Exhibit No.

BRITISH COLUMBIA UTILITIES COMMISSION

Generic Cost of Capital ~ Stage 2

Written Evidence of

Corix Utilities Inc. Central Heat Distribution Limited

River District Energy Limited Partnership

10 July 2013

B2-17

markhudsGenerec Cost Capitol

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INDEX 1. Introduction .................................................................................................. 1 2. Structure of this Submission ...................................................................... 2 3. Key Concepts – Small Utility Perspective ................................................. 3

3.1 Small TES Utilities differ fundamentally from the benchmark utility ......... 3 3.2 Regulatory burden of setting capital structure and return on investment (debt and equity) is disproportionate to the relative size of the utility business. 4 3.3 Commission’s risk matrix should be simplified ......................................... 6 3.4 Certain aspects of the risk matrix approach should follow a generic approach ........................................................................................................... 9

4. Conclusion ................................................................................................. 10

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1. Introduction 1 This evidence is submitted on behalf of the following companies who operate utilities 2 within British Columbia: 3

• Corix Utilities Inc. and its related companies (“Corix”), 4 • Central Heat Distribution Limited (“Central Heat”), and 5 • River District Energy Limited Partnership (“River District”). 6

7 This evidence will refer to them collectively as the “Companies”. 8 9 The Companies provide Thermal Energy Services (“TES”) throughout British Columbia. 10 In most cases, the Companies’ TES projects are regulated as “public utilities” under the 11 Utilities Commission Act (“UCA”). In the case of Corix, some of its projects are not 12 regulated under the UCA. In all cases, these utilities are very small compared to 13 FortisBC Energy Inc. (“FEI”), which the Commission established as the benchmark utility 14 in the Generic Cost of Capital (“GCOC”) Stage 1 proceeding. 15 16 The Companies are collaborating in this proceeding to provide the Commission with a 17 small utility perspective on the cost of capital issues being reviewed in the GCOC Stage 18 2 proceeding. While these companies have significant differences in their operations – a 19 reflection of the diverse range in TES projects – they also share common perspectives 20 on the challenges facing small TES utilities. This submission focuses on those common 21 perspectives. 22 23 Corix participated in the GCOC Stage 1 proceeding and filed evidence on the issues 24 affecting the cost of capital for a small utility, including a discussion of a small utility size 25 risk premium. Corix suggested that the Commission adopt a generic approach to setting 26 a deemed capital structure, return on equity, and debt rates to recognize: 27 28

1) the fundamental differences between a small TES utility and the benchmark 29 utility; and 30 31 2) the limited resources available to small utilities to meet the regulatory burden 32 of establishing a fair return on investment through a formal Commission review. 33 34

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Section 7 of the Commission’s decision deals with the cost of capital issues for small 1 utilities. The Companies have developed this evidence to respond to the Commission’s 2 directions in the Stage 1 decision, particularly the directions related to the use of the “risk 3 matrix” approach.1 To be efficient, the Companies will rely on the record from Stage 1 4 that deals with the small utility issues and will supplement that record with this 5 submission. 6 7 2. Structure of this Submission 8 This submission comprises two documents, organized as follows: 9 10

• Overview Document: 11 o This document outlines the following key concepts relevant to small 12

utilities: 13 14 Small TES utilities differ fundamentally from the benchmark utility; 15

16 The regulatory burden of setting capital structure and return on 17

investment (debt and equity) is disproportionate to the relative size 18 of the utility business; 19 20

The Commission’s risk matrix should be simplified; and 21 22

A generic approach should be applied to set capital structure and 23 return on investment. 24

25 • Appendix A – Company-specific evidence: 26

27 o Each of the Companies briefly outlines the risks and challenges that each 28

utility business faces, keeping in mind the areas identified in the 29 Commission’s risk matrix; 30 31

o The Companies also comment on the factors in the Commission’s risk 32 matrix and offer their perspectives on how the factors may apply and 33

1 See page 101 and Appendix E of the Commission’s decision.

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should be weighted, based on their experience operating small utilities in 1 British Columbia. 2 3

The Companies are also filing supplemental evidence from Pauline Ahern of AUS 4 Consultants, as part of their submission. In that evidence: 5

6 • Ms. Ahern calculates the specific risk premium adjustments for each of the 7

Companies using the Ibbotson and Duff & Phelps risk studies that were 8 explained in Stage 1; and 9

10 • Ms. Ahern also comments on the Commission’s risk matrix approach and its 11

factors, based on her experience as an expert in the area of cost of capital for 12 regulated public utilities. 13 14

3. Key Concepts – Small Utility Perspective 15

3.1 Small TES Utilities differ fundamentally from the benchmark utility 16

Setting the return on equity and capital structure for a “benchmark low-risk” utility in 17 Stage 1 established a reference point against which other utilities could be compared.2 18 FEI was selected as the benchmark utility because it is a natural monopoly utility that is 19 “well established, of sufficient size [with] a diverse customer and asset base” and is “well 20 understood” because of its history as the benchmark utility.3 21 22 Small utilities differ from FEI because they meet virtually none of those “low risk” criteria. 23 Most notably, small utilities often operate in a competitive environment where customers 24 have many energy choices, including their service provider if they choose TES. 25 26 The TES market is an emerging market that, unlike the natural gas distribution utility 27 market, is not characterized by natural monopolies. The TES market provides service to 28 customers at a small scale using many different applications of both existing and new 29 technologies. Due to the local nature and smaller size of TES energy projects, the TES 30

2 Order G-148-12, Appendix A, Reasons for Decision, p. 2. 3 Ibid, p. 4.

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market has much lower economic barriers to entry than the natural gas distribution 1 market, and is best served when competition is encouraged. 2

3 Small utilities, particularly those offering TES services, also do not compete solely on the 4 basis of price or quality of service. They compete based on the environmental qualities 5 of their service, such as the degree to which the heat or electricity provided is “clean” or 6 “green”, which is becoming an increasingly important social value. For this reason, 7 government policies and initiatives have encouraged the development of TES projects. 8 9 Small utilities meet these competitive challenges in a variety of ways. Their operations 10 reflect attempts to serve diverse aspects of the energy market, often with innovative 11 technologies. These efforts entail a very different, and riskier, risk profile than for a 12 conventional utility business characterized by a natural monopoly with a large, captive 13 customer base paying its regulated cost of service. 14

15 As a result, the return that investors expect to receive on an investment in small utilities 16 is higher than an investment in the benchmark utility. 17

3.2 Regulatory burden of setting capital structure and return on investment 18 (debt and equity) is disproportionate to the relative size of the utility 19 business. 20

Some Canadian jurisdictions have recognized small size as a material risk factor. In its 21 two most recent GCOC proceedings, the Alberta Utilities Commission awarded AltaGas 22 a premium based on “AltaGas’ relatively small size, rural service area, geographically 23 dispersed customers and high level of customer contributions.”4 24 25 The AUC approach is to establish a common ROE, and vary the deemed capital 26 structure to reflect relative risk. AltaGas’ equity thickness is 4% higher than ATCO Gas, 27 a natural gas distribution utility comparable to the BCUC benchmark. AltaGas is 28 nevertheless significantly larger than the small utilities that are the subject of this 29 evidence. AltaGas’ regulated business in Alberta is natural gas distribution “to nearly 30

4 Decision 2011-474, p. 91.

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72,000 residential, rural and commercial customers in over 90 communities across 1 Alberta”.5 2

3 While there is clear empirical support for a small utility equity risk premium, as explained 4 in Ms. Ahern’s Stage 1 evidence, such a premium has not been considered extensively 5 in public utility regulatory jurisprudence. This situation is not surprising. Entities that are 6 regulated as public utilities in B.C. are often not regulated as public utilities in other 7 jurisdictions, so the cost of capital issues do not arise in the regulatory arena. For small 8 utilities that do fall within public utility regulation, the cost and effort to assemble the 9 evidence to demonstrate a fair return for a small utility will often outweigh the benefit of 10 doing so. So, it would be rare for the cost of capital issues to be contested in any depth. 11 12 Demonstrating a fair return in a formal BCUC review requires retaining experienced 13 counsel, expert witnesses, and the deployment of substantial internal resources to 14 manage a sophisticated regulatory process. Faced with this reality, many small utilities 15 would see only two options: 1) accept Commission determinations without challenge, or 16 2) seek to operate in other jurisdictions. Thus, the economic regulation designed to 17 protect the public interest may instead stifle the market for small utilities offering 18 innovative alternative energy solutions. 19 20 The Commission itself has noted: 21 22

“Regulation is costly, time-consuming, and limited by informational asymmetries. 23 It is only in natural monopoly situations where consumer protection is needed 24 that these limitations are outweighed by the benefits of regulation.”6 25

26 The risk of the regulatory burden frustrating the TES market can be mitigated by 27 lowering the regulatory barrier to facilitate small utility participation and growth in the 28 TES market. Moreover, the public interest does not require regulation because 29 competitive market forces are sufficient to protect against abuse of market power. 30

5 http://www.altagas.ca/utilities/altagas_utilities 6 Alternative Energy Services Inquiry Report, p. 14.

http://www.altagas.ca/utilities/altagas_utilities

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3.3 Commission’s risk matrix should be simplified 1

In its GCOC Stage 1 decision, the Commission recommended that small utilities use the 2 matrix attached to the decision as Appendix E to establish their risk profile relative to the 3 benchmark utility: 4 5

The “size” factor is one of the risk factors included in the matrix. The 6 Panel recommends that the small utilities use this risk matrix attached as 7 Appendix B to Order C-1-13 of the TELUS Garden Decision9 in the Stage 8 2 proceeding and for future projects to justify their case for the 9 appropriate capital structure and risk premium over and above the 10 benchmark ROE.7 11

12 The matrix consists of 19 risk factor categories and a relative comparison between the 13 applicant, FEI and six other TES utilities. However, the relative comparison does not 14 truly recognize the relative risk differential between FEI and the small TES utilities. 15 16 The largest equity risk premium that the Commission has awarded is 100 basis points. 17 This differential simply does not reflect the real difference in risk profiles between the 18 benchmark utility and most small TES utilities operating in B.C. This point is confirmed 19 by both the empirical research related to equity risk premiums and the actual financing 20 experiences of the Companies, which experience would be typical of other small utilities. 21 22 The risk matrix ignores that experience. Once an equity risk premium has been 23 established for the first TES utility – in this case, Dockside Green Energy – then the 24 matrix focuses attention onto the relative risk between small utilities, rather than the 25 relative risk between the benchmark utility and the overall category of small utility. This 26 proceeding is the first opportunity to examine the appropriate equity risk premium in any 27 depth. 28 29 For the risk matrix approach to be valid, it must properly situate the small utility category 30 relative to the benchmark utility and then allow for individual variation. To be specific, 31 the risk premium spread must not be limited to 100 basis points, either explicitly or 32

7 Stage 1 Decision, p. 101.

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implicitly through a relative comparison within the small utility class. There is no 1 principled foundation to support that limit to the risk premium. 2 3 Further, the matrix is difficult to apply in practice because the 19 factors are duplicative 4 and appear to receive equal weighting. Ultimately, the risk matrix approach becomes a 5 highly subjective exercise that may give the perception of structured analysis when, in 6 fact, the structure does not recognize or properly weight the key factors that drive risk. 7 8 The regulatory burden can be alleviated by simplifying the matrix to allow it to reflect 9 small utilities’ experience more accurately. A threshold and important element of 10 simplifying the matrix is to recognize that utility size is the dominant characteristic that 11 drives or influences most of the 19 categories. 12 13 The Commission’s 19 risk factors are: 14

15 1. Technology risk/system performance 16 2. Fuel risk cost and availability 17 3. Customer base (Diversity, certainty) 18 4. Default risk of customer 19 5. Property development risk 20 6. Developer/customer connection risk 21 7. Load forecast uncertainty 22 8. Utility size 23 9. Initial construction cost risk 24 10. Future construction cost risk 25 11. Operating cost risk 26 12. Public acceptance risk 27 13. Fixed/variable rate design 28 14. Levelized approach to rates 29 15. Financial risk 30 16. Competitive challenges 31 17. Provincial climate change & energy policies 32 18. Regulatory uncertainty 33 19. Business development risk 34

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1 The Companies believe that the factors may grouped together into the following 2 categories. Some of the risk factors would become subcategories of the larger risk 3 categories: 4 5

A. Risks that have been empirically measured: 6 7

1. Utility size risk (8) 8 2. Financial risk (15) 9

10 B. Risks that have not been empirically measured: 11

12 3. Competition risk (16) 13 4. Customer load risk: 14

a. Customer base (Diversity, certainty) (3) 15 b. Default risk of customer (4) 16 c. Developer/customer connection risk (6) 17 d. Load forecast uncertainty (7) 18 e. Public acceptance risk (12) 19

5. Development cost risk 20 a. Property development risk (5) 21 b. Initial construction cost risk (9) 22 c. Future construction cost risk (10) 23 d. Business development risk (19) 24 e. Technology risk (1) 25

6. Operating cost risk 26 a. Fuel risk cost and availability (2) 27 b. Operating cost risk (11) 28

7. Rate design risk: 29 a. Fixed/variable rate design (13) 30 b. Levelized approach to rates (14) 31

8. Regulatory risk 32 a. Regulatory uncertainty (17) 33 b. Provincial climate change & energy policies (18) 34

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1 The relative weighting for each factor will depend on the circumstances of each utility, 2 but utility size is the overarching and dominant factor affecting small utility risk. The 3 smaller the size of a utility, the less its ability to manage and lower its risk, and ultimately 4 the higher the equity risk premium. 5 6 The competitive risk factor is also a key element. Small TES utilities face far greater 7 competitive challenges than the benchmark utility, which for gas distribution is a natural 8 monopoly and, in some municipalities, has an exclusive service franchise. Most small 9 TES utilities do not have exclusive service franchise rights so they operate in a truly 10 competitive market. 11

19.4 Certain aspects of the risk matrix approach should follow a generic 12 approach 13

The matrix approach can incorporate both empirical-based elements and subjective 14 elements. The matrix can make use of the empirical correlations between utility size and 15 market return to quantify with some precision what investors would perceive a fair return 16 to be. Ms. Ahern described the relevant Ibbotson and Duff & Phelps calculations in 17 Phase 1, and has elaborated in her Stage 2 testimony on how this work could be applied 18 to the Companies. 19 20 Using an empirical approach to set the risk premiums to account for the utility size risk 21 and the financial risk has a solid foundation, based on the research and empirical 22 evidence that was explained during the Stage 1 by Ms. Ahern and Ms. McShane. That 23 evidence was uncontroverted in the Stage 1 proceeding. It is the best evidence to guide 24 the Commission in this Stage 2 proceeding. 25 26 For the first two factors (A. 1. Utility size risk and A. 2. Financial risk) noted in Group A of 27 the revised matrix factors, a generic approach can be used to calculate the appropriate 28 range of risk premium. Ms. Ahern’s evidence elaborates on the calculation of the 29 appropriate equity risk premium for the Companies to illustrate the approach. 30 31 The remaining elements of the matrix (those that have not been empirically measured – 32 i.e. Group B) can be assessed with the information provided by the Companies directly. 33

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Those factors can be used to adjust the results of the generic analysis, if appropriate in 1 the circumstances. 2

3 Financing small utilities on a stand-alone basis is challenging and expensive. For that 4 reason, it is preferable to set a deemed debt structure and deemed debt rates using a 5 reasonable benchmark rather than require small utilities to gather and present evidence 6 of debt rate offers from financial institutions. Financial institutions will not lightly quote a 7 debt rate for a hypothetical situation since the quote is a binding commitment. 8 9 20. Conclusion 10 Both the academic and actual experience show that the returns established by the 11 Commission using the matrix approach do not reflect the returns investors expect of 12 businesses of comparable risk. The current equity risk premiums shown in the 13 Commission’s matrix have evolved to the current levels because the utilities involved 14 have not been in a position to marshal a full evidentiary case to establish what a fair 15 return would be. 16 17 This regulatory burden creates a disincentive to the growth of the TES sector in British 18 Columbia. That impediment is inconsistent with the broad climate and energy policy 19 goals established by government in its energy policy initiatives and the Clean Energy 20 Act. 21 22 The Companies propose a simplified version of the Commission’s matrix that: 23 24

• recognizes that utility size is a key driver of risk for small utilities, and 25 26

• adopts an empirical approach to situate the small utility within a comparable 27 cohort of utilities based on size, and then identifies a reasonable equity risk 28 premium range based on that comparison. 29

30 This solution would result in a streamlined process for the key factors in the 31 Commission’s risk matrix, alleviating the regulatory burden on small utilities improving 32 the fairness of the returns they receive. Improved returns would, in turn, stimulate the 33 development of the innovative energy solutions that small utilities offer, consistent with 34

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provincial policy goals. At the same time, the customer interest is protected by 1 competition in the TES market. Customers may choose their TES service based on the 2 criteria they value. 3 4 For the capital structure and return on investment, the Companies recommend the 5 following standards be used as the default position for small TES utilities: 6 7

• Capital Structure: The debt/equity ratio should be set at 40% debt / 60% equity 8 to reflect the realistic capital requirements of typical small utilities. 9 10

• Return on Equity: The equity risk premium for small utilities relative to the 11 benchmark low-risk utility should be a minimum of 250 bps. This equity risk 12 premium is below the low end of the equity risk premiums that Ms. Ahern has 13 calculated in her evidence. Those risk premiums are already conservative in 14 nature given the size of the companies referenced within the empirical studies. 15 16

• Debt: The debt component of the capital structure should be set to track a 17 benchmark credit spread that reflects BBB or BBB(low) rated debt relative to the 18 10 year Government of Canada bond yield. 19 20

In all cases, these standards would be the minimum standards that would be applied in 21 the absence of evidence to suggest further adjustments. It would always be open to a 22 small utility to make the case for further adjustments to reflect its individual 23 circumstances. In most cases, however, these standards would allow for a generic 24 approach to assess the core elements of risk that is based on empirical evidence for the 25 category of small utility, rather than placing an overwhelming evidentiary burden one 26 small utility at a time. 27 28 All of which is respectfully submitted by Corix Utilities Inc. and its related companies, 29 Central Heat Distribution Limited, and River District Energy Limited Partnership. 30 31

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APPENDIX A 1 Company Specific Evidence 2

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1. Corix Utilities Inc. 4 5 Q1. Outline your company’s utility operation. 6 7 A1. Corix and affiliate companies own and operate TES undertakings across North 8

America. In B.C., Corix owns and operates the following TES undertakings, 9 some of which are regulated by the BCUC: 10 11

• Lonsdale: Lonsdale Energy Corporation (“LEC”) is a corporation owned 12 by the City of North Vancouver that owns a district energy system that 13 serves residents in the Lower Lonsdale area. The district energy system 14 provides hydronic space heating and domestic hot water service. Corix 15 has partnered with LEC to operate and provide customer care for the 16 district energy system. Under the terms of the agreement with LEC, Corix 17 also designs, finances and builds the local energy plants (natural gas 18 boilers), located in designated buildings on the LEC system. LEC is not 19 regulated by the BCUC because it is a municipally-owned utility. 20 21

• Dockside Green: Corix is a partner in Dockside Green Energy Inc. 22 (“DGE”) with a 17% equity share. Under an agreement with DGE, Corix 23 also operates the DGE system. DGE is a public utility regulated by the 24 BCUC. DGE provides hydronic energy for space heating and domestic 25 hot water to the Dockside Green community in Victoria using a central 26 energy plant. The plant consists of a biomass gasification system and a 27 supplementary natural gas boiler. 28 29

• UniverCity at Burnaby Mountain: Corix is developing a district energy 30 system to serve the UniverCity community on Burnaby Mountain. The 31 initial system will provide service through a temporary natural gas boiler 32 facility. A permanent central biomass energy plant will be constructed in 33 later phases. UniverCity is regulated by the BCUC. 34

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1 • Sun Rivers: Corix operates a series of stand-alone geo-exchange 2

systems that provide space heating for the community of Sun Rivers near 3 Kamloops. These stand-alone systems serve individual residences on 4 Kamloops Indian Reserve No. 1. 5

6 Corix is also in the feasibility analysis stage for several similar sustainable energy 7 thermal district energy projects in the lower mainland. 8 9 This evidence focuses on Dockside Green and UniverCity. 10

11 Q2. Who are your customers? 12 13 A2. The customers for these types of developments are generally residential stratas 14

with some mixed residential commercial strata developments. In the case of 15 UniverCity, the system also services one preschool customer. 16

17 Q3. Who do you compete with? 18 19 A3. Competition may come from a variety of sources, including FEI, BC Hydro, other 20

TES providers, the project owner/developer and in some cases municipal 21 corporations. Once the district energy system is in place, there are occasions 22 where connection is practically mandatory and competition for the thermal 23 service is limited. Where connection is not mandatory, competition would come 24 from other stand-alone solutions – for example, electric baseboards. 25

26 Competition generally occurs in the feasibility assessment stage for greenfield 27 TES projects. Customers developing a new building, or considering retrofitting 28 an existing building, have the traditional heating options of electric baseboard 29 heating, central natural gas air heating, or a natural gas fired boiler. Increasingly, 30 many customers are also interested in exploring alternative energy options. The 31 reasons for doing so will vary from customer to customer. A customer that 32 decides to consider an alternative option in more depth will usually issue a 33 request for proposals (“RFP”) to develop a TES system. 34

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The RFP process is competitive, and generally results in several bids from TES 1 service providers. The ultimate choice is based on multiple factors, including: 2

• the positive environmental characteristics of the energy supply, 3

• the merits of the project design, 4

• expected capital cost, 5

• expected operating costs and rates, 6

• risk allocation and performance guarantees, 7

• expertise of the TES provider, and 8

• the overall relationship, form of contract, and potential partnership 9 between the parties. 10

Q4. Please describe the market for your company’s services in BC. 11 12 A4. The market is characterized by several drivers. These include a desire for a 13

higher level of environmental sustainability, a flexible platform for the 14 implementation of new technologies, the potential for lower life cycle costs and 15 mandated reductions in greenhouse gases, to name a few. Our clients include 16 developers of comprehensive developments, municipalities and public 17 institutions. 18

19 Q5. Explain how the market is changing. 20 21 A5. Generally, we are seeing an increasing desire to implement smaller, district scale 22

thermal energy systems at institutions and municipalities. These are attractive to 23 this customer set because of sustainability and flexibility. Waste heat and other 24 less conventional energy sources are increasing in popularity. 25

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Q6. How is your utility business financed? Can it be financed on a stand-alone 1 basis? If so, at what rates relative to the prime rate? 2

3 A6. Corix Utilities is financed through a combination of debt and equity. Corix Utilities 4

is debt financed through Corix’s consolidated credit facilities. Corix Utilities 5 provides debt financing to its regulated utilities through intercompany loan 6 agreements with a cost of debt that reflects the specific risk profile of that project. 7

8 Directly accessing bank debt on a stand-alone basis would be administratively 9 burdensome and inefficient given the relative size of the utilities. 10

11 Q7. Explain the risks facing your utility business. 12 13 A7. Small TES utilities face a variety of challenges that differentiate them from 14

traditional utilities, including the following: 15

• Attracting customer interest in a sustainable energy project when the general 16 public perception is often that a traditional natural gas or electric utility option 17 will be cheaper; 18

• TES systems feature new technologies, new systems, and new 19 configurations. The upfront cost of pursuing customers can be significant as 20 a result; 21

• While the community-focused nature of these projects may allow more 22 modular and phased development, they do not benefit from the scale and 23 diversity of a large monopoly system, such as natural gas utility, to dampen 24 the effects of variability in local conditions and weather; 25

• Since the TES market is in an early stage of development, a significant 26 portion of the cost and effort is spent on business development to secure 27 projects and develop them successfully; 28

• TES developers, other than the existing utilities like FEI, do not have an 29 existing utility rate business that they can use to absorb costs and financial 30 risk. Thus, the TES offerings must be priced to reflect the market and the 31

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actual cost of service, rather than a subsidized cost. The TES developer 1 shareholders must absorb the balance of the significant upfront business 2 development costs and risk; and 3

• Finally, TES providers that fall within public utility regulation also bear a 4 relatively heavy regulatory burden given the small size of start-up TES 5 projects and their revenues. Typically, these costs cannot be passed through 6 to customers. 7

Q8. Comment on the factors outlined in the Commission’s risk matrix, 8 including the number of factors listed and how you would weight them. 9

10 A8. The Commission’s matrix provides an extensive list of factors. Since the majority 11

of the factors in the matrix are interrelated, it is difficult to determine weights for 12 each factor. 13

14 Grouping the factors listed in the matrix under a smaller subset of risk factors 15 would help to focus the process and to assign weights. The most important factor 16 that is related to virtually all other factors is size of the utility. Utility size should be 17 assigned the highest weight. 18

19 Q9. To what extent is the size of your utility operation a factor in relation to the 20

other risk elements listed in the Commission’s matrix? 21 22 A9. Size is the most important risk factor. It affects most other factors listed in the 23

matrix. 24 25 Q10. What adjustments would you recommend to the risk matrix? 26 27 A10. The matrix risk factors should be consolidated into a few factors. This would 28

facilitate assigning weights to each factor. 29 30

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Q11. Explain how the significance of administrative burden of participating in 1 Commission Cost of Capital proceedings relative to the size of your utility 2 operation. 3

4 A11. Participation in proceedings of this nature requires a substantial commitment of 5

resources both internal and external. The effort is disproportionate due to the 6 small size of the utility relative to the large low-risk gas utility. 7

8 Q12. Do you have the ability to pass through all of those regulatory costs to 9

your customers through the utility rats? 10 11 A12. No, the small customer base means that passing through costs from proceedings 12

of this nature in customer rates is not feasible. 13 14 Q13. Would a generic approach to setting the capital structure and cost of 15

investment (debt and equity) for small utilities assist in alleviating the 16 regulatory burden ? If so, explain how. 17

18 A13. Yes. A generic approach, as was proposed in the evidence submitted by Corix in 19

Stage 1, would allow small utilities to supply readily available information related 20 to their particular operations to the Commission and for the Commission to set a 21 small utility capital structure based on a defensible empirical body of work. 22

23 24

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2. Central Heat Distribution 1 2 Q1. Outline your company’s utility operation, including the location and 3

number project sites within your utilities 4 5 A1. Central Heat provides thermal energy in the form of steam to buildings in 6

downtown Vancouver. It has operated as a regulated utility in BC since 1968. 7 8 Q2. Who are your customers and how many are there? 9 10 A2. Central Heat customers are a diverse mix of offices, hotels, public institutions, 11

retail, and residential condos. The company serves over 200 buildings with a 12 combined total space of approximately 39 million square feet It is the largest 13 district energy company in Canada by customers connected. 14

15 Q3. Who do you compete with? 16 17 A3. Customers may choose to use Central Heat, electricity, natural gas or hybrid 18

systems for heating. In other words, the primary competitors to Central Heat are 19 BC Hydro, FEI, and other TES providers. In some cases these other energy 20 sources are used in conjunction with Central Heat. 21

22 Q4. Please describe the market for your company’s services in BC. 23 24 A4. Generally, district energy service in BC is expanding. Central Heat focuses its 25

efforts on providing district energy utility service to downtown Vancouver 26 customers. 27

28 Q5. Explain how the market is changing. 29 30 A5. The public and various levels of government have become more interested in 31

different energy systems recently, resulting in government incentives, new 32 policies, and increased competition from traditional utilities. 33

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Specific examples include: 1 2 • Hybrid energy systems have become both more popular and more practical 3

to develop, and Central Heat has been involved in some conversions 4 recently. 5 6

• FEI is now providing subsidies in the form of grants for buildings to buy 7 boilers. The company is increasingly hearing more about this in the market. 8 9

• Recent City of Vancouver policies focus on reducing greenhouse gas 10 emissions. The City would like to see the use of biomass or other energy 11 sources that are considered to be less carbon intensive. The City of 12 Vancouver policy directly influence district energy development and the ability 13 of providers to be able to compete, requiring a substantial amount of civic 14 engagement at the policy level 15

16 Q7. How is your utility business financed? Can it be financed on a stand-alone 17

basis? If so, at what rates relative to the prime rate? 18 19 A7. The utility is financed through commercial credit arrangements with a bank. It is 20

now financed on a stand-alone basis. The variable borrowing rate is prime plus 21 0.5%. 22

23 The bank also requires an equity component of approximately 50% and other 24

financial ratio conditions. 25 26 Q8. Explain the risks facing your utility business. 27 28 A8. Notable risks include the following: 29 30

• Central Heat competes directly with FEI and BC Hydro for business, but 31 operates in the market without an exclusive franchise. New customers can 32 choose one of Central Heat’s competitors, and existing customers can 33 choose to convert their energy supply to another source. Central Heat’s 34

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customer based energy demand is less than 2% of the low risk benchmark 1 utility to which it is compared. 2 3

• Central Heat competes directly with municipal district energy developments, 4 where the municipality is not only unregulated, but entitled to establish 5 policies affecting Central Heat. 6 7

• There is a tax policy bias against natural gas use (carbon tax) that 8 disproportionately burdens Central Heat relative to some competitors, notably 9 BC Hydro. 10 11

• Government policies pose a constant risk of subsidizing competitors or 12 otherwise adversely affecting Central Heat’s ability to attract customers. 13 14

• Demand side management programs of large utilities offer funding in the form 15 of grants to subsidize boiler purchases. Capital costs are a factor in customer 16 choice. 17 18

• City of Vancouver policy would prefer biomass use in Vancouver instead of 19 natural gas. The development consequences pose material risks and costs. 20 21

• Utility size limits financing options that are otherwise available to large 22 utilities. Bank credit facilities are subject to variability in the market and the 23 practices of a bank at any point. 24

25 Q9. Comment on the factors outlined in the Commission’s risk matrix, 26

including the number of factors listed and how you would weight them. 27 28 A9. Central Heat provides general comments before specifically addressing each risk 29

matrix category. 30 31

General Comments 32 • The Commission’s risk matrix comprises real business risks but, because they 33

overlap, the list of risks should be simplified into broader categories. The list is 34

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useful because it identifies sub-issues and can highlight risks which vary 1 significantly between small utilities. For example, property development risk may 2 be very significant to a small utility with a greenfield project, but is not a serious 3 risk to Central Heat which has grown for 45 years in an area of high density. The 4 same risk should therefore receive different weight in the specific risk matrix for 5 each company. The current use of the matrix treats all risks equally, without any 6 weighting and where some categories overlap, risks subjective and inaccurate 7 outcomes. 8 9

• It is noteworthy that the TES utilities contained in the suggested matrix all have 10 risk premiums that are at most 100 basis points above that of FortisBC Energy 11 Inc. Despite being a utility 45 years old, Central Heat’s credit facility requirement 12 reflects materially more risk than the BCUC’s benchmark debt to equity ratio 13 (38.5 equity thickness), certainly more than the 100 bps suggested by the matrix 14 as a maximum. Central Heat did not achieve a rate of return comparable to the 15 current benchmark (8.75%) until after twenty years of operation, and incurred 16 losses during its first ten years. Cost constraint was and continues to be a 17 priority, and Central Heat has operated without levelized costs, without deferral 18 accounts and in an area highly suitable to district energy. 19

20 Specific Risk Matrix Comments 21

1. Technology risk/system performance risk associated with chosen technologies 22 23 Moderate risk, above benchmark 24 25

• District energy is adaptable to improvement in technology and fuel types. 26 • A range scale fuel switch to biomass, for example, has very significant risks to 27

the utility because of added costs and environmental concerns. 28

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• System performance expectations are 100% and although Central Heat has 1 been over 99.9% for 45 years, the need for very high system performance is 2 even more essential to smaller utilities. 3

4 2. Fuel Risk cost and availability 5 6 High risk, above benchmark 7 8

• While natural gas is one of the most reliable fuels available, and is a flow through 9 cost to customers, alternative fuels like biomass are not, and in fact require a 10 stable backup fuel source such as natural gas to ensure customers’ high 11 reliability expectations are met. 12 13

3. Customer Base (e.g., diversity, certainty, growing declining) 14 15 Low risk, comparable to benchmark 16 17

• Central Heat has a diverse customer group and is not reliant on any one or a few 18 customers. A startup utility, as we once were, is more susceptible to that risk as 19 are small utilities that serve one entity, i.e., Ski Hill. 20 21

4. Default risk of customer 22 23 Low risk, comparable to benchmark 24 25

• This has not been an issue because property owners wish to maintain their 26 building’s energy service. There is some risk associated with the loss of a 27 customer building through fire. 28

29 5. Property development risk 30 31 Moderate risk, above benchmark 32 33

• Central Heat is less exposed to that risk than it was the case in the Company’s 34 early years. A new green field development is exposed to this risk as evident with 35 several developments in BC. 36

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6. Developer/customer connection risk 1 2 High risk, well above benchmark 3 4

• One of the largest risks can be if there is no mandatory connections and no 5 exclusive franchise. Central Heat does not have an exclusive franchise. 6

7 7. Load Forecast Uncertainty 8 9 High risk, well above benchmark 10 11

• Weather can vary +/- 15 year to year and customer demand side energy 12 reductions add further uncertainty. Central Heat’s load forecast uncertainty risk 13 is borne by the Company. 14

15 8. Utility size 16 17 High risk, well above benchmark 18 19

• If a small utility has an exclusive franchise and mandatory connections, utility 20 size risk is significantly less. Central Heat has neither. 21

22 9. Initial construction cost risk 23 24

• Central Heat is beyond the initial construction phase so this risk is not a factor. 25 • Central Heat certainly experienced this risk when initially starting to build its utility 26

infrastructure. It can be a significant risk factor for a small utility. 27 28 10. Future construction cost risk 29 30 Moderate risk, above benchmark 31 32

• Less risk than initial construction, however the utility is still susceptible to new 33 costs of construction price escalation and regulatory change risk. 34

35 11. Operating cost risk 36 37 Moderate risk, above benchmark 38 39

• This should largely be a known risk before startup. Interest rate and labour costs 40 have a real risk impact for smaller utilities, including Central Heat. 41

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12. Public acceptance risk 1 2 High risk, well above benchmark 3 4

• Depending on a utility’s input fuel, public acceptance can be a significant risk. 5 6

13. Fixed/variable rate design 7 8 Low risk, comparable to benchmark 9 10

• Central Heat has an almost all variable based rate design. We have had no 11 complaints from any customers because they are also easier to understand and 12 directly related to consumption. 13

14 14. Levelized approach to rates 15 16

• [Not directly applicable given comment to the Fixed/variable rate design 17 category] 18

• Levelized rates are based on a set of assumptions well into the future. The 19 forecasts used to create them can and do vary dramatically. Central Heat has not 20 used levelized rates and is not inclined to do so. Levelized rates do not 21 necessarily align customer interests with the utility and create the prospect of 22 large offside deferral accounts. 23

24 15. Financial risk 25 26 High risk, well above benchmark 27 28

• There is more financial risk with smaller utilities for numerous reasons. Financing 29 is susceptible to credit issuance requirements which vary. This category is 30 affected by a number of the issues detailed in the responses to other categories. 31 32

16. Competitive challenges 33 34 High risk, well above benchmark 35 36

• Unless a small utility has an exclusive franchise and mandatory connections, it is 37 faced with significantly higher risks. 38

o Municipalities, such as the City of Vancouver, have entered the TES utility 39 business. They access public funds, can accumulate deferral account 40

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balances, write policy affecting their competitors, and are essentially 1 unregulated monopolies competing against regulated non-monopoly 2 utilities. Where municipal competition exists it creates a materially higher 3 risk for small TES utilities. 4 5

o Large utilities’ demand side management funds are being placed into the 6 market, distorting customers’ choices between alternative energy 7 providers. In essence district energy companies and other small utilities 8 are paying competitors to compete against them. This may be an 9 unintended outcome, but it is a risk most competing businesses do not 10 experience. 11

12 17. Provincial climate change and energy policies 13 14 High risk, well above benchmark 15 16

• Government intervention into the marketplace has an equal chance of positively 17 or negatively affecting Central Heat’s business, depending upon whether the 18 effect bolsters Central Heat relative to its competitors or vice versa. 19

20 18. Regulatory uncertainty 21

22 High risk, well above benchmark, but duplicative of earlier categories 23 24

• Central Heat is affected by BCUC utility regulation, municipal policies and 25 permitting decisions, and more general provincial policies. 26 27

• BCUC regulation has maintained a relatively level playing field. In contrast, 28 municipal regulation lacks neutral party oversight. Provincial policy is politically 29 motivated to some degree and consequently subject to change. 30 31

19. Business development risk 32 33 High risk, well above benchmark, but duplicative of earlier categories 34 35

• Many of the above noted risks are parts of the overall business development risk. 36 ______________________________________________________________________ 37 38

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1 2 Q10. To what extent is the size of your utility operation a factor in relation to the 3

other risk elements listed in the Commission’s matrix? 4 5 A10. Size is a major factor. While smaller utilities experience similar risks to large 6

utilities, the potential consequences are more severe because small utilities have 7 fewer resources, are less able to mitigate adverse market effects and are less 8 diversified. 9

10 Q11. Explain the significance of the cost and administrative burden of 11

participating in Commission Cost of Capital proceedings relative to the size 12 of your utility operation. 13

14 A11. Central Heat’s risk profile is well beyond that of a provincial wide natural 15

monopoly on numerous fronts. Arguing over a quarter point here or there is a 16 costly use of resources when the fundamental issue is that the risks are 17 materially different. 18

19 Q12. How are your customer rates set? 20 21 A12. Cost of service regulation. Central Heat has made a practice of not using deferral 22

accounts because they distort the utility true costs, increase debt and discourage 23 a more disciplining approach to spending. 24

25 Q13. Do you have the ability to pass through all of your regulatory costs to your 26

customers through the utility rates? 27 28 A13. Yes, subject to BCUC approval. 29 30

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Q14. Would a generic approach to setting the capital structure and cost of 1 investment (debt and equity) for small utilities assist in alleviating the 2 regulatory burden ? If so, explain how. 3

4 A14. Yes, it would be a more efficient means to arrive at a capital structure for smaller 5

utilities. The matrix serves a purpose in that it acknowledges that there is an 6 extensive list of risks that vary depending on the circumstances of each utility. 7 But the resulting practice of largely mimicking the debt to equity ratio of a large 8 utility, subject to small premiums, does not reflect real world outcomes. 9 If shareholders are prepared to align their interests with customers in early years 10 by foregoing return (something that can be almost guaranteed at a traditional 11 utility by using deferral accounts), there is reason to support a higher rate of 12 return in later years. This can be also achieved when allowing smaller utilities 13 greater equity thickness in their capital structure. 14

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3. River District Energy Limited Partnership 16 17 Q1. Outline your company’s utility operation, including the location and 18

number project sites within your utilities 19 20 A1. RDE is a district energy utility established to provide thermal energy for space 21

heating and domestic hot water to the River District development in southeast 22 Vancouver. River District is under construction now and, at buildout in 23 approximately 20 years, will contain 7.0 million square feet of residential and 0.5 24 million square feet of retail/commercial density. The development is to include 25 approximately 60 separate legal parcels in the 130 acre site, each of which may 26 include one or more air space parcels owned by separate stratas. 27

28 The distribution piping system at River District includes the provision to supply 29

buildings to be constructed on specific vacant sites outside of River District. The 30 timing for construction on these sites or likelihood of connecting to RDE is 31 indeterminable. 32

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At build out RDE will produce approximately 70 GW.h per year. Initially natural 1 gas will be used, with a low-carbon alternative subsequently implemented when 2 economically feasible. The current plan calls for construction of a 5 km closed 3 loop hot water pipeline to an existing waste-to-energy-facility. The pipeline would 4 supply approximately 80% of River District’s annual energy needs with natural 5 gas used for peaking and backup. The local regional government, Metro 6 Vancouver, owns the WTEF and would recover the capital and operating costs of 7 the energy capture equipment and pipeline through a rate charged to RDE. 8

9 To date the RDE system consists of a temporary gas fired boiler, distribution 10 piping system and one energy transfer station. 11

12 Q2. Who are your customers and how many are there? 13 14 A2. RDE commenced providing service to its first, and so far only, customer in 15

October 2012. River District will include approximately 60 separate land parcels, 16 each of which may contain more than one airspace parcel. The precise number 17 of customers RDE will serve is presently estimated at 80-100. 18

19 Q3. Who do you compete with? 20 21 A3. To date 1.6 million of the total 7.5 million square feet of density has been 22

rezoned. The zoning conditions act somewhat like a franchise, and contain a 23 requirement for the buildings to connect to RDE’s system to supply 100% of the 24 thermal energy needs. Wesgroup expects the City will include the same 25 requirement as a zoning condition for the remaining 5.9M square feet of density. 26 This zoning condition restricts competition from conventional thermal energy 27 solutions but does not entirely eliminate it. Building owners are permitted to 28 implement building-specific solutions as long as they produce GHG reductions 29 acceptable to the City Engineer. 30

31 RDE sets its tariff against the benchmarks of rates charged by other utilities and 32

the cost of business as usual service. This practice serves as a proxy for open 33 competition in that the market effectively sets RDE’s rates. 34

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1 Q4. Please describe the market for your company’s services in BC. 2 3 A4. RDE’s market is limited to buildings to be constructed at River District and, 4

potentially, specific sites nearby. 5 6 Q5. Explain how the market is changing. 7 8 A5. RDE commenced operations in October 2012 and does not believe it has 9

sufficient first-hand experience to describe how the market is changing. 10 11 Q7. How is your utility business financed? Can it be financed on a stand-alone 12

basis? If so, at what rates relative to the prime rate? 13 14 A7. RDE’s development and net operations are 100% funded by its parent, 15

Wesgroup Properties Limited Partnership (“Wesgroup”). RDE will make 16 application for financing in several years when it has positive cash flow so it is 17 able to service the debt. 18

19 Wesgroup has substantial real estate holdings, including a large portfolio of 20 income producing properties. When RDE does obtain financing it believes the 21 lender will require that Wesgroup provide a guarantee of RDE’s obligations, 22 comparable to the guarantee required by the BCUC as a condition of granting 23 RDE’s CPCN. Wesgroup has ongoing relationships with all of Canada’s tier-1 24 chartered banks and several tier-2 lenders. RDE believes these lenders will be 25 prepared to lend to RDE at interest rates and terms comparable to those charged 26 Wesgroup for development projects. RDE expects financing while the system is 27 under development would be due on demand and at rates ranging from prime 28 plus 1.25% to 2%, inclusive of commitment and renewal fees. As River District 29 nears completion, and substantially all of the RDE’s system is constructed, it may 30 be possible to arrange a term loan with a fixed interest rate. 31 32 RDE does not offer an opinion as to interest rates for financing unsupported by a 33 guarantee from Wesgroup because it does not believe such financing to be 34

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available or, if financing was available, it would only be available at rates that 1 RDE would not find acceptable. 2

3 Q8. Explain the risks facing your utility business. 4 5 A8. The key risks include: 6

• Uncertainty of timing and amount of load: 7 8

o The buildings at River District will be constructed over the next 20+ 9 years and will follow the cyclical real estate market. To help illustrate 10 the point, consider that in the past five years BC housing starts have 11 ranged from a low of 16,000 to a high of 39,000. 12 13

o Energy use is dependent on a number of factors, including building 14 type, construction practices and occupant behavior. RDE forecasted 15 the Energy Use Intensities (“EUI”) for the buildings at River District 16 based on expected building typologies, which may change over time 17 in response to customer preferences, and known building code 18 requirements, which are becoming more stringent as they relate to 19 energy use. 20 21

• Construction cost uncertainty: 22 23

o There are few experienced district energy contractors and suppliers in 24 BC. Tendered rates vary widely from one phase to the next 25 depending on how busy they are. 26 27

o Many components are manufactured in Europe and distributed 28 exclusively by a single supplier in Canada. Long lead times and 29 variable pricing is the norm. 30 31

o RDE is a small utility being constructed in phases with a discrete 32 customer base. There is little opportunity to realize economies of 33

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scale in purchasing, exert pressure on suppliers or pass on costs to 1 customers. 2 3

• Access to capital on acceptable terms: 4 5

o The timing and likelihood of obtaining independent financing on 6 acceptable terms remains unknown. 7

8 Q10. To what extent is the size of your utility operation a factor in relation to the 9

other risk elements listed in the Commission’s matrix? 10 11 A10. RDE’s small size makes it susceptible to risks more readily absorbed by larger 12

utilities, principally as described in the response to Q8 13 14 Q11. Explain the significance of the cost and administrative burden of 15

participating in Commission Cost of Capital proceedings relative to the size 16 of your utility operation. 17

18 A11. The administrative burden is prohibitive. By way of example, RDE estimates that 19

the legal and consulting costs required to actively participate in Stage 2 of the 20 GCOC proceeding would approach 50% or more of RDE’s estimated total 2013 21 revenues. 22

23 Q12. How are your customer rates set? 24 25 A12. Customer rates are set by benchmarking against other TES utilities in the region. 26 27 Q13. Do you have the ability to pass through all of your regulatory costs to your 28

customers through the utility rates? 29 30 A13. No. RDE’s business plan supporting its CPCN application and rates tariff 31

included a provision for annual filings with the Commission. There was no 32 provision for participating in any subsequent Commission proceedings. All costs 33 associated with the CPCN and tariff processes were separately tracked and are 34

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eligible for recovery over the first five years of operation to the extent overheads 1 do not exceed the annual totals included in the CPCN submission. Any costs 2 remaining unrecovered after 5 years are for the account of RDE’s parent. 3

4 Q15. Would a generic approach to setting the capital structure and cost of 5

investment (debt and equity) for small utilities assist in alleviating the 6 regulatory burden ? If so, explain how. 7

8 A15. Yes. RDE is a discrete TES established to service River District. Its parent, 9

Wesgroup, has substantial resources but RDE does not have the in-house 10 expertise to respond to Commission and intervener submissions or the ability to 11 pass on to ratepayers the cost of retaining third party experts. 12

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1. Introduction2. Structure of this Submission3. Key Concepts – Small Utility Perspective3.1 Small TES Utilities differ fundamentally from the benchmark utility3.2 Regulatory burden of setting capital structure and return on investment (debt and equity) is disproportionate to the relative size of the utility business.3.3 Commission’s risk matrix should be simplified19.4 Certain aspects of the risk matrix approach should follow a generic approach

20. Conclusion