economic efficiency and customer

choice. In contrast, BC Gas argued that the Commission did not have jurisdiction to preserve or enhance

competition so that the objective suggested by Enron should not be accepted.

BC Gas did not take issue with the four objectives put forward by staff but stated that different proposals

to move current utility services from the utility to an NRB will affect the objectives differently and that

flexibility will be required. Further, BC Gas argued that any statement of objectives adopted by the

Commission should include some reference with respect to the Commission pursuing these objectives only

in the areas in which it has jurisdiction.

4 . 2 Choosing a Corporate Structure: Criteria

As shown in Figure 4, the staff position paper identified four corporate structure options under which

goods and services could be provided to the downstream retail market. The paper suggested that, for any

individual proposal for utility participation in the downstream retail market, the corporate structure which

should be chosen was that which best met the four objectives. As shown in Figure 4, these corporate

structures are:

i) provision by the utility as a regulated tariff item;

ii) provision by the utility as an unregulated good;

iii) provision by an NRB using some utility resources; and

iv) provision by a completely stand-alone NRB using no utility resources.

11

In assessing which of the four corporate structure options best satisfies the four objectives discussed

above for any particular proposal, the position paper suggested the following criteria.

i) Does a natural monopoly currently exist for the good or service?

ii) If the good or service is not a natural monopoly, can the utility ratepayer be sufficiently protected ifeither the utility or an NRB offers the good or service?

iii) Are there significant economies of scale or scope associated with the good or service?

iv) Could the provision of the good or service be used to offset assets which would otherwise bestranded?

v) Does there already exist significant customer choice with respect to the good or service?

vi) Is the provision of the good or service by the utility or a related-NRB likely to lead to marketdominance abuses in the long term?

Several parties indicated that of the four potential corporate structures identified for the delivery of goods

and services to the downstream retail market, only two were acceptable. These were: i) provision by the

utility as an regulated tariff item, and iv) provision by completely stand-alone NRBs using no utility

resources. Groups such as HVCI and MCABC argued that, unless the good or service were a natural

monopoly, utilities should only be allowed to participate in the downstream retail market through a stand-

alone NRB using no utility facilities or services. This was seen as providing maximum protection to the

ratepayer and is consistent with their view that only the first two of the four staff objectives should be

reflected in the Commission's decision making. Further, MCABC argued that given the current level of

fiscal restraint in government, it was unlikely that codes of conduct and other watchdog measures could be

adequately enforced.

These groups appeared to recognize that using utility resources to provide downstream services could

result in the avoidance of stranded utility assets but argued that it would be at the expense of current

service providers. CEBC argued that the Commission should not be concerned about the economic well-

being of the utility at the expense of the economic well-being of other industry participants, while MCABC

argued that reduced utility earnings now should be weighed against years of good, stable earnings.

Further, MCABC argued that allowing utilities to compete in the downstream retail market, either directly

or through related-NRBs, would lead to a loss of customer choice in the long term.

Enron also argued that utilities should be prohibited from participating in the downstream market other

than through stand-alone NRBs except under very exceptional circumstances. Although Enron did not

appear to reject the proposed criteria, they argued that restricting participation to stand-alone NRBs was

required to mitigate both the risk of cross-subsidization and the risk of anti-competitive behavior by the

utility. Further, they argued that, since the only appropriate utility functions were those related to the

12

'pipes and wires', there was unlikely to be any significant economies of scale or scope to offset the

increased risk of a related-NRB. Finally, they argued that they did not believe utility participation would

enhance customer choice since any competitive advantage accruing to the NRB from association with the

utility would be detrimental to competition. For example, Enron suggested that utility participation in

Demand-Side Management ("DSM") programs does not enhance customer choice since it restricts

participation by new entrants that could provide the service. Accordingly, Enron asked the Commission to

adopt the decision taken by the Manitoba Public Utilities Board, which prohibited utility participation

except through completely stand-alone NRBs.1

In contrast to the position outlined above, the utilities supported the potential use of related-NRBs to enter

the downstream retail market. West Kootenay Power Ltd. ("WKP") agreed that a stand-alone NRB was

the best way to protect ratepayers but stated that it might not be ideal in every circumstance. In particular,

WKP argued that restricting participation to stand-alone NRBs could prevent achievement of economies of

scale or scope, particularly when these economies were linked to core competencies. Accordingly, WKP

argued that, when there are substitutes which could provide effective ratepayer protection, these

alternatives should be allowed .

BC Gas indicated that it wished to move existing utility services which could or should be provided on a

competitive basis out of the utility and into NRBs but indicated that this would need to be done as market

conditions permitted. Further, BC Gas indicated that, while it viewed the provision of retail services by a

stand-alone NRB as the preferred long-term option, since it prevented any cross-subsidization by utility

ratepayers, in the short run it might be necessary to use related-NRBs as a transitional step. BC Gas urged

the Commission to provide explicit recognition of the need to permit the 'transitioning' of emerging

RMDM products and services from regulated utilities to non-regulated companies. PNG also argued for

the use of related-NRBs to avoid stranded costs and stated that the issue of stranded costs was likely to

achieve greater importance as the areas of natural monopoly diminished.

BC Gas also expressed concern with how criteria v) and vi) might be applied. With respect to criterion v),

BC Gas suggested that, if the utility already has some of the market share of a product or service which is

now competitive, the service should be 'transitioned' to the market regardless of the number of

competitors. Further, the utility argued that existing and potential customers should be allowed to choose

the service they take as well as their service provider.

With respect to criterion vi), BC Gas argued that the Commission has no mandate to determine the

potential for long term competitive market abuses, except insofar as the utility's provision of services

potentially creates the abuses. Similar views were expressed by WKP, which argued that the

1. Manitoba Public Utilities Board, Public Hearing to Review the Guidelines for Acceptable Conduct Between Centra Gas

Manitoba In. and its Affiliated Companies, Order of the Board No. 110/96, released November 4, 1996.

13

Commission could not consider impacts on unregulated business or unregulated markets when exercising

its jurisdiction over services provided by a utility to an NRB.

Westcoast recognized that total separation does provide maximum protection to ratepayers but argued that

other factors also needed to be considered. As indicated earlier, Westcoast argued that the rights of

consumers and shareholders to capitalize on potential efficiency gains were important. As a result, they

argued the degree of corporate separation should reflect individual circumstances.

Westcoast also expressed concern with respect to criterion vi), arguing that the regulator is limited to

ensuring the utility does not, by its behavior or structure, abuse its monopoly position to prevent the

development or continuation of a competitive market for those products and services which are not

regulated. Specifically, they argued that the Commission is confined to ensuring that there is no cross-

subsidization and that NRBs are not given information which would interfere with fair competition. In

addition, Westcoast stated that market dominance achieved under fair competition and contestable market

conditions was not, in and of itself, abusive. Finally, Westcoast argued that forcing a stand-alone NRB

structure on utility participation in retail markets was of no value to consumers unless it was the result of

customer choice.

Other parties, such as Willis Energy Services ("Willis") and Kanelk Transmission Company ("Kanelk"),

argued that participation through stand-alone NRBs should not be required under all circumstances. Willis

argued that this could lead to extra costs and that as long as NRBs covered their own costs ratepayers were

adequately protected. Kanelk argued that allowing utilities to compete in the downstream retail market

increased customer choice.

4 . 3 Choosing a Corporate Structure: Principles

Finally, the staff position paper suggested that if the six criteria discussed above were accepted, the

following principles would be appropriate for making determinations with respect to proposals regarding

specific goods and services.

i) If a natural monopoly exists for the good or service, it should be provided as a regulated tariff item(Corporate Structure 1 in Figure 4).

ii) Utility participation in the unregulated downstream market by completely stand-alone NRBs usingno utility resources is generally the preferred option since it provides the maximum protection toutility ratepayers (Corporate Structure 4 in Figure 4). Variations from this option should beundertaken only when it can be shown that this option would result in the loss of significanteconomies of scale or scope, the incurrence of substantial stranded costs for the utility, or unduerestriction in customer choice.

14

iii) The onus should always be on the utility to prove that the benefits associated with the use of utilityresources are sufficient to warrant the changed structure. Generally, the Commission wouldexpect to see economies of scale or scope, or the avoidance of stranded costs, only with respect togoods or services which are closely aligned to the utility's core competencies, e.g., billing andmeter reading and meter services. Similarly, benefits from increased customer choice are mostlikely to occur in new and emerging markets or where there are few current providers of the goodor service, (e.g., equipment repair services in remote communities).

iv) If the Commission decides to allow the use of utility resources in the provision of the unregulatedgood or service, the preferred option is through a related-NRB (Corporate Structure 3 in Figure 4).Direct participation by the utility in the provision of an unregulated good or service should beallowed only when the costs associated with forcing the provision through the related-NRBstructure would significantly offset the benefits associated with the use of the utility's resources(Corporate Structure 2 in Figure 4).

v) Utilities and their related-NRBs must move unregulated products which use utility resources intostand-alone NRBs as soon as market conditions warrant or the Commission otherwise sodetermines (Corporate Structure 4 in Figure 4). Utilities will be required to provide periodic proofthat the benefits associated with the use of utility services continue to exist.

vi) In all cases, the Commission should consider the long-term effects on the market of utility orrelated-NRB provision of unregulated goods and services.

All parties appeared to agree that if a good or service were a natural monopoly, it should be provided as a

regulated tariff item. MCABC also supported the concept that a completely stand-alone NRB was the

preferred option for utility participation in the downstream retail market and that the onus is on the utility to

prove why a variation from this structure is desirable. However, MCABC opposed the use of any utility

resources in the provision of unregulated goods and services under any corporate structure.

MCABC supported the principle that utilities and their related-NRBs must move unregulated products

which use utility resources into stand-alone NRBs as soon as market conditions warrant or when the

Commission otherwise so determines. However, MCABC expressed concern that the staff position paper

appeared to envision a situation in which the utility would begin a project at ratepayer expense but move it

to an NRB once it became profitable, without compensation to the utility. MCABC argued that assets

acquired under regulation are not the exclusive property of the company and shareholders but are the

shared assets of both the company and ratepayers. Accordingly, it stated that if assets were moved to an

NRB, the utility and its ratepayers should be compensated.

As well, MCABC requested that the Commission nullify the 1988 agreement between Inland Natural Gas

and its successors and MCABC, regarding appliance sales. Finally, MCABC indicated that the principle

that the Commission should consider the long-term effects on the market of utility or related-NRB

provision of unregulated goods and services was unclear.

15

The Association for the Advancement of Sustainable Energy Policy ("AASEP") also was concerned that

ratepayers might be made to pay the start-up costs for DSM programs which would then be transferred to

NRBs once the programs became profitable. Additionally, AASEP expressed concern that the movement

to non-regulated supply would change the type of programs offered, that market failures would not be

addressed and that too little DSM would be purchased. Accordingly, AASEP argued that utilities should

only be allowed to change DSM programs if they can show that the new programs would deliver equal or

greater savings.

Both PNG and BC Gas indicated that they saw the principles set out in the staff position paper as being

reasonable, although BC Gas stated that the Commission should make clear that any principles and

guidelines adopted by the Commission applied only to the provision of utility resources used to support

downstream retail market activities during a transitional period. Similarly, WKP stated that the final

principles and guidelines should clearly state that the principles and guidelines are not intended to affect

products and services traditionally provided by the utility, such as metering and billing. In addition,

BC Gas stated that in its view, in considering long-term effects, the Commission was limited to

considering the terms for provision of resources by the utility to a related-NRB and the impact on the

utility and its ratepayers, and not to the market generally. This view was supported by the City of New

Westminster ("the City") which suggested that the Commission did not have the jurisdiction to consider

the effect that utility-provided goods and services could have on the market. In addition, the City argued

that the Commission did not have the responsibility to determine when market or other conditions

warranted the transfer of a business activity from the utility to an NRB.

Kanelk stated that they did not support the principles set out in the paper since they viewed the

Commission's duty to be limited to ensuring that ratepayers do not subsidize non-regulated operations.

Accordingly, they argued that each utility should have the flexibility to develop its own corporate structure,

as long as it can reasonably demonstrate that the regulated operations are not subsidizing the non-regulated

operations.

4 . 4 Transfer Pricing Policy

The staff position paper suggested that, where utility resources are used to provide unregulated goods and

services, either directly or through a related-NRB, the use of the utility resources must comply with a

Commission-approved transfer pricing methodology. Further, the paper suggested that the transfer

pricing policy should ensure the following:

i) The operating costs of non-regulated activities are not reflected in the utility's cost of service.

ii) The costs of developing new business ventures are charged to and recovered from the NRB.

16

iii) The accounting costs are transparent and fully recover costs for all services, including overhead,space, employee benefits, inconvenience, and a profit margin where appropriate. If the serviceprovided by the utility to the related-NRB could also be obtained from an independent supplier, theprice paid by the related-NRB to the utility should be no less than the competitive market price.

iv) The financial costs of each business are borne by the business. In the exceptional case where theutility provides guarantees, it must be given financial compensation.

All parties appeared to recognize that if the Commission were to allow utility affiliated NRBs to use utility

facilities or services, a transfer pricing policy governing these transactions is required. BC Gas stated that

ensuring an equitable return to the utility for any services provided, providing appropriate protection to

ratepayers and preventing any unfair competitive advantage from being conferred on the related-NRB

should be the prime considerations with regard to structuring such a policy. However, BC Gas also

argued that the specific components of the transfer pricing policy should be established on an NRB-

specific basis to reflect individual circumstances rather than as a blanket policy designed to apply to all

circumstances. Accordingly, BC Gas suggested that, in this process, the Commission should establish a

general framework to ensure that these goals were met but develop more specific rules when specific

applications were brought forward. BC Gas also argued that the transfer pricing policy should specify that

there would be periodic reviews for compliance. This was echoed by MCABC, which called for periodic

reviews of transactions between the utility and its NRBs.

WKP argued that the transfer pricing policy should simply ensure that the incremental operating cost of

non-regulated activities are not reflected in the utility's cost of service. Further, WKP stated that the price

at which facilities or services were priced to the NRB should be at their incremental cost of provision.

Although the staff position paper contemplated that facilities and services would be charged at the full

embedded cost of the facility or service, WKP argued that there was no economic reason to price at

anything more than incremental cost. Indeed, WKP argued that to price services above incremental costs

would result in ratepayers benefiting at the expense of the NRB customer.

PNG also suggested that the charge which the NRB paid should be based on the incremental or marginal

cost of providing the service but added that the charge should also include some return for the utility

ratepayer. In this way, PNG argued that the benefits of sharing services or facilities would accrue to both

the NRB and the utility rather than going entirely to the utility.

Kanelk indicated that it supported the transfer pricing policy although it suggested that if ratepayers were

bearing none of the risks of the non-regulated activities, they should reap none of the rewards. In

addition, Kanelk rejected the position that NRBs must be financed separately from the utility, suggesting

that this could result in a sub-optimal corporate structure which could adversely affect a utility's ability to

compete in the market.

17

Enron, who had argued that NRBs should be stand-alone except under exceptional circumstances, argued

that utilities and their NRBs should be permitted to share overhead administrative services to the extent that

such sharing does not allow the exchange of market-sensitive information.

4 . 5 Code of Conduct

The staff position paper suggested that the utility and its NRB must comply with a Commission-approved

code of conduct. The paper suggested that each utility develop its own code of conduct to reflect its

particular circumstances and unregulated market offerings, but that all codes should cover employment of

utility personal, including career training and development, procedures for contracting for utility services

(sharing and costing of resources), treatment of confidential information (management and employees),

inter-company procurement and review of information (accounting, allocation and reporting). The policy

should also ensure that no financial risk from the unregulated activities accrues to the utility. Specifically,

sufficient safeguards should be put in place to protect utility ratepayers from any liability associated with

the unregulated activity.

Specific suggestions for inclusion in the code included the following:

i) The regulated company will not provide to the NRB any market-sensitive or confidentialinformation that would inhibit a competitive energy services market from functioning. Ifcustomers agree to the release of customer information, it should be provided to anyone for a pricebased on non-discriminatory access to the information.

ii) No regulated company personnel will state or imply that favoured treatment will be available tocustomers of the company as a result of using any service of an NRB.

iii) No regulated company personnel will preferentially direct customers seeking competitively offeredservices to an NRB.

iv) The regulated company will formally advise all employees of expected conduct related to theseprinciples and it will undertake to perform periodic audits of the relationships to ensure compliancewith these principles.

v) Complaints by non-affiliated parties about the application of these principles, or any alleged breachthereof, will be brought to the immediate attention of the senior management of the regulatedcompany and subsequently a report of the complaints, and action taken, will be filed with theCommission.

vi) The financing of the utility and NRB will be accounted for entirely separately with the financingcosts reflecting the risk profile of each entity.

vii) NRBs will not be allowed to use the utility name as the primary identifier of the company, but canmake reference to the name of its parent company on letter head, advertisements, etc.

18

In those cases where retail customers have direct market access to the commodity, the utility's code of

conduct will also include the following provision.

viii) The regulated company will treat all requests for distribution system access for the purpose ofdirect commodity marketing equitably and according to the requirements approved for directcommodity marketing in British Columbia.

Several parties had comments with respect to the code of conduct. PNG stated that the relationship

between utilities and NRBs should be governed by a set of rules which ensure that there is no cross-

subsidization between the utility and the NRB and that there is no unfair competition. However, PNG

stated that these rules should not preclude the NRB from offering a complete menu of energy solution

services.

BC Gas stated that the code of conduct must outline the utility's relationship with its unregulated

businesses, including the transfer of information and the provision of resources, that it should ensure the

minimization of risks to ratepayers, and that it should ensure that no unfair advantages are created for the

NRB. However, BC Gas indicated that these rules may need modification during transition periods and

that the level of information sharing between the utility and the NRB should reflect specific circumstances.

Westcoast argued that concerns about cross-subsidization should be dealt with through cost allocation and

pre-determined transfer pricing guidelines. In addition, Westcoast argued that rules for affiliated NRBs

should not prohibit the affiliated NRB from offering a comprehensive package of services since, to do

otherwise, implies customers are precluded from the benefits of a bundled service.

HVCI expressed concern that the staff position paper contemplated each utility writing its own code of

conduct. HVCI appeared to be concerned that this would be done without Commission input and that each

utility would control what the code of conduct allowed. Enron suggested that the code of conduct should

be developed by a working group of all interested parties and that the Commission should set a deadline

for its development.

With respect to the first item in the suggested code of conduct, governing the flow of information, Kanelk

suggested that it be amended to state that the regulated company will provide confidential information to a

third party if requested to do so by the customer, without necessarily making the information available to

other third parties. In addition, Kanelk suggested that the utility be allowed to recover the costs of doing

so. Enron indicated that the code should include provisions which state that a regulated company should

not provide any market information to the NRB unless that information is made available on comparable

terms, in terms of price and timing, to other market participants. In contrast, WKP suggested that the code

of conduct should only include a statement as to the privacy of the customer information, a statement as to

19

who shall have access to the information, and the fee to be charged to affiliates or any other party

requesting such information.

With respect to the second item, that no regulated company personnel will state or imply that favoured

treatment will be given if a customer does business with a utility NRB, Enron argued that the code should

include a prohibition from condoning or acquiescing in any other person stating or implying that favoured

treatment will be available to customers of the regulated company as a result of the customer using any

service of, or conferring any benefit directly or indirectly on, an NRB. In addition, Enron stated that the

third item in the suggested code, that no regulated company personnel will preferentially direct customers

seeking competitively offered services to an NRB, should be modified to state that if a customer or

potential customer requests from the regulated company information about products or services offered by

an NRB or its competitors in downstream markets, the regulated company may provide such information,

including a directory of retailers of the product or service, but shall not promote any specific retailer in

preference to any other retailer.

Several parties suggested revisions with regard to the complaint procedure described in the staff position

paper. CACBC (B.C.) et al. stated that the code should make provision for periodic reviews with the

results forwarded automatically to the Commission. Enron suggested that the code of conduct must be

effective and enforceable and expressed doubt that Section 124(4) of the Utilities Commission Act, which

allows the Commission the power to impose a penalty of up to $10,000 for failure to comply with a

direction of the Commission made under the Act, contained the appropriate or sufficient penalty. Enron

suggested that, if the code of conduct were breached, an appropriate penalty would be the loss of use of

utility resources for some specified period of time. Enron also argued that the Commission must review

and rule on any complaints concerning violations of the code. BC Gas suggested that all complaints

should be forwarded to the Commission which will then forward such complaints to the appropriate utility

for resolution. BC Gas also argued that flexibility with respect to penalties for non-compliance with the

code was needed and that there should not be one penalty for all code violations.

As indicated earlier, Kanelk rejected the position that non-regulated businesses must be financed separately

from the utility since they believed this could result in a sub-optimal corporate structure which could

adversely affect a utility's ability to compete in the market. However, Enron suggested that the code be

expanded to prohibit cross-guarantees or any other form of financial assistance whatsoever being provided

directly or indirectly by a utility to its NRB

Significant discussion revolved around the use of the utility name by NRBs. All utilities argued that the

right to use the utility name belonged to the shareholders of the utility who had the right to use it as they

wished. WKP stated that the value of the name arose from the goodwill with which the company was

regarded. As customers do not pay for goodwill in rates, WKP argued that the value of the name accrued

20

solely to shareholders. Westcoast provided a similar argument. In addition, Westcoast maintained that

name recognition was not an unfair advantage.

CACBC (B.C.) et al. agreed that NRBs should be allowed to use the utility name since they viewed this as

providing information which customers would value. However, they maintained that the NRB should pay

for the privilege since the goodwill associated with the name belonged to the utility. If the NRB did not

pay for the use of the name, they maintained that this would amount to transferring a valuable asset to the

NRB without any compensation. They suggested that independent evaluations be done to establish the

value of any particular utility name.

HVCI took a similar position, arguing that the goodwill associated with the use of the utility name arose

from items for which ratepayers, through the utility, had paid, including institutional advertising and

charitable contributions. HVCI characterized the use of the utility name as a soft but effective cross-over

benefit which is inconsistent with the spirit of fair competition. Further, they argued that if the utility were

allowed to charge the NRB for the use of the name, the name should be made available to anyone who

wished to purchase it.

MCABC also argued that NRBs should not be allowed to use the utility name. They argued that assets,

acquired under regulation, are not the exclusive property of the company and shareholders but the shared

assets of both the company and the broader shareholders, the rate-paying public. In particular, they

argued that the name was an asset of the utility and that the assets of the utility belonged to ratepayers since

the assets had been paid for through rates. Further, they argued that the fact that NRBs wanted to use the

utility name implied that NRB participation is not viable without it.

With respect to the last item in the proposed code of conduct, that the regulated company will treat all

requests for distribution system access for the purpose of direct commodity marketing equitably and

according to the requirements approved for direct commodity marketing in B.C., Enron argued that

'equitably' should be defined as follows:

1. A utility must apply any tariff provision relating to utility service in the same manner to the same orsimilarly situated persons if there is discretion in the application of the provision.

2. A utility must strictly enforce a tariff provision for which there is no discretion in the application ofthe provision.

3. A utility may not, through a tariff provision or otherwise, give its marketing affiliates or customersof affiliates, preference over non-affiliated companies or customers in matters related to utilityservice including, but not limited to, scheduling balancing metering, storage, standby service, orcurtailment policy.

4. A utility must process all similar requests for utility (service) in the same manner and within thesame time period.

21

In addition to comments on the items in the proposed code of conduct, some parties suggested certain

additions. CACBC (B.C.) et al. suggested that the code provide more specific guidance. For example,

they argued that the code should include a prohibition of routine movements of personnel between utilities

and NRBs by way of transfers or promotions. In addition, Enron stated that the code should require

separation of the operating personnel of the NRB from the operating personnel of the utility to the

maximum extent possible.

4 . 6 Other Issues

Certain parties, such as Novagas Clearinghouse Ltd., stated that the commodity function should be

removed from the utility since provision of the commodity is not a natural monopoly.

5 . 0 COMMISSION GUIDELINES WITH RESPECT TO UTILITYOR NRB PARTICIPATION IN DOWNSTREAM RETAIL MARKETS

5 . 1 Use of Utility Assets and Services in the Downstream Retail Market

5.1.1 Jurisdiction

Based on the submissions received as well as the legal opinion sought by staff, the Commission

understands its jurisdiction with respect to the use of utility assets and services to provide unregulated

goods and services to be as follows.

The Commission does not have the power to control the activities or to determine what services an NRB

will provide if the NRB is a self-financing, stand-alone, arm's length affiliate using no resources of the

utility.

The Commission has the jurisdiction to regulate the relationship between a public utility and an affiliated

NRB to the extent that the relationship affects ratepayers. The Commission may implement a transfer

pricing policy to regulate the interface between the utility and the NRB or may prohibit a utility from

providing an NRB with any utility assets and services if, in the Commission's judgment, this is required

to protect ratepayers.

The Commission has the jurisdiction to prohibit a public utility from participating in retail markets

downstream of the meter if prohibition is the only reasonable and effective means by which the

Commission can mitigate or alleviate any negative effects on ratepayers. In this case, the parent

corporation of the utility may still decide to create a subsidiary NRB to participate in the retail market

downstream of the meter. Alternatively, the Commission may implement a transfer pricing policy to

22

regulate the interface between the regulated and unregulated activities of the utility if in the Commission's

opinion this provides ratepayers with sufficient protection.

The Commission supports the general position of staff that determinations regarding the extent and manner

in which utility assets and services may be used to provide goods and services to the downstream retail

market should be made on a basis which takes into account individual circumstances. However, it is clear

from the submissions received and the legal opinion that certain changes to the specific objectives, criteria

and principles initially proposed by staff are needed. The objectives, criteria and principles which the

Commission intends to use to guide its determinations regarding the extent to which utility assets and

services may be used to provide goods and services to the downstream retail market are outlined below.

5.1.2 Objectives

Based on the information received, it is clear that the Commission has jurisdiction to consider the first two

objectives given in the staff position paper when considering the extent to which utility assets and services

may be used to provide goods and services to the downstream retail market. Conversely, the Commission

finds that it has no jurisdiction to consider the impacts of the use of utility assets and services, either

directly or through NRBs, on the retail market downstream of the meter. Accordingly, the fourth staff

objective, that customer choice should be maximized, and the additional objective proposed by Enron, that

robust competition in downstream markets should be preserved and enhanced, are beyond the

responsibilities of the Commission in making its determinations.

With respect to the third objective identified by staff, that the most efficient allocation of goods and

resources should be sought, the Commission believes that this forms a proper part of its consideration, but

only to the extent that ratepayers are affected. Accordingly, the Commission believes that it may consider

whether a proposal would enhance or reduce the possibility of stranded utility assets, or otherwise increase

the economic efficiency with which utility assets are used for the benefit of ratepayers, but may not

consider the implications for economic efficiency with respect to the larger market. The Commission

accepts the concern voiced by some parties that a precise measurement of economic efficiency is not

possible, particularly when considered from a societal perspective, but expects that it is possible to

determine directionally whether a particular proposal enhances or reduces the likelihood of stranded costs

or otherwise provides benefits to ratepayers.

Accordingly, the objectives which will guide the Commission's determinations with respect to utility and

NRB participation in the retail market downstream of the meter are as follows.

23

Figure 6: Commission Objectives

There must be no subsidy of unregulated business activities, whether undertaken bythe utility or its NRB, by utility ratepayers.

The risks associated with participation in the unregulated market must be borneentirely by the unregulated business activity, that is the risks must have no impact onutility ratepayers.

The most economically efficient allocation of goods and resources for ratepayersshould be sought.

In addition, the Commission agrees with staff that greater achievement of one objective may require a

lesser achievement of another objective so that trade-offs may be required. The Commission will be the

sole arbiter of how the trade-off between objectives should be made in determining the extent and manner

in which utility services and assets may be used to participate in the retail market downstream of the utility

meter.

5.1.3 Criteria

With regard to the six criteria proposed by staff, the Commission has concluded that they should be

revised as follows.

i) Does a natural monopoly currently exist for the good or service?

ii) If the good or service is not a natural monopoly, can the utility ratepayer be sufficiently protectedthrough a transfer pricing policy mechanism if either a division of the utility or a related-NRBoffers the good or service?

iii) Will the use of utility assets or services in the provision of the good or service reduce the risk ofutility assets being stranded to the detriment of ratepayers or otherwise provide benefits toratepayers?

In coming to the conclusion that staff criteria three, five and six should not form a basis for its

determinations, the Commission finds that it has jurisdiction to consider the impacts, either positive or

negative, of the use of utility assets or services in the provision of goods to the downstream retail market,

only with respect to utility ratepayers. If the new service is to be provided within the utility, the

Commission will consider the appropriateness of this service within the mandate of the public utility.

24

5.1.4 Principles

Based on its analysis of the submissions, the Commission determines that principle six, that in all cases

the Commission should consider the long-term effects on the markets of utility or related-NRB provision

of unregulated goods and services, falls outside of its jurisdiction. Similarly, the Commission accepts that

the principles must be revised to exclude references to considerations of customer choice.

Accordingly, the Commission accepts that the following principles should govern the choice of corporate

structure.

i) If a natural monopoly exists for the good or service, it should be provided as a regulated tariff item(Corporate Structure 1 in Figure 4).

ii) Utility participation in the unregulated downstream market by completely stand-alone NRBs usingno utility resources is the preferred option since it provides the maximum protection to utilityratepayers (Corporate Structure 4 in Figure 4). Variations from this option should be undertakenonly when it can be shown that this option would result in substantial stranded costs for the utilityand/or that a transfer pricing policy mechanism will act to provide sufficient protection forratepayers.

iii) The onus should always be on the utility to prove that the benefits associated with use of utilityresources are sufficient to warrant the changed structure and that the transfer pricing policymechanism will provide sufficient protection to ratepayers.

iv) If the Commission decides to allow the use of utility resources in the provision of the unregulatedgood or service, the preferred option is through a related-NRB (Corporate Structure 3 in Figure 4).Direct participation by the utility in the provision of an unregulated good or service should beallowed only when the costs associated with forcing the provision through the related-NRBstructure would significantly offset the benefits associated with the use of the utility's resourcesand it can be shown that a transfer pricing policy mechanism will provide sufficient protection forratepayers (Corporate Structure 2 in Figure 4).

v) Utilities and their related-NRBs will be encouraged to move unregulated products which use utilityresources into stand-alone NRBs as soon as market conditions warrant (Corporate Structure 4 inFigure 4). When a utility-provided product is moved to an NRB, the NRB will be required to payfair market value to the utility for the assets, including goodwill, associated with the product. Inaddition, utilities will be required to provide periodic proof that the benefits associated with the useof utility services continue to exist and that ratepayers continue to be sufficiently protected. TheCommission will make directions to prohibit the use of utility assets and services in the provisionof goods and services downstream of the retail market at any time that it finds it in the interests ofratepayers to do so.

5 . 2 Transfer Pricing Policy

As indicated above, the Commission's jurisdiction with respect to the extent to which utility assets and

services can be used to provide goods and services in the downstream retail market is centred on the

protection of ratepayers. Accordingly, the Commission is convinced that any transfer pricing policy must

ensure that ratepayers are kept harmless from any excursion by the utility, either directly or indirectly, into

the downstream retail market.

25

The Commission has concluded that the four components of a transfer pricing policy outlined in the staff

position paper are essential. In addition, the Commission agrees with groups such as MCABC that the

transfer pricing policy should include a requirement for periodic reviews of transactions between a utility

and its NRBs.

The Commission does not agree with parties, such as WKP, who argued that the price at which utility

assets or services are charged to the NRB should reflect the incremental cost of provision only. These

services have value and the NRB should expect to pay for that value. To do otherwise would mean that all

the benefits of shared services accrues to the NRB. Accordingly, the Commission concludes that the

provision in the staff paper with respect to pricing of assets and services is appropriate.

Generally, costing should recover the fully allocated cost or the incremental cost, whichever is higher.

This will ensure that ratepayers will benefit or are not harmed by the transaction. Where the incremental

costs are lower than the fully allocated cost, ratepayers should receive a value by pricing above the fully

allocated cost towards a market price for the service. In this latter instances, the Commission will need to

consider if such services should be provided to all competitors or to the NRB exclusively.

The Commission is not convinced by the argument that the specific components of the transfer pricing

policy should be established on an NRB-specific basis to reflect individual circumstances rather than as a

blanket policy designed to apply in all circumstances. Although the Commission accepts that there may be

provisions required for a gas utility that may not be required for an electricity utility, or vice versa, the

Commission will be reluctant to approve any transfer pricing policy which deviates significantly from that

which the Commission believes provides the most protection to ratepayers. In all cases, the burden will lie

with the utility to prove that deviations are appropriate.

Accordingly, the Commission concludes that a utility's transfer pricing policy should ensure the following:

i) The operating costs of non-regulated activities are not reflected in the utility's cost of service.

ii) The costs of developing new business ventures are charged to and recovered from the NRB.

iii) The accounting costs are transparent and will normally fully recover for all services, includingoverhead, space, employee benefits, inconvenience, and a profit margin where appropriate. If theservice provided by the utility to the related-NRB could also be obtained from an independentsupplier, the price paid by the related-NRB to the utility should be no less than the competitivemarket price and will never be below the incremental cost.

iv) The financial costs of each business are borne by the business. In the exceptional case where theutility provides guarantees, it must be given financial compensation.

v) Utilities will be required to file periodic reports which demonstrate that they are adhering to thetransfer pricing policy. The form and timing of the report will be determined by the Commission.

26

The Commission will require utilities to bring forward for approval proposed transfer pricing policies at

the time they bring forward any application to use utility assets or services in the provision of unregulated

goods and services in the downstream retail market.

5 . 3 The Code of Conduct

In order to protect ratepayers, the Commission will require each utility to bring forward for approval a

code of conduct for the relationship between the utility and its NRBs or the utility and any division within

the utility which offers unregulated goods or services, at the time the utility brings forward any application

to use utility assets or services in the provision of unregulated goods and services.

As with the transfer pricing policy, the Commission is convinced that any code of conduct must ensure

that ratepayers are kept harmless from any excursion by the utility, either directly or indirectly, in the

downstream retail market. Accordingly, the Commission generally does not accept the argument that the

code of conduct should be modified during transition periods and that the level of information sharing

between the utility and the NRB should reflect specific circumstances. Although the Commission can

envision some circumstances in which such a relaxation of the code might be possible without jeopardizing

ratepayers, in these circumstances, the burden of proof that such exceptions are justified will lie with the

utility. Further, the justifications must lie within the Commission's jurisdiction to consider. In the

absence of sufficient evidence by the utility, no relaxation of the code will be allowed.

Many suggestions were received with respect to the specific elements which should be included in the code

of conduct. Much of this debate centred around the use of the utility name by NRBs. The Commission is

concerned that the use of the utility name by related-NRBs could interfere with the Commission's

responsibility to protect ratepayers. The Commission will likely have to rule on this matter on a case by

case basis considering the related-NRB function, the potential impact on ratepayers (including confusion

between regulated and non-regulated services) and the services provided by the utility at rates to be

determined by the Commission.

Based on all the submissions provided, the Commission determines that the code of conduct principles

contained in the staff position paper should be modified as follows:

i) The regulated company will not provide to the NRB any market-sensitive or confidentialinformation that would inhibit a competitive energy services market from functioning. Ifcustomers agree to a release of customer information to the NRB, it should be provided to othermarket participants under the same terms and conditions and for the same price. Should anindividual customer make a specific request to have information released to a particular third party,it will be released to that party only. The utility will be able to recover from the customer the costsassociated with the provision of this information.

27

ii) No regulated company personnel will state or imply that favoured treatment will be available tocustomers of the company as a result of using any service of an NRB. In addition, no regulatedcompany personnel will condone or acquiesce in any other person stating or implying that favouredtreatment will be available to customers of the company as a result of using any service of an NRB.

iii) No regulated company personnel will preferentially direct customers seeking competitively offeredservices to an NRB. If a customer, or potential customer, requests from the regulated companyinformation about products or services offered by an NRB or its competitors in downstreammarkets, the regulated company may provide such information, including a directory of retailers ofthe product or service, but shall not promote any specific retailer in preference to any other retailer.

iv) The regulated company will formally advise all employees of expected conduct related to theseprinciples and it will undertake to perform periodic audits of the relationships to ensure compliancewith these principles. These audits will be performed no less than once a calendar year and filedwith the Commission.

v) Complaints by non-affiliated parties about the application of these principles, or any alleged breachthereof, will be brought to the immediate attention of the senior management of the regulatedcompany and subsequently a report of the complaints, and action taken, will be filed with theCommission. The report will be filed with the Commission within one month of the complaintbeing made.

vi) The financing of the utility and NRB will be accounted for entirely separately with the financingcosts reflecting the risk profile of each entity. No cross-guarantees or any form of financialassistance whatsoever should be provided directly or indirectly by a utility to its NRB withoutapproval of the Commission.

vii) Use of the utility name by a related-NRB will require approval by the Commission to ensure thatits use will not interfere with the Commission's ability to protect ratepayers.

In those cases where retail customers have direct market access to the commodity, the utility's code of

conduct will also include the following provision.

viii) The regulated company will treat all requests for distribution system access for the purpose ofdirect commodity marketing equitably and according to the requirements approved for directcommodity marketing in British Columbia.

5 . 4 Other Issues

At this time, the Commission does not intend to address the issue of whether the commodity function

should be removed from the utility. Nothing contained in this paper should be interpreted to imply that the

commodity function should be removed.

With respect to the request by MCABC to nullify the 1988 agreement between Inland Natural Gas and its

successors and MCABC, regarding appliance sales, the Commission will pursue this matter separately

from this policy paper.

APPENDIX 1Page 1 of 1

List of Initial Responses to Commission Staff Paper

1. Association for the Advancement of Sustainable Energy Policy2. BC Gas Utility Ltd.3. British Columbia Hydro and Power Authority4. British Columbia Public Interest Advocacy Centre5. Brian Donnelly6. Building Owners and Managers Association7.. City of New Westminster8. Consulting Engineers of British Columbia9. Enron Capital and Trade Resources Canada Corp.10. Heating, Ventilating and Cooling Association of B.C.11. International Brotherhood of Electrical Workers - Local 21312. Kanelk Transmission Company Limited13. Mechanical Contractors Association of B.C.14. Northwest Pacific Energy Marketing Inc.15. Novagas Clearinghouse Ltd.16. Pacific Northern Gas Ltd.17. Pan Alberta Gas18. Radian Mechanical Inc.19. Residential Hot Water Heating Association of B.C.20. United Association of Journeymen and Apprentices of the Plumbing and Pipefitting

Industry of the U.S. and Canada, Local Union 17021. West Kootenay Power Ltd.22. Westcoast Energy23. Westcoast Seismic Protections Co. Ltd.24. Willis Energy Service

List of Reply Comments to Initial Responses

1. BC Gas Utility Ltd.2. British Columbia Hydro and Power Authority3. British Columbia Public Interest Advocacy Centre4. Enron Capital and Trade Resources Canada Corp.5. Heating, Ventilating and Cooling Association of B.C.6. West Kootenay Power Ltd.

FortisBC Energy Inc, General Terms and ConditionsSection 12A

Order No.: G-28-11 Issued By: Diane Roy, Director, Regulatory Affairs

Effective Date: March 1, 2011

BCUC Secretary: Original signed by E.M. Hamilton Original Page 12A-1

12A. Alternative Energy Extensions

12A.1 System Expansion - FortisBC Energy will make extensions to the FortisBC EnergySystem using technology that produces alternative energy, in accordance with the provisions of this section. The alternative energy extensions include geo-exchange, solar-thermal and district energy systems which are described below:

Geo-exchange systems, also referred to as geo-thermal systems, earth exchange systems or ground and water source heat pumps, utilize the latent heat energy contained in near surface layers of the earth, ground water and surface water. A subsurface piping system contains a liquid that absorbs heat from the surrounding material and delivers it to a central heat exchanger. High efficiency heat pumps convert this latent energy into hot water or steam contained in a separate piping system that can then deliver the heat energy to where it is required for space heating and hot water uses. Centralized equipment is usually contained within specifically designed mechanical room that serves the entire development. The heat exchanger is reversed to provide space cooling, removing heat from the building(s) and returning it to the subsurface substrate.

Solar-thermal water heating systems, also called solar hybrid water heating systems, are a system of solar collection tubes and piping capture heat energy from the suns rays and deliver it to a central heat exchanger, where it is converted to domestic hot water anddistributed in a manner similar to that described above for geo-exchange systems. The solar collection tubes are located outside the building or buildings, typically on the roof, while centralized equipment is again housed in a specifically designed mechanical room.

District energy systems employ a range of energy technologies and sources to deliver piped heating (steam or hot water) and/or cooling (cool water) to multiple buildings and customers within a neighbourhood from a central plant location or locations.

12A.2 Ownership - All alternative energy extensions will remain the property of FortisBC Energy.

12A.3 Cost of Service Model - All applications by Customers for service using an alternative energy extension will be subject to review using a cost of service model. The cost of service model will determine the rate that a customer will pay for the service associated with the alternative energy extension. Service will be provided under the terms and conditions of the Service Agreement between FortisBC Energy and the Customer.

FortisBC Energy Inc, General Terms and ConditionsSection 12A

Order No.: G-28-11 Issued By: Diane Roy, Director, Regulatory Affairs

Effective Date: March 1, 2011

BCUC Secretary: Original signed by E.M. Hamilton Original Page 12A-2

12A.4 Projected Energy Consumption/Number of Customers - The projected energy consumption and number of customers to be used in the cost of service model will be determined by FortisBC Energy by

(a) estimating the number of Customers to be served by the alternative energy extension;

(b) if applicable, establishing consumption estimates for each Customer; and

(c) projecting when the Customer will be connected to the alternative energy extension.

If applicable, the projection will take into consideration the estimated number and type of thermal appliances used and the effect variations in weather conditions throughout the applicable Service Area have on consumption. All Customers expected to connect to the alternative energy extension will be considered in the cost of service model.

12A.5 Costs - The total costs to be used in the cost of service model include, without limitation

(a) the full labour, material, and other costs necessary to serve the new Customersless any contributions in aid of construction by the Customers or third parties, grants, tax credits, or non-financial factors offsetting the full costs that are deemed to be acceptable by the British Columbia Utilities Commission;

(b) the appropriate allocation of FortisBC Energy's overheads associated with the construction of the alternative energy extension;

(c) depreciation expense related to the capital equipment associated with the alternative energy extension; and

(d) the incremental operating and maintenance expenses necessary to serve the Customers.

In addition to the costs identified, the cost of service model will include applicable taxes and the appropriate return on investment as approved by the British Columbia Utilities Commission.

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2500 . FOUR BENT ALL CENTRE105S DUNSMUIR STREETP.o. BOX 49190VANCOUV. B.C.CAADV7 IS8

Boughton Peterson Yang AndersonBAIS &. SQUC:ITRSTlOl- MAl.A .

B.C. UTILITIES COMMISSION

RECEIVED & ACKNOWLmGEO

MA i 2 1991

TE (60) 681-69fi (60) 683-5317

laers~bpya.comll~l'.Y ..i-N Oi: Gordon A. Fulton

45026.6_ fOR :. i nr ¡: "1:,,-,,, ni:~"ONSE..._ FOR RESOURCE ROOM......INFO. TO BE FILEO...___

fl NO:

March 10, 1997

B.C. Utilties Commsion6th Floor900 Howe StreetVancouver. B.C.V6Z 2N3

Attntion: Ms. Deborah Emes. Mana2er. Stratec Serce

Dea Ms. Emes:

Re: Re Maets Down of the Met

You have requted our opinon on the Comiion's jursdicton with rest to partciption by

a public utility or an affia non.relate busines ("NRft) in th unrgute reta maretsdownstr of th mete ("RMM"). Mote spifcaly, you have asked whether the Commsioncan preven a pUblic utiity or an NR from pacipatg in RMM. You have also asked whethrthe Commsion ca preven a l'ublic utiity frm providi service to an NR or whether thCommion is limite to looki at cross-chaes. Finaly, you have reested our opinion as towhether th ratepayers or sharold own a public utlit's na.

Badgrouru

Th Commission is consid th ise of paipaon by public utiiti an NRs in RMM.The Commission is al consideri gudelins or term and condtins if public utilities or NRsparticipate in RMM.

The cru of tb issue is whether public uù1cs or NRs shold be aUowed to provide servce andprodts "downwsir" of the mete. Histncay. puli utlities foc on make up-strof th meter. naly prodion an delivery of gas or elecity. Sece an proucts downM

str of the mete ax provi by contrs an businse in a comptitive mat.pla.Pubüc utiities have not tronally be involved in RMM.

Th Commion st prepar an distute a position papr enttled ftReta MaetsDowntr of th Utity Mete". da Deber 4, 1996 (tb "Sta Paper") an intedcommeiu from interete panies. A nube of paripam mae sumiions ~ reply

VANCOUV . HONG KONG . TAI . SHGH

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submissions to the COnussion. Some rase concern about the Commion's jursdction toregulate partcipation by public utilities and NRs in RMDM.

In arrving at our opinon. we have considered the Uiiliies Commssion Ace, S.B.C. 1980. c. 60and amendments thereto (the "Act"), certn texts on public utility regulation, and th relevantcaslaw. In addition, we have considred th submissions made by varous pares in respons to

the Staff Paper.

Summ of Optnion

The followin is a summa of our opinon:

1. The Commsion doe not have the juricton to diecy regulate an NR uness th NRBis itslf a public utility. a common caer, or a common processor.

2. The Commsion has th jurcton to relate th relato.ihip beween a public utlity andan affiat NR to the extent that the relationhip afects raEmavers. For exaple, theCommion ha the juridicton to ense th an NR is not "subsided" by a public utilityto the detrent of rateyers.

The Commion doe not, however, have th jursdcnon to regulat th relationshipbetwee a public utilty and an NR so as to ene th relationsp doe not afft th

comptive retail maket down-str of th mete. The Commission's juriicton is

limte to consideration of th effects of th relatons on raayers.

3.

4. The Commion ha th juricton to reguate RMM activities by a pulic utiity i butonly to th extent tht such activities affect rateyer. Simrly, th Commsion ha thejursdiction to prohibit a public utity from parcipati in RMM if prohiòition is the onlyreonale an effective mea by which th Commion ca mitigate or aleviare anynegave effts on rateayers.

S. Rapayer do no own a public utility's corrate nae. Th corprate nae is goodwilwhich is own by the compan. Th shaholde have a right to sha in dl assets of acompany, inudg th coiprate na, if the compay is dilved.

VANCOUV . HONG ICNG . TAJ . SHANGH

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Discusion:

The Commsion's Juridictuin - Legal Priciples

The questions on which we were aske to express an opiion ar questions regarding theCommion's jursdiction an, as such, it is helpful to sum some of the key priciplesdescribed in the rent B.C. Cour of Appeal decision in British Coluia Hydro & PowerAuthoriiy v. British Columbia (Utilities Commission) (1996), 20 B.C.L.R. (3d) 106 (C.A.) (the"B.C. Hydro Decision"):

1. The stang point for an anysis of the Commission's jurisiction is the Act;

2. The Act is detailed legislaon which amply delite the Commsion's juriiction by

express term. Thre is no need to imply teon; an

3. The speifc proviions of th Act conferrng judiction on th Commission should be

exaed in light of th U,mpse of the Act, th rean for.th Commssion's exis. the

are of expese of th commssioners, an the na of the problem before thCommission. Th purse of the Act an the rean for th Commission's exitenc isdefied by lookig at the historical purose of th Act an rean for the Commision'sexitenc.

Commsin's JuritUn tI Diectl., Regue NRBs

Th Comssion clealy ha jurdiction over a "public utility". which is define in s. i of the Actto me:

~ ...a persn. .or hi lessee, tIstc, reiver or liquidator, who owns or opera in thePrvin, equipmen or facilties for

(a) th productn, generation, storage, trssn, sae, delivery or fuhiof electity, na gas, ste or any oth agen for the prodtion of

tight, het, cold or power to or for ui public or a coipraüon forcompenstion, or

(b) th conveyan or ttsmission of inormtion, mesages or communcationsby guded or ungded elecmagnti waves, inludin syste of cale,

microwave. optica fire or raocmmuncations wher that service isoffer to di public for compensation,

but upublic uti" doe not inlud

(c) a muncipaity or regiona distrt in repe of seices fumi by thmuncq, or regional distr widi its own boes.

(d) a persn not .otherwise a public utit wh. f\hes the servce orcommodty only to hielf, hi emloyee or tenats, where the service orcommodit is not resold to or us by oth,

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(e) a person not othis a public utlity who is engaged in th petroleuminust or in the wellhd prouction of oil, nanial gas or othr naalpeoleum substa, or

(0 a person not otherwis a public utity who is engaged in the production of

a geotheral resour, as defi in the Geotherml Resources Act. "

If an NR is itself a public utilty as defi in the Act. the Commssion bas jurdiction over theNRB. The Commission alo ha jurisiction over common procesors and caers uner Part 5of the Act. Cenain provisions of th Act deal with muncipalities and regiona distrcts.

Nowhere does th Act speificaly confer on the Commssion the jurction to regulae NRBs orany othr person, which is not itslf a public utiity. In OUT opinion, th Commission doe not haveme jurisdiction to diry regulate NR th are not tblves pulic utities, common caers,or common procson.

Commission's Jurdictin to Regulae the Relinship Betweeu a Publi Utiit an an NRB

Our opinon tht the Commsion does not have th jursdicon to directly regulate an NRB this not itslf a public utity doe not prelud th Commssion's jurisiction to regulate i:

relauonship beteen a public utiity an an NR.

Boron submits tht the Commsion ha the jursdon to regulate al asts of th relationshipbetween a public utility an an NR. In su. Ei submits the basis for th juriicton is

th genera supelVisory powers undr s. 28 of the Act an the "conttaift relationsip betwee

a public utiity an an NRB. Boon is al cleay of th view tht the Commion has thejuriiction to reguate the relationsmp to prolC competition in RMM.

BC Gas agrees me Couiion ba the juriction to regulate th reationsp beeen a publicutiity an an afiate NR, but only in so fa as is ncsa to enur rateayers ar notnegatvely afecte by th relaons. In other word, th Commsion ba th juricton toenur th is no "cross-subsiiztiontl. However, BC Gas submits th Commision does not bave

th jurcton to preent th flow of bets from th public utity to th NR, provide this no crss-subsiiztion. In B.C. Gas' view, competion is a mattr with th jurdiction of

othr regutory agencies.

B.C. Hydro ta the view tht s. 28 is not so broad a provision as to confer blat authrity onthe .Commision to reat all utiity activiti. B.C. Hydr cite the Cour of Appel decision in

B.C. Hydro. supra. B.C. Hydr is of th view th Commsion does not have th juridiction to

reulate competion in RMM.

Other inte par, such as th inden heag, coolin, gas and ventii(i1'g contrtorsar clealy of th view th Common ha the judicton to reguat the relationsp beccnNRs an public utiliti to en thre is no cross-subsidition and unai competitive

advantages.

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Section 28 of th Act provides:

"(1) Th commsion ha general supervion of al public utilities and may maorders abot equipment, applian, saety device, cxtenson of work or

syste, Íilin of rate schedules, report an othr matters it considers

ne or advisable for the safety, convenenc or service of the public orfor th proper cain Out of th Act or of a contct, chr or fncmseinvolvin use of public propert or ri¡h.

(2) Subject to. th Act, th commsion may mae regutins requir a public utiityto condt its oprations in a way th doe not iinnp~ssarily interfere with, or causnnnM.llllJry dae or innveneoc to, the pulic"

Section 28 is ofren referd to as th Commssion's genera suprvisry power over public utties.It is worded rater broy but. in light of th B. C. Hydro decision. it mus be rea in th contxtof the Act as a whole an the hitorical puipse of the Commion.

At P 111 of th B. C. Hydro Deision, th Cou of Appel šu th purse of thCommision:

"In ths light th Uties Act is a currnt exple of th mc adopted ùi NortAmri Ílly in th Unite Sta. tg açhicve a balanc in the DubHc interestbetween monoooly. where monooolv is acte as nesa. an protetion to ui

conser provied bv comDctition. Th grt of monoly thug certficaon of

public convenen an nesity acmpaned by th conevc burn on thmonopoly of providig servce at approved ra to all with th ar from which

comoetiöon was excluded." (emphais add)

In itS submion, &rn refer to th Coun of appe deision in B.C. Ga Utili Ltd. v. B.C.Hydro er åi. (May 3t. 1995) CA011981 (B.C.C.A.) (-th BC Ga Deision"). In tht deision,

th Commio amend th 1agc of an agent beee B.C. Ga an B.C. Hydr to giveeffec to th intent of th panes in light of ce ched cir. The Coun cotson a nu of ocions about th "broa power" of th Commion to re¡u B.C. Ga anB.C. Hydro.

At page 10 of th BC Ga Deision. th Cour of Ap stre:

"Th reguro power of lh Commsion in th ma is neessaily bro inolder tbt it be able to disrge its du to eo tht th moiily unsuner its suon oprate acrdg to th be ii of th coDS pub.un es1i priples of utity reon ..

Th "mattrs" tefme to by th Cour of Ap rela to seti 30, 31, 36. 641) an (2),65(1), 70(1) an (2). 103(1) an li4(l). Tb Cour of Appe in th Be Ga Decision wasspfiçay de with th Commsion's jution to rc cx contts beeen puli

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utilties where th contrcts diretly affecte the curent raes paid by ratepayers. The Be GaDecision did not specifcally dea wim the Commission's general supervsory powers under s. 28of the Act. Rathr, it dealt with numerous oth provisions of the Act. Finaly, the BC HydroDecision is more recent and, in our view i provides a naower ínerretation of the Commission'sgeneral jurdiction over pUblic utilities.

In both decisions, however, the Cour of Appel refers to "consers" or the "consumng public".In our opinion, "consumers" and th "consing public" mea consumers of the products and

services of a public utilty. More speifcally, consmers ar raayers. It follows th purposeof the Act and the Commission is to balance th right of th monopoly to reeive fair compenstionwith the nee to proteci ratepayers from the abuse of a public utiity's monopoly powers.

As a result and berig in mind the purse of the Commission, it is also our opinion tht section28 confers upon th Commission the jurdicton to regulate th relationsp between a public utiltyan an NR to th extent the relationship impacts rapayer. For examle, if th NRB uses theassets, syst or service of the public utility, rateayers ar effectively subsiding the NR and,as such, the Commission has th jurisdiction to regulate th cross-susidi%tion. It is furter our

opiiuon tht th Commion ba the juriiction to ens th the NRB's activities do not impose

additiona busins or finacia ri on the public utity.

It is importnt to emphaiz tht the Commion's junsdiction to regulate th relationship betweena public utity an an NR arses beuse the public utiit an its ratepayers are affecd by therelationsp. 11 Conuission, as a relt, ha th jursdcton over th public utity to regulateits activities to miimize or elite th effect on rateayer. Th Commision doc not, however,have th jurction to directly regu th NRB beus the relatonsp affects rateayers (unlessthe NRB is a public utiity). Of cours, the indect result is tht th Commission affects astsof me NRB's busines an operations by regulati di relationship betwee it and the publicuulity .

Competin ui RMM

The isse of protecting or fosterg comptition in unrguated makets is a more difficult ise.

Enn inbide a nuer of authonties in suport of its submision. Mos of th autorities arAmca sta tnòun decisions tht adopt FERC Order 497, whi is an Order regulti threlations betWee inrs pipelin an thir maketi afiate. In ea of the Americauthoriti, th Cour or trbun consider, amongt other fatol's, £he effect of the pipeline-affiiarelaonsp on othr non-af ma.We wis to ma two commen abot th America authoritis cite by Enn. First, neithFERC Order 497 nor any of the cour or trbun decisons dea wim seice or productsdown of the metr. Seond, America tribunals operate witb a different legilative anlegal frwork th the BCUC. In Briti Columbia, the Commsion must exerise its powers

under th Act with regar to th priiples set out in th BC Hydr Decison.

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Therefore. it is our view tht the American aumoriues cite by Enn are not determintive of thissue.

Enn also inluded a deision of the Manitoba Public Utilties Boar. Ordr No. 110196, dateNovember 4, 1996. In tht case, the Board considered guidelines for acceptable conduct betweenCentr Gas Mantoba Inc. an irs affliated companes in rest of, amongst oth thgs. markets

downtram of the metr. At p. 21 of the Decision, th Boar ordred Cent Gas to form aworkg commtt to consider a code of conduct. stating:

"Th purse of this code of conduct should be to ense tht Cent trars itsafliate as it would any thir party in order to allow for fair compensation for all

parcipan in the competitive elements of the nawra1 gas maret or relate

servce. .

At p. 23 of the Decision, the Board ordered the Code of Conduct beteen th utiity an its

affliates to include th following:

-Th sha servce mus not reslt in undue disadvane"to any competitors in themart. "

The Manitoba Puli Utiity Bord was obviously of the view it ha th juricton to consider ùi

effec of me relaonship between a public utilty an its atfuiate on umgued. competitivemarkets. Unforttely. the Boar did not specificaly state in its deision whic provision of itsAct confer su jursdiction on the Board.

We have reviewed th Mmiroba Public Utilities ACI. R.S.M- 1987, c. P280. as amend. Threis no provision of the Act th speifically confers juriiction on th Bo to reguarc or coiderthe effec of public utities or NRBs on compeutive ma. Setion 74 of th Act is simi to

s. 28 of th B.C. Ac. We reviewed caselaw in whic s. 74 was considere. None of th judciadeisions wer belpM to us in arriving at ou preset opinion. Nor were we able to find a

. discsion of ths iss in the authorities we reviewed. In Bonbrighl et al (1993) at 5S3. th

authors compa "regulation" an anu-lNst laws. In so doin, they se to difernt ben

the two form of reguon, stng th the "aims and motives" ar differnt. Finlly, we werealso unable to f'in a B.C. ca tht speifically dealt with th isse.

In our viw, an in light of th B.C. Hydr Decision. th quon as to tl Commssion'sjuriction to reat an-competitive practises in DOn-regute maet reui tb followianysis: .

Is there a spic statury provision in the Act whi confers juron on theCommsion to regula an-cmpeitivc practi in non-ie ma? Inanwer th question, it is importnt to kee in mi th purose of public utiitytribunal.

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We have concludd, afr consideri the purse of the Commion and the Act, tht thCommission's general survisory powers undr s. 28 do not confer jwisdiction on Ule Commionto regulate an-competitive practies by a public utity in RMM.

The only other provision of th Act tht might be applicable is s. 65 which srates tht a publicutility caot dema a rate for a service fu in th Prvinc tht is "unuly discriminatory" .

Again, s. 65 mus be interprete in light of tl purose of the Commission and th Act. In ourview, s. 6S confers on th Commssion the jurisdction to ensure tht a public utility doe notunduly disrimite as between rapayers so as to give an undly preferential rate to a speificbusiness, person, or ra class.

As was th ca with our consideraton of th Commion's jurdiction to regulate affliate ofpublic utilities, we cat find a speific provision of the Act tht confers on me Commion thjurisdiction to regulate anti-competitive behaviour by public utities or NRs in non-regulateRMM.

In our view, th histonca puipose of public utiity trbuna was to protet th ratepayer from thmaket power of th monopoly public utiity by sett price and conditions of seice. In fact,an as note in th B. C. Hydro Decision an th Staff Paper, monopolies were ofren acepte as

necessa. The inoduction of comptition in area such as gas mareting an sales is a rentdevelopment. Competition in production is also a rent development, partculaly electrity

production. Th Commision. lik many public utiity trbun, is grppling with ways of fostenngfair competition in makets tht Wci historiy considere pa of a "natural" monopoly, whieat the sa ti proteg th inre of rateayers. As note in th Staff Papr, th interet by

some public utties in RMM is itself a rent development.

In our view. RMM an comption in those in wer not hiorical conc of public utity

trbunas. 1ñefore, it is ou opinion th th Commion doe not have the jurisdiction underthe Act to regulate, or conside, the efts of publi utiity or NR l'arcipation on un-reguteRMM.

In arrving at our opinon, we ackowledge th it difers from th America aurhrities cite by

EnoD, an the Mantoba Public Utilities Board Decsion. Ou opinon also confct with th 1993B.C. Gas Furn Repai Plan Deision. However, we would note th following:

(a) For th rens cite above, the Amri autriti ar not determtive of thissu;

(b) There was no diion in th B.C. Ga Furce Reai Pla Deision about thsour of th Commion's jurction 10 regu or conside the effects of publicutity or NR parciptin in RMM. Fur, th B. C. Hydro Deion was~lead afte the B.C. Ga Fiiee Repai Plan Deision;

Th Matoa Pulic Utiiti Board did not consider th B. C. Hydro Deision in its

1996 Cenr Deision; aJ(c)

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(d) Ou opinon alo seem to be consistent with the submiions mad by parcipantswho parcipate in BeUe proceings on a rela basis.

Commsion's Juriditin to Regulae RMM

As note above, the Commsion ha jurisdicuon over public utilities, as defied in s. 1 of th Act.The extern of th Commssion's juriction is detrmin by the Act. be in min th purose

of the Act an public utilty trbun in genera.

In the Mantoba Public Utilties Boa Decision, Centr Ga referr to the decision of thManitoba Cour of Appeal in Grea Winnipeg Cablevision Limed v. Th Public Uiilis Board

an Mantoba Telephone System. (1979) 2 WW 822 (Man C.A.). In tht case, th Courtconsidere whedir the Mantoba Public Utities Board had the jurcuon to reguate the amountof rent chaged for coaxal cables by public utilities. Th Coun of Appe state at 87:

"It is common groun tht MTS is a public uulity within tb defition, with repet

to its telephone an telegrph seices.. .Jt does not necessary follow that eveiyngdone bv the MTS is suiec to th ~gulatorv suoervon of the boar. It is possiblefor an underg to be a public utir. as defme in th Act for some purses andnot for others." (emphais ad)

Th Mantoba Coun of Ap went on to consider t: speific provisions of th Act and concludth Act did not give th Boar the juction to ieguar coax cables.

Th deision is import for two reons. Fir. the eoun conclud a tnòun doc not have

jurdiction over every a pulic utty doc simly beaus it is a public utity as defi byth Act. Secnd. the Coun will look to th relevant sta to dere th scpe of th trun's

jurisdictin over a public utiity. In our view. the Matoba Coun of Ap deision is consisntwith th priiples en in tb B. C- Hydro Deision

Varous proviions of th Act give th Comiision juricton to rete sece. opeons.

prop, rates or syste of 8. public utility. "Seicell is defi in s. 1 of th Act to inlud:

"th use an acommodn provide. an a prot or coodty fushed, bya public utity an al in th plan, eqme, apartu. applia,prope an facilties emloyed by or in conntion with a public ut inprovidi servce or in fu a prouc or coty for th purse in whithe l'ublic utiity is enaged an for the us an acmmodtion of the public. ø

Th dcfintin of "seic-, "options". "propeny". an "syst- could be inred broadyto inlude RMM activities. However, th varou provisoo of the Ac mu be inrete inlight of th puse of the Conussion. naly the lroteon of th rateyer agains thmonopoly power of th utiity. Fu. the innton of th LegiIa whe th Act was enais imrt. As note above, it se unely di Legistue reonaly contmpla thparcipaon of public utlities in RMM when the Act cae ino foic in 1980. In ou opinon,

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it is far more likely the Legislatue had in mind the trtiona service, operations, propert ansystems of a public utiity, naely production an delivery of natu gas an electrcity. TIs viewis support by th dcfintion of public utilty in s. 1 which clealy focus on prodtion anddelivery. In lighi of the Cour of Appe deision in B. C. Hydro supra., we are of the view thCourt would probably apply a naow interetation to thes term.

Regardless, an for th reons state above, we are of th view th Commssion has the

jursdiction un s. 28 of the Act to ensure a pulic utility's parcipation in RMM does notaffect ratepayers. We ar also of th view th Commion could prohiòit a public utity fromparicipating in RMM ü the public utity's parcipation in RMM affec ratepayers andprohibition was th oñI reonable method to mitigate or alleviate the negative imacts onratepayers.

Is the Corporate NOJ of a Pulic Utili Owned by the Shteholdrr or the Riepayerr?

It se to be a setted priiple of law th th nae of a business form pan of the goowil of

the business. Gowil. in turn, is an asset of th busin whi is ownd by th ownrs of thebusiness. (Bugde v. Voisey (1955), 2 D.L.R. (2d) 427 (Nfld. T.D.) at 433). In the ca of a

coxporaüon, th shaeholders own a right to sh in th asts of the corpration upon disolution.

Most utiities with the juriction of th Commsion ar companes inoipratc pursuat to thCompanies Aci R.S.B.C. 1979 c. 59 as amened. Secon 2i(1) of the Companes Act spificaystate tht a coany has the ful lega cacity of a na pen. A company. therfore, hathe riht to own asts, inludin goowi an trdemaks. B.C. Hydro is inipora uner theHydro an Power Authority Act R.S.B.C. 1979 c. 188 as amend. Secon 12(e) an (g) of thtAct gives B.C. Hydo th right to own an disse of prort including, amongst otr ths,

rrademks.

In our opiIon, regute pUblic utiites in B.C. have th right to own goowil an their corpratenae unles thre is a speific legisative rue to th contm. Furcrore, the sholders ofthe public utiit own a sh of those assets, subjec to legition to th coni. We considereth provisions of th Compan Acr. th Utiities Commsion Act, and the B. C. Hydro an PowerAurity Act. Th ar no provisions in any of the th sra tht speifcay stte tht apublic utlity doe DOt own its goo'Yil an corprate na, nor ar th any provisions th affectth priiple th sJwholders own a right to sha in th goowil of a pulic utity upon

disoluton.

Thre is also some issu as to whethr th Commion ca reguat how a publi uti us itscorpora or busin nae. West Kotey Power refe to two deisions in its submision. Thfirst is th deion of th Supreme Cour of th State of Minta in Mtngasco v. MinesotaPublic Utilitis Commion (lun 13, 199). Th decision is al refer to by Ceoi Ga in thedeision of th Mato Pulic Utiiti Tnbu. In Minnegasco. the Cour held tht goowUl

is an ast of a utity which is not paid for by rateyen. Thfore, in th ca, th Connconcludd th tnòuna did not have th jurtion to im revenu to a public utity jf an

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affilte did not pay to us the company nae. Th secnd decision referrd to by Wes KootenayPower is th deision of the Californ Public Utilties Commission in Southern Edison Co.,

(1988), Cal. PUC. In tht case th Public Utiities Commssion concluded that goowil is not anasset which is paid for by the rateayers. Neither the Minngasco nor th Southern Edison Co.decision conclude tht goodwil is not propert of a public utilty.

The Matoba Public Utiities Boar concluded tht it did in fat have junsdction over thcorporate or buins na of a public utiity. However, the Boa went on to decide that it wouldnot rect th us of the public utity's na by affliate. In so deding, th Board considere

statutory provisions which ar simlar to setions 28 an 59 of th Utilies Commssion ACE.

Section 59 state:

59. (1) Excet for a disposition of its propert in th ordii coure ofbusin, a public utiity shal not, withut fit obtain thecommion's approval, dispose of or encumber th whole or par ofits prope. frhises, lices, peits, concessions, pnvileges or

rihts, or by any mea. direct or indit. merge. amlgamte orconslida in whole or in par its propert. frhi. lice.

perm, concions, privileges or ngh with those of anothrperson._ (2) Th commion may give its approval uner th seon subjec tocondtions an reiren considere nesa or deirale in thepublic interest. (emphais added)

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Section 59 confers upn th commion th juiition to contrl dipositions an encbraesof propert of a pulic utity. In our opinon. the propert refer to in s. 59 inudes goowilan any trde mak rits in a coi:rate nae. This is consisnt with th Manitoba Public

Utilities Tribuna decision.

Th te "dispse" is defi in the Interpreation Act. s. 29. as follows:

"dispose" me to trer by any metod an includes assign, give. sell, grt,chge, convey. beueth, deVÍ. leae, dives, teea an agr to do any of thesth;

Th defition suggets th more th a mer lice of the us of pro is need. Ther mustbe an ac "trfer" of a propri inret.

Th defition of _dill in rh Black's Law Dictional) is:

"Dis of To a1 or di owners of proper;. . .to pass into thecontl of somQOne els; to aleie, relish, par with or get nd.

of; to put out of th way; to fi with; to baai away.

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The re "encumber" is not defined in Blac's Law Dictona. Th caelaw we reviewed inwhich the (em ha been considered was not helpfu to us in rehig our opinon.

"Encumbrances" against prope inlude chges, liens, an mongages. It is questionable. in ourview. whefuer licencs are encbra again propert. A license is only a right to us propertfor a specific purpose in rerom for a licens fee and may be revoked at any tie. A breach of alicense subjects th par in breh to dages.

It is our view tht s. 59 of the Act is innded to prohibit a public utility from doing anythng withits propert, inluding goodwil, tht might put th prop outside of the jurisdiction of theCommission, or tht migh inerere with th Commission's abilty to protet ratepayers. Tb,a public utilty caot sell or asign its nae without Commission approval. A public utity

probably can, however, licenC it nae without Commsion approva.

Th then is our opinion. If we ca amplif mattr; in any way, plea feel free to contct us.

You very trly,

BOUGHTON PETEON YANG ANERON

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L:lGAS0.6\NinJtt

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