20 floor, four bentall centre 1055 dunsmuir street ... … · of river district in burnaby to a...

20th Floor, Four Bentall Centre 1055 Dunsmuir Street Vancouver, BC V7X 1L5 www.parklane.com

July 27, 2011 BC Utilities Commission 6th Floor, 900 Howe Street Vancouver, BC V6Z 2V3 Dear Sirs: Re: Application for a Certificate of Convenience and Necessity for the District Energy

Utility (“DEU”) at the River District, Vancouver We are pleased to submit our application referenced above. As instructed, we are providing one hard copy of the application and electronic copies of the application and appendices. We have also provided a full working copy of the financial model for each of the three scenarios described in the application. River District Energy Limited Partnership (“RDE”) is seeking:

• A CPCN under the Utilities Commission Act for the construction and operation of a DEU to serve the River District in Vancouver, BC

• Approval of the proposed revenue requirement, rate design and rates as set out in the application for the first five years of operation, which includes construction of distribution piping system, energy transfer stations and temporary and permanent energy centres to serve the initial development parcels.

The long-term business plan, which includes build out of the DEU infrastructure and connection to Metro Vancouver’s waste to energy facility in Burnaby, is presented as context for the proposed levelized rates, rate stabilization account and long-term benefits of the project. RDE intends to file an updated capital plan and projections within five years of commercial operation or when a major addition to capital assets is required, whichever is sooner. RDE requests that the Commission establish a written process to review this application and render its decision by mid December 2011 to enable RDE to serve its first customer early in 2012. RDE requests this process for the following reasons:

1. The River District is a new community being developed on former industrial lands located in southeast Vancouver. The planning and rezoning process has included 66 public meetings over 8 years with the DEU featured as a key element in the community sustainability strategy. Support for a DEU has grown to become a condition of rezoning and it is needed for buildings constructed to target the requisite LEED Gold standard.

B-1

markhuds

RIVER DISTRICT ENERGY DES CPCN

BC Utilities Commission July 27, 2011

2. The DEU will serve a pre-identified group of customers; the future strata owners of the River District development. RDE is a member of the Parklane Group developing River District and careful consideration was given to system and rate design to aid the overarching goal of ensuring that all areas of the development are successful, including the DEU.

3. Construction of the first building will begin in August and the builder, Polygon Homes, has indicated it will be calling for construction heat in February 2012 with occupancy scheduled for summer 2012. It is important that RDE be able to provide service within this timeframe.

The member entities of the Parklane group are privately held. RDE respectfully requests the financial statements and the working copy of the financial models to be kept confidential to protect the parties’ business interests. If you have any questions, please contact the writer at (604) 648-1810. Yours truly, Parklane Homes

Ross Hanson, CA, MBA Chief Financial Officer CC: Brian Crowe, Assistant City Engineer, City of Vancouver Ken Carrusca, Division Manager, Integrated Planning Division, Metro Vancouver

Application by River District Energy Limited Partnership

for a Certificate of Public Convenience and Necessity

July 27, 2011

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River District Energy

Application to the BC Utilities Commission for a Certificate of Public Convenience and Necessity

District Energy Utility at the River District, Vancouver

CPCN Application

Submitted to

British Columbia Utilities Commission

Submitted to: Submitted by: British Columbia Utilities Commission

RE: District Energy Systems

Sixth Floor, 900 Howe Street Box 250

900 Howe Street Vancouver, BC

V6Z 2N3

Attention: Commission Secretary

River District Energy Ltd Suite 2000 – 1055 Dunsmuir Street Vancouver, BC V7X 1L5 Main Contact: Ross Hanson, Chief Financial Officer Direct (604) 648-1810 Cell (604) 690-9530 [email protected]

mailto:[email protected]

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Contents

1 Executive Summary ................................................................................................................. 5

2 Applicant .................................................................................................................................. 7

2.1 Name, address and nature of business .............................................................................. 7

2.2 Financial capacity ........................................................................................................... 10

2.3 Technical capacity .......................................................................................................... 10

2.4 Name, title and address of contact ................................................................................. 11

2.5 Name, title and address of legal counsel ........................................................................ 11

2.6 Project team .................................................................................................................... 12

2.7 Regulatory process ......................................................................................................... 14

3 Project Need, Alternatives and Justification .......................................................................... 15

3.1 Project history ................................................................................................................ 15

3.2 Project build out schedule and load analysis .................................................................. 16

3.3 Screening analysis of alternative technologies............................................................... 20

3.4 Summary of preferred alternative .................................................................................. 23

3.5 Financial modeling and inputs ....................................................................................... 24

3.6 Capital structure ............................................................................................................. 34

3.7 Depreciation rates ........................................................................................................... 34

3.8 Income taxes ................................................................................................................... 35

3.9 Revenue requirements .................................................................................................... 35

3.10 Levelized rate proposal .................................................................................................. 35

3.11 Rate design ..................................................................................................................... 36

3.12 Rate stabilization account............................................................................................... 37

3.13 Rate benchmarks ............................................................................................................ 37

3.14 Financial projections ...................................................................................................... 38

3.15 Sensitivity analysis ......................................................................................................... 39

4 Public consultation ................................................................................................................. 40

4.1 Community ..................................................................................................................... 40

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4.2 First Nations ................................................................................................................... 41

4.3 Other stakeholders .......................................................................................................... 41

5 Project Description ................................................................................................................. 44

5.1 Overall project ................................................................................................................ 44

5.2 Project phasing ............................................................................................................... 45

5.3 System components ........................................................................................................ 47

5.4 Implementation schedule................................................................................................ 51

5.5 Human resources requirements ...................................................................................... 52

5.6 Risk analysis ................................................................................................................... 52

5.7 Environmental and social impacts.................................................................................. 54

5.8 Permits and approvals .................................................................................................... 55

6 Project Cost Estimate ............................................................................................................. 56

6.1 Project cost assumptions ................................................................................................ 56

6.2 Project capital cost budget.............................................................................................. 57

7 Provincial Energy Policy Considerations ............................................................................... 58

8 New Service Areas ................................................................................................................. 60

8.1 Areas within Vancouver ................................................................................................. 60

8.2 Areas within Burnaby..................................................................................................... 60

9 Appendices ............................................................................................................................. 62

9.1 Appendix 1 - Financial statements of Parklane .............................................................. 62

9.2 Appendix 2 - Public consultation chronology and examples of materials ..................... 63

9.3 Appendix 3 – DEU Information for developers ............................................................. 67

9.4 Appendix 4 - Letters of support ..................................................................................... 85

9.5 Appendix 5 - Technical studies ...................................................................................... 87

9.6 Appendix 6 - Financial model ........................................................................................ 88

9.7 Appendix 7 - DEU system designs ................................................................................ 91

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1 Executive Summary River District Energy Limited Partnership (“RDE”) is seeking a Certificate of Public Convenience and Necessity (“CPCN”) to construct and operate the District Energy Utility (“DEU”) to serve the River District of Vancouver, which is being developed by RDE’s affiliate Park Lane Ventures (1986) Limited Partnership.

The DEU will be developed in phases to efficiently match capital investment with community development and provide flexibility for transitioning to alternate heat sources:

• Buildings will be connected to the DEU via an energy transfer station (“ETS”) located in each building and owned by RDE. A hot water distribution piping system (“DPS”) will connect the natural gas Energy Centre (“EC”) to the ETS in each building.

• Early building loads will be served by a temporary EC that will be transitioned to a permanent EC containing gas-fired boilers.

• Once load reaches a sufficient threshold the current plan is to construct a pipeline to convey waste heat from Metro Vancouver’s Waste to Energy Facility (“WTEF”) approximately 4.5 km to the east of River District in Burnaby to a Renewable Energy Transfer Station (“R-ETS”) on the eastern edge of the River District.

When the community is built out the DEU will reduce annual GHG emissions by approximately 8200 tonnes, and electricity consumption by 22.2 GW.h, relative to the business-as-usual approach to heating and providing domestic hot water to multi-family residential buildings in Vancouver. The project aligns well with the Provincial Government’s green energy objectives under the 2007 BC Energy Plan and the Clean Energy Act.

The River District is located on former industrial lands along the Fraser River in southeast Vancouver. The development will be built to high social and environmental standards. It will ultimately include approximately 710,000 m2 of floor space (~55 legal parcels), consisting mostly of residential uses, with some smaller amounts of retail, office and community uses. The DEU will serve all economically connectable loads in the River District. It is also anticipated that several parcels owned by the City of Vancouver west of Kerr Street will be connected when they are redeveloped.

The first buildings to connect will be two apartment buildings on Parcel 7 and marketed as New Water. The builder, Polygon Homes, will commence construction in August 2011 and will be calling for construction heat in February 2012 with occupancy scheduled for summer 2012.

The design work on the DEU is underway and portions of the DPS installation have been completed to take advantage of other infrastructure development for the site.

This CPCN Application has been prepared for a stand-alone DEU to service all of River District and several city-owned properties to the west. RDE is currently working in close cooperation with Metro Vancouver to negotiate an MOU for the terms, conditions and pricing for waste heat from the WTEF. These discussions include strategies to reduce the costs of waste heat from the WTEF and advance the pipeline timing.

There may be opportunities to increase the size and change the alignment of the pipeline to serve additional loads in Burnaby. It is expected these opportunities will be considered as incremental business cases during

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the detailed design phase, once the general parameters of the heat supply contract have been developed with Metro Vancouver. RDE has also identified several options to serve River District in the event it cannot negotiate an acceptable supply agreement with Metro Vancouver or secure suitable rights of way through Burnaby.

It is anticipated that Metro Vancouver will own and operate the waste heat capture equipment at the WTEF and the pipeline to the River District and that the rate for heat sales to RDE will recover costs allocated to this project, net of any grants or other considerations. The long-term supply solution is provided in this Application only for context. RDE is seeking a levelized approach to rates that reflects competitive pricing benchmarks and will file updated capital plans and rates once initial infrastructure is developed and the costs and terms of the heat supply from the WTEF can be confirmed.

This CPCN Application was developed in accordance with the 2010 CPCN Application Guidelines. It was also prepared with reference to recent Commission decisions for DEUs serving Dockside Green in Victoria and UniverCity in Burnaby.

RDE would be the utility services provider responsible for system operations and maintenance, emergency response, and billing and customer care functions. The rates were developed using a cost of service model and financial structure consistent with that implemented by other regulated utilities in British Columbia.

Section 2 – “Applicant” provides information about RDE, its technical and financial capacity, the project team and an overview of the regulatory process proposed for this project.

Section 3 – “Project Need, Alternatives and Justification” includes information about the project, its purpose, the initial feasibility study (including alternative sources of heat considered) and the results of the financial and technical analysis of the selected technical concept compared with business-as-usual heating costs. This section also provides an overview of the expected ownership and cost of waste heat from the WTEF and various sensitivity analyses.

Section 4 – “Consultation” focuses on the stakeholder consultation process conducted to date. Samples of related material developed for the consultation process are included in Appendices.

Section 5 – “Project Description” provides a detailed technical description of the project and an overview of the project implementation process.

Section 6 - “Project Costs” - in addition to the summary of the project costs provided in Section 3, this section includes a more detailed breakdown of the capital costs and an overview of the feasibility assessment assumptions.

Section 7 – “Provincial Government Energy Objectives and Policy Considerations” – addresses British Columbia’s Energy Objectives and the project’s impact on the environment.

Section 8 – “New Service Areas” includes information about potential new energy loads to be serviced by the DEU.

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2 Applicant

2.1 Name, address and nature of business

River District Energy Limited Partnership (“RDE”)

RDE has been formed to develop and own the District Energy Utility (“DEU”) to provide energy for heat and domestic hot water to the master planned community formerly known as the East Fraser Lands and now being marketed as The River District. RDE intends to operate the DEU but will contract areas of operations to qualified third parties. RDE has as its general partner, River District Energy Ltd. River District Energy Ltd is a company incorporated under the laws of the Province of British Columbia, registration number 0897151.

Park Lane Fraser Lands Limited Partnership (“Fraser Lands LP”)

Fraser Lands LP is the beneficial owner and developer of the lands comprising the River District development. Fraser Lands has as its general partner, Park Lane EFL Developments Ltd.

Park Lane Ventures (1986) Limited Partnership (“Park Lane (1986) LP”)

Park Lane (1986) LP is the land development unit of the Parklane Group of companies. It acquires and develops land for use by its building and marketing affiliate, Park Lane Homes, or for sale to third parties. Park Lane (1986) LP has as its general partner, Park Lane Ventures Ltd.

Park Lane Homes Limited Partnership (Park Lane Homes LP)

Park Lane Homes LP designs, constructs and markets homes under the Parklane brand on land it acquires from its affiliates or purchased from third parties. Park Lane Homes has as its general partner, Park Lane Housing Ltd.

Collectively Parklane (1986) LP, Park Lane Homes LP and their respective subsidiaries are known as the Park Lane Group “Parklane”. All Parklane affiliates have as their business address 2000 – 1055 Dunsmuir Street, Vancouver, BC. V7X 1L5

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The ownership structure of RDE within Parklane is depicted in Figure 1 below.

Park Lane Ventures (1986) Limited

Partnership

Park Lane Fraser Lands Limited

Partnership

River District EnergyLimited Partnership

Park Lane Ventures Ltd.

Park Lane EFLDevelopments Ltd.

River District Energy Ltd.

GP Interest

GP Interest

GP Interest

100%

100% 100%

100%

Figure 1 - RDE Ownership structure

About Parklane

Parklane commenced operations in 1981 and is an integrated land development and residential building and marketing company with operations throughout the BC lower mainland.

Parklane’s focus is on creating master planned communities. Recent projects include Bedford Landing in Fort Langley, a collection of approximately 500 detached houses, townhouses and apartments, and Heritage Woods in Port Moody, consisting of 1300 single and multi family homes. Parklane has been the recipient of over 200 local, provincial, national and international awards including being named best builder at the provincial and national levels. Parklane was again named Canada’s Best Builder for 2011 by the Canadian Homebuilders Association. The firm is frequently cited as great place to work and in the last 6 years has received 9 provincial and national awards, including 3 as one of Canada’s top 100 Employers.

Parklane is among a group of companies with shared ownership that operate in diverse industries ranging from commercial land development and building ownership, instrumentation and testing services for oil and gas companies, investment banking, transportation and third party logistics management.

About the River District and the DEU

The River District is located in southeast Vancouver on 130 acres. Parklane owns 126 acres with approximately 7.5 million square feet of buildable density. The River District will be built to high environmental and social standards. It will include offices, shops and restaurants, two school sites, four

Park Lane Group

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daycares, a community centre and be home to approximately 15,000 residents. Buildings constructed will target LEED Gold. Approximately 1.2 million square feet of density is designated for affordable housing. 25 acres has been set aside for parks including a 1.4 km public walkway along the foreshore. An artist rendering of the completed community is shown in Figure 2 below.

Figure 2 - Artist rendering of the River District

The DEU at The River District will ultimately consist of an Energy Centre (“EC”) equipped with gas-fired boilers, a Renewable Energy Transfer Station (“R-ETS”), Distribution Piping System (“DPS”) and Energy Transfer Stations (“ETS”).

The source of energy will be built in three stages:

1. A temporary EC will be constructed using natural gas boilers to serve the first buildings connected to the system

2. A permanent EC will be constructed using natural gas boilers and sized to serve all of the buildings at The River District, then retained for peaking and backup once the R-ETS is constructed. The temporary EC will be decommissioned.

3. The R-ETS will be constructed once sufficient energy load has been connected to the system to justify the connection to the alternative energy source.

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The anticipated alternative energy source is currently Metro Vancouver’s Waste-to-Energy Facility (“WTEF”) located to the east in Burnaby. The WTEF has been in continual operation since 1988 and processes approximately 280,000 tonnes of the lower mainland’s solid waste each year. Energy will be captured at the facility and supplied to the R-ETS via hot water routed through a 4.5 km parallel deliver-and-return pipeline. It is expected that the energy capture equipment at the WTEF and pipeline will be owned and operated by Metro Vancouver and the energy will be supplied to RDE under long term contract.

2.2 Financial capacity Funding for the development and operation of RDE will be provided by Parklane and conventional bank sources. As of Parklane’s most recent year ended December 31, 2010 the group had revenues of $96 million and assets of $188 million. The group has been consistently profitable throughout its history.

Parklane maintains ongoing banking relations with four of the largest Tier 1 banks in Canada. Parklane intends to fund the development of the DEU from its own resources until the permanent EC is constructed in 2014. At that time Parklane will make application for conventional financing from a Canadian chartered bank.

If required to secure financing for RDE, loan covenants are available from affiliates, including Wesgroup Properties Limited Partnership (“Wesgroup”). Wesgroup is a privately owned firm engaged in commercial, retail and institutional development for its own portfolio or for sale to third parties. As of the most recent fiscal year ended December 31, 2010 Wesgroup and its affiliated entities had assets exceeding $600 million.

Financial statements for Parklane’s most recent fiscal year ended December 31, 2010 are referenced in Appendix 9.1 and have been provided in confidence under separate cover.

2.3 Technical capacity Parklane has retained third party experts to assist with the development of the DEU. These firms are described in the Project Team section of this application and include FVB Energy Inc (“FVB”), Compass Resource Management Ltd (“Compass”) and Owen Bird Law Corporation. Parklane’s Chief Financial Officer is directly responsible for project management and its President, Peeter Wesik, is the project sponsor.

Parklane has significant in-house design and construction management expertise with professional engineers, technicians and architects on staff. The firm is committed to improving its in-house capacity for developing and managing the RDE DEU. Ms. Robin Petri,PEng, joined the firm in 2010 as the Director, Land Development for the River District and is responsible for overseeing the design, tendering and construction of all site services and DEU infrastructure. Ms. Petri was most recently with the City of Vancouver where she was responsible for site services for the Southeast False Creek and the Olympic Village.

Senior engineers from The City of Vancouver’s Neighbourhood Energy Utilities group have provided technical expertise. The key individuals responsible for the design, construction and operation of the City’s Southeast False Creek NEU have reviewed the RDE system designs and shared energy consumption data for

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buildings connected to the SEFC NEU. The input has been reflected in designs issued for tender and in the financial model included in this CPCN application.

FVB established the design standards for the temporary EC and Parklane is currently reviewing submissions received from qualified firms invited to respond to a request for proposals. Operation of the temporary EC during the initial years will be performed by the firm contracted to design, construct and commission the facility. The selected firm will also be responsible for obtaining an operating permit and maintaining compliance with the BC Safety Council standards.

Customer billing and inquiries will be performed under contract by Wesgroup’s property management group. The group provides comprehensive building maintenance and customer support for approximately 400 commercial and residential tenants.

2.4 Name, title and address of contact Communication with the applicant should be addressed to: Ross Hanson, CA, MBA Chief Financial Officer Parklane Group 2000 – 1055 Dunsmuir Street Vancouver, BC V7X 1L5 Phone: (604) 648-1800 Fax: (604) 648-2868 E-mail: [email protected]

2.5 Name, title and address of legal counsel

DEU legal advisor

Christopher Weafer, LLB Shareholder Owen Bird Law Corporation 2900 595 Burrard Street Vancouver, BC. V7X 1J5 Phone: (604) 691-7557 Fax: (604) 688-2827 E-mail: [email protected]

Corporate counsel:

Barbara Vanderburgh, LLB Partner



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Fasken Martineau Dumoulin LLP 2900 – 550 Burrard Street Vancouver, BC V6C 0A3 Phone: (604) 639-4937 Fax: (604) 631 3232 E-mail: [email protected]

2.6 Project team

Key external members of the RDE project team include:

Compass Resource Management Ltd (“Compass”)

Primary contact: Trent Berry, Partner

Compass is a team of research and consulting professionals dedicated to improving both the quality of policy and management decisions and the decision making capacity of citizens, organizations and governments. The firm specializes in policies, projects and plans related to the management of natural resources, technology, and human health. Compass is a Canadian-based company with projects and experience worldwide. The firm has worked in virtually all facets of the energy industry. In recent years, Compass has completed business cases, and/or supported implementation and business planning for several dozen district energy systems including Southeast False Creek Neighbourhood Energy Utility (Vancouver), UniverCity Neighbourhood Utility Service (Burnaby), Yellowknife District Energy System, Revelstoke Energy, as well as several proposed systems in Seattle, Portland, Richmond,

City of VancouverSpecial Advisors

Fasken MartineauCorporate Counsel

Peeter WesikProject Sponsor

Ross HansonProject Manager

Compass Business Planning

Owen BirdLegal Counsel

Robin Petri, PEngTendering & Construction Management

FVB EnergyEngineering &

Design

WesgroupCustomer Care &

BillingMarnie Stariha

Regulatory Filings


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Victoria, and Squamish. Mr. Berry was a member of a group of external experts that advised the Province of B.C. on its 2007 Energy Plan, and supported the implementation of a variety of energy policies arising from the Plan.

Please see www.compassrm.com for curriculum vitae on the firm and its principals

FVB Energy Inc. (“FVB”)

Primary contact: Jim Manson, Partner

FVB helps organizations create, operate and grow energy utility enterprises, as for-profit businesses or to cost-effectively serve the needs of non-profit institutions. It serves energy companies, educational campuses, health care centers, municipalities, building developers and industrial plants. FVB Energy operates in 38 US states, 12 Canadian provinces or territories and 21 countries. The firm has played a major role in the growth of the district energy industry and provided consulting services for most of the new district cooling and district heating systems developed or under development in North America since 1990.

Please see www.fvbenergy.com

City of Vancouver (the “City”)

The City has made available its senior staff responsible for the development and operation of the City’s Southeast False Creek neighbourhood energy utility (“SEFC”). SEFC commenced operations in 2009 and uses sewer heat recovery to supply energy for heating and DHW to the neghbouring development which will comprise 5.6 million and 1.0 million square feet of residential and commercial density, respectively. SEFC uses rate setting, costing and accounting principles which closely follow those used by regulated utilities in BC.

Additional design and engineering

The DEU system components are consistently designed to integrate with conventional site services. The firms responsible for other interfacing elements of site services include:

• InterCAD Consulting Engineers Site services design

• Ausenco Sandwell

Sanitary sewer design

• Moffat & Nichol Foreshore engineering design

http://www.compassrm.com/

http://www.fvbenergy.com/services/energy_companies.cfm

http://www.fvbenergy.com/services/ed_fac.cfm

http://www.fvbenergy.com/services/health_center.cfm

http://www.fvbenergy.com/services/municipal.cfm

http://www.fvbenergy.com/services/developers.cfm

http://www.fvbenergy.com/services/indust_plants.cfm

http://www.fvbenergy.com/

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2.7 Regulatory process In June 2010, Parklane met with a BCUC staff member to advise of its intention to undertake the development of the DEU at the River District. In April 2011, Parklane met with several BCUC staff members to provide an update on the project.

In this Application RDE is seeking:

1. A Certificate of Public Convenience and Necessity under Sections 45 of the Utilities Commission Act (“Act”) for the construction and operation of RDE’s proposed community based DEU at the River District, Vancouver, BC.

2. Approval under sections 56, 60 and 61 of the Act of the proposed revenue requirements, rate design and rates for the initial five year period as described in the Application:

a. The rate base described in Section 3.14 of the Application

b. The revenue requirements described in Section 3.9 which include:

i. A deemed capital structure of 60% debt and 40% equity

ii. Debt financing costs estimated at 6%

iii. A Return On Equity (“ROE”) of 10%, based on the current FortisBC ROE that serves as a benchmark for public utilities, plus a premium of 50 basis points

iv. Operating costs as provided in Section 3.5.3

v. A 20-year levelized rated structure in which RDE defers a portion of its annual revenue requirements during the initial years in order to provide affordable customer rates

c. Approval of the accounting treatment of:

i. A rate stabilization account which serves to record shortfalls in the recovery of revenue requirements in the early years with the goal of complete recovery over the 20-year levelizing period.

ii. The rate design in Section 3.11

In this Application, RDE is only seeking approval of the projected rate base, revenue requirements, rates and rate stabilization account associated with the first five years of operation, which includes construction of DPS and ETS, as well as the temporary and permanent EC to serve the initial development parcels. The long-term business plan, which includes the full expected DPS and ETS assets, boiler capacity, and the pipeline to Metro Vancouver’s WTEF, is presented as context for this Application, in particular as context for the proposed levelized rates, rate stabilization account and long-term benefits of the project. The approach to levelized rates is consistent with the approach to other new district energy systems approved by the Commission (UniverCity, Dockside Green). RDE intends to file an updated capital plan and projections within five years of commercial operation or when a major addition to capital assets is required, whichever is sooner.

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3 Project Need, Alternatives and Justification

3.1 Project history In November 2006, Vancouver City Council unanimously approved the East Fraserlands (now River District) Official Development Plan (“ODP”). Section 5, Environmental Strategies outlined a series of environmental initiatives to be considered in order to contribute to sustainable community objectives. Section 5.2.1 c) recommended “subject to investigating technical feasibility and financial viability at the time of re-zoning, implementing a community-wide heat source and system strategy such as ground source, bio-mass, sanitary sewer heat recovery, solar hot water, and waste heat recovery is to occur.” Following approval of the ODP, Parklane partnered with the City of Vancouver to sponsor a study on the feasibility of a District Energy Utility (“DEU”) for the River District, similar to studies conducted for the City to determine the feasibility of the NEU for Southeast False Creek, which was subsequently developed by the City.

In September 2007, Compass Resource Management and FVB Energy completed an initial feasibility study for a DEU to supply the River District. This study included an analysis of loads, screening of potential heat sources, assessment of heat distribution alternatives, and financial analysis of the DEU. The initial feasibility study assumed a stand-alone utility with its own management, insurance and working capital requirements. The technical analysis examined the full development build out. For simplicity, the financial model for the initial feasibility study focused only on rezoning Areas 1 and 2 of the development. A wide range of possible heat sources were considered including groundsource heat pumps, sewer heat, biomass and waste heat from the Metro Vancouver WTEF in Burnaby.

Metro Vancouver is the new name of the Greater Vancouver Regional District or GVRD. The Metro Vancouver WTEF is also referred to in some documents as the Burnaby Waste Incinerator or BWI.

The Metro Vancouver WTEF was selected as the preferred alternative and used in the base case analysis. A biomass plant using local woodwaste, including waste residues from City parks, was considered as the next best alternative in terms of GHG emissions and costs.

On September 16, 2008, following public hearing City Council gave third reading to the Area 1 Rezoning for the River District. The Area 1 rezoning included the following provisions with respect to a DEU:

• Building design is to include provision of connections to, and be compatible with, the proposed DEU.

• Buildings shall, upon implementation of the DEU, connect to the system for provision of all building heating and domestic hot water services. Exceptions, however, may be granted by the City Engineer on a case by case basis for the use of solar systems to generate heat energy or equipment to acquire waste heat energy from the refrigeration or cooling system of a building for the purpose of supplementing the heat energy provided by the Neighbourhood Energy Utility.

• Provide compatible, energy efficient design and details of the in-building heating and domestic hot water for the connection to the proposed DEU.

Similar provisions were included in the Area 2 rezoning enacted by City Council on December 10, 2010. Parklane engaged Compass and FVB to update certain assumptions in 2009 and 2010 as part of discussions with the City on the viability and approach to the DEU during the Area 2 rezoning process. Metro

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Vancouver also conducted additional analyses to verify assumptions about the amount and cost of heat available from the WTEF used for the initial feasibility analysis.

During the initial feasibility stage, the analysis was performed to be applicable to either public (eg. City of Vancouver) or private ownership. In early 2010, the City informed Parklane that it did not want to develop or own the DEU but still wanted to see a DEU serve the River District based on the earlier feasibility study and updates, and to secure the GHG reductions and other community benefits associated with the DEU.

In April 2010, Parklane issued a Request for Expressions of Interest from qualified providers with the desire, expertise and capability to develop and operate the DEU subject to an updated business case. Following review of the submissions and meetings with the proponents, Parklane decided to proceed on its own with the development of the DEU, in part due to the near-term development timeframes and close linkages between the DEU development and other site servicing plans being led by Parklane. Parklane subsequently engaged Compass and FVB to assist in detailed design of the initial phases and to update and expand the business case to reflect latest design assumptions and costs, and the full build out of the DEU.

3.2 Project build out schedule and load analysis The River District will encompass approximately 710,000 m2 of developed floor space (~55 legal parcels), consisting mostly of residential uses, with smaller amounts of retail, office and community uses.

The DEU will serve all economically connectable loads in the River District. The River District includes 11,500 m2 of townhomes to be built on parcels 2, 4 and 6. A separate analysis was conducted of the costs to connect these 77 townhomes, including a secondary ETS for each townhome. This analysis found that the high fixed costs of connection would outweigh any potential benefits from adding these loads. Given that the townhomes represent a small portion of total potential loads and will be built relatively early in the development of the DEU, we have excluded these townhomes from the system design and financial analysis. However, the townhomes will be designed so that they may be connected at a future date. The City has accepted this approach

The base case load forecast also includes future expected development across Kerr Street (outside the River District development area) on parcels currently owned by the City of Vancouver. The City agrees with the inclusion of these parcels as potential utility customers. Table 1 summarizes the expected floor area that will be connected to the DEU by build out.

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Table 1: Base Case Projection of Floor Area Connected to the DEU by Build Out

m2 Live / Work 24,900 Row house 52,728 Low rise wood frame 306,270 Mid rise 132,026 High rise concrete 142,771 Retail 23,350 School / Community Centre 15,432 West of Kerr – CoV Buildings 12,630 Total 710,107

Energy use intensity factors (“EUIs”) were developed for the different building “archetypes” as part of the initial DEU feasibility study in 2007. These EUIs were derived from a load analysis conducted by Sheltair/FVB for a feasibility study of the DEU that now serves SEFC, which includes Vancouver’s Olympic Village.

Thermal end-use demand was originally estimated for each building archetype using the DOE 2.1-E model under weather and other input assumptions relevant to Vancouver. Buildings were assumed to exceed the requirements of ASHRAE 90.1-2001 by 20%, the applicable building code for Vancouver at the time. Following the original feasibility study, the City adopted ASHRAE90.1-2007 in 2009. The City expects to adopt ASHRAE 90.1-2010 sometime next year, although no formal commitment has been made. The City expects that going forward EUIs could be up to 10% lower under ASHRAE 90.1-2010. Given the possibility of higher building performance in the future, the EUIs from the original feasibility study have been reduced by 5% overall in the financial model for this Application.

Table 2 compares the EUIs (space heat plus domestic hot water) developed for the 2007 feasibility study with the 5% reduction EUIs used in this Application, as well as EUIs anticipated under ASHRAE 90.1-2010. Table 2 also shows actual metered consumption for one recent project in SEFC, which was built to a high performance standard.

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Table 2: Comparison of Heating EUI Assumptions (Annual Space Heat + Domestic Hot Water)

River District Feasibility

River District CPCN

Expected EUIs Under ASHRAE 90.1-2010 SEFC (Actuals)*

Live/Work 88 84 Row house 77 73 Low rise 97 92 Mid rise 108 103 97 111

Hi rise concrete 108 103 97 Retail 50 48 30

Office 66 63 65 School/Centre 64 61

*Based on actual metered DEU consumption for a mid-rise development in SEFC (estimated 90% occupancy) over two years, adjusted for average weather.

The detailed space heat, domestic hot water (“DHW”) and peak load EUIs used for the purposes of this Application are shown in Table 3. Demand for DHW is assumed to be fully diversified, so peak loads reflect space heat peak demand only. A further diversification factor of 85% is applied to space heating peak demands for estimating the diversified peak demand of the DEU.

Table 3: Detailed Base Case EUIs Used in this Application

Space Heat kWh / m2 DHW kWh / m2 Peak W / m2

Live/Work 54 30 55 Row house 43 30 40 Low rise 62 30 40 Mid rise 73 30 45 Hi rise concrete 73 30 45 Retail 34 14 30 School/Community Centre 41 20 55 West of Kerr - CoV Buildings 70 30 48

For the purposes of this Application, Parklane has elected to reduce the EUI assumptions from the original feasibility study, with annual energy use reduced by 5%, for the following reasons:

1. The ASHRAE 90.1-2010 EUIs represent an ideal outcome for an “average” building. They account for no variability in performance arising from different uses within an archetype (e.g., retail is a diverse category and actual energy use will vary between stores and restaurants), building-specific design and construction practices (e.g., higher fraction of glazing), long-term equipment maintenance, or occupant behaviour. They also do not include allowances for amenities such as pools or fitness centers, which can greatly increase total energy use but are difficult to forecast at this stage of planning.

2. No formal commitment has yet been made by the City to adopt ASHRAE 90.1-2010.

3. Future changes in EUIs will affect potential revenues but also future design and capital cost assumptions. Capital cost estimates in this analysis contain a level of conservatism as this EUI

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adjustment was made after the capital costs were prepared and based on slightly higher assumption of energy demand.

While efficiency standards have increased in B.C. and Vancouver, and technical innovation in materials has been significant, this has not translated into lower actual energy consumption in buildings according to a recent building audit conducted for BC Hydro and the City of Vancouver.1 Figure 3 illustrates the wide variability in actual building performance. Figure 3 summarizes the actual energy use intensity for space heat from 38 multi-unit residential buildings located in the Lower Mainland by year built. The data shows the trend in energy use has been flat or upwards in terms of space heating requirements (normalized for floor area).

Figure 3: Actual Space Heating Energy Use by Building Age in Vancouver

The River District is anticipated to have a 23 year development period, with full build out by 2034. A summary of the development schedule used for the business case is shown in Table 4 below. As shown in Section 5.2.1, the River District will generally be developed from west to east, in roughly four key phases of 5 – 6 years each.

1 RDH Building Engineering Ltd. 2009. Energy Consumption and Conservation in Mid and High Rise Residential Buildings in British Columbia. Report #1: Energy Consumption and Trends. Prepared for CMHC, City of Vancouver, BC Hydro, Terasen Gas, and HPO.

0

20

40

60

80

100

120

140

1972

1974

1976

1978

1980

1982

1984

1986

1988

1990

1992

1994

1996

1998

2000

2002

2004

Year Built

Spac

e H

eat C

onsu

mpt

ion

- kW

h/m

2

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Table 4: Summary of development schedule

2012 2014 2016 2018 2020 2025 2030 2035 Connected m2 Live/Work - - - - - 23,706 24,900 24,900 Row house - - 2,377 2,377 2,377 12,142 22,719 52,728 Low rise 14,489 48,890 68,352 81,359 92,117 121,100 180,162 306,270 Mid rise - 12,641 24,601 27,436 30,967 63,651 109,330 132,026 Hi rise concrete - - 5,279 12,479 21,116 89,805 130,680 142,771 Retail - - - 11,083 11,083 16,750 23,350 23,350 School / CC - - - - - - 8,000 15,432 West of Kerr - - - - - 7,017 12,630 12,630 Total 14,489 61,531 100,609 134,733 157,660 334,171 511,771 710,107 MW.h sales 1,335 5,802 9.538 12,293 14,533 31,272 47,829 65,666 Peak MW 0.5 2.2 3.6 4.7 5.5 12.2 18.7 25.7

Parklane conducted sensitivity analysis of the effect of additional load reductions without a commensurate change in future system design or capital costs to reflect lower loads. These results are summarized in Section 3.15 below. Parklane will monitor actual performance of buildings in SEFC and the River District, and trends in building standards. Adjustments to forecast loads will be made as required during detailed design and costing of future phases of the DEU.

3.3 Screening analysis of alternative technologies2 During the initial feasibility study completed by Compass and FVB in September 2007, a wide variety of heat source options were screened. District cooling was not considered because of the high percentage of residential uses and lack of significant cooling penetration expected in residential units.

The study considered four alternative heat sources:

1. Sewer heat recovery (as used in Southeast False Creek) 2. Geothermal

2 Additional details on the screening analysis can be found in the original feasibility study: Compass Resource Management. September 2007. Business Analysis for a Neighbourhood Energy Utility. Prepared for City of Vancouver and Wesgroup.

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a. Ground-water with Heat Pump b. Ground-source with Heat Pump

3. Biomass (using wood residues or pellet fuels) 4. The Metro Vancouver WTEF located in Burnaby

The Fraser River was excluded from consideration as a source of heating or cooling because of anticipated regulatory issues.

In general, the selected alternate energy technologies provide energy at a lower annual fuel cost but have higher initial capital costs than conventional sources of heat such as natural gas boilers. Because of the higher capital costs, high utilization of any alterate energy capacity is required to achieve lower unit costs. The optimal sizing and timing of the alternate energy capacity is dependent upon the total load and load profile. The screening assumed an alternative energy system sized to approximately 25% of the peak load, which could provide up to 75% of annual energy requirement. Natural gas boilers are used for peaking and back-up (~25% of annual energy).

For initial screening, the levelized cost of each technology option (baseload + peaking gas) was compared for a target heating load of ~50,800 MW.h/year (~20MW peak), equivalent to the expected loads by the end of Phase 2 . For this target load, the alternative energy system was sized at 5 MW, with peaking natural boilers of 21 MW. For reference, a system based entirely on natural gas was also included in the comparisons. Figure 4 summarizes the initial screening results. The costs are for energy supply only (to rank resource options) and do not reflect the costs of distribution or energy transfer stations.

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Figure 4: Original Screening of Different Energy Sources (Levelized Annual Costs)

Following the preliminary economic screening of all of the plant alternatives above, the more detailed business analysis was confined to two alternatives for alternate technologies: 1) waste heat from Metro Vancouver’s WTEF located in Burnaby, and 2) biomass using wood residues (e.g., from City parks and local sawmills). These were shown to be the most promising alternatives in terms of both costs and environmental benefits. The WTEF was shown to have higher costs than biomass under the assumptions used in the initial screening, but was still lower in cost that the various heat pump options. In addition, opportunities were identified that could further reduce the relative costs of the WTEF in the more detailed analysis.

During the more detailed business analysis, it was determined that a district energy system utilizing waste heat from Metro Vancouver’s WTEF in Burnaby was viable and, under the updated assumptions available for the study, would actually be preferable to biomass. During the screening analysis of the WTEF, FVB initially developed costs based on a 5 MW steam condenser and a 200 mm pipeline. However, in subsequent discussions, FVB found it may be possible to increase the capacity of this alternative to 10 MW by increasing the size of the steam condenser (for an incremental cost of $1 million) with no change in pipeline diameter if the target delta T can be achieved. Further analysis determined that the reduced use of natural gas in the DEU would more than offset the incremental cost of $1 million estimated by FVB for the 10 MW sizing. The net impact of these changes reduced the cost of the WTEF relative to biomass, although biomass remained a viable fall back option. The WTEF alternative also results in a larger reduction in GHG emissions, as a result of the higher amount of natural gas displaced in this alternative.

Following the initial feasibility study, Metro Vancouver confirmed the assumptions in that analysis. After Parklane decided to proceed with the development of the DEU, Metro Vancouver then conducted additional study and design. As described further below, the total cost of the WTEF portion of the project has increased. Parklane and Metro Vancouver are currently examining options to reduce or reallocate some of these additional costs.

-500

1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500

All Gas GSHP GWHP Sewer HP Biomass -Wood Waste

Biomass -Pellet

WTEF

thou

san

ds

$20

07

Annual Operating Annual Fuel Levelized Capital

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3.4 Summary of preferred alternative The technical details of the anticipated system design are described elsewhere in this Application. Briefly, the key features of the proposed project that inform the financial model and rate setting are as follows:

1. A temporary natural gas boiler plant will be used to supply heat to loads for the first 2 years of development (under base case development rates).

2. A permanent natural gas boiler plant will be installed in Year 3 near the Phase 1 loads. This permanent plant will provide full heat supply until the load reaches an economic threshold to support construction of the pipeline to the WTEF in Burnaby. Once the pipeline to the WTEF is completed, the permanent natural gas boiler plant would continue to provide peaking and back-up support to the River District Energy DEU.

3. The WTEF concept would involve installing equipment at Metro Vancouver’s existing WTEF, located approximately 4.5 km from the eastern edge of the River District, to extract up to 10 MW of heat capacity.3 Heat would be extracted from the existing steam turbine. Heat extraction equipment would be housed in the existing WTEF. Waste heat from the WTEF can be extracted at a useable temperature for the DEU.

4. A heat exchanger would transfer the extracted energy to a separate closed hot water loop that would transport hot water from the WTEF to a second heat exchanger located in a Renewable Energy Transfer Station (R-ETS) at the eastern edge of the River District development for distribution within the River District. At buildout, the WTEF could supply ~87% of the River District’s annual thermal energy demand.4

5. The pipeline connecting the WTEF and R-ETS would consist of a buried 200 mm two-pipe closed loop (supply and return). A possible route has been identified along North Fraser Way. Much of the proposed pipeline routing would be through light industrial areas. The route is approximately 4.5 km

3 Depending on the achievable delta T, the pipeline and heat extraction equipment could potentially deliver up to 12 MW with no incremental capital costs. To be conservative this Application has assumed a 10 MW pipeline capacity. 4 There is uncertainty around the annual energy supplied by the pipeline. Analysis suggests that the WTEF could supply anywhere from 85% to 93% of annual loads at build out. The Metro Vancouver WTEF can meet a relatively high portion of annual load because there is virtually no turn-down limit associated with this option. In the case of a biomass plant, the plant would have to be shut-down when the load is below a critical threshold relative to the capacity of the biomass system, further limiting the contribution of this alternative to annual energy supply.

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long and would likely require some right-of-way easements. The piping is the largest cost of this alternative.5

6. Under base case development assumptions and with no additional cost reductions or support, the pipeline would be installed in approximately 2027. This may be advanced if the capital costs that must be borne by the customers of River District Energy can be reduced, development occurs more rapidly, or natural gas prices rise above levels assumed in the base case analysis. It is RDE’s desire to connect to a low-carbon heat source as soon as it is economically feasible.

7. Currently, Metro Vancouver anticipates it would own and operate the heat extraction equipment at the WTEF and the pipeline. The capital cost of these components is excluded from the long-term projections. Instead, a rate is estimated for the heat delivered to the River District R-ETS that covers Metro Vancouver’s operating costs, capital carrying costs (based on the anticipated economic life of equipment and Metro Vancouver’s long-term debt rate) and foregone electricity revenue.6

8. Only the expected capital and operating costs for the first five years of operation are included in this Application. A levelized approach to rates is proposed and initial rates are based on other benchmarks. The required escalation of rates beyond five years to recover deferral account balances will vary depending upon the final technology selection and costs. These are included in this application as context for approval of the Phase 1 system costs and rates.

3.5 Financial modeling and inputs The financial model was used to generate three long-term scenarios reflecting different assumptions about the availability and cost of waste heat from the WTEF.

5 The City of Burnaby has suggested a possible realignment of the pipeline to utilize existing rights of way and serve other potential customers along the pipeline route. These additional costs are not included in the base analysis. In addition, there may be opportunities to serve additional loads in Burnaby along the pipeline route. There is additional heat available from Metro Vancouver’s WTEF. However, the pipeline sizing would need to be increased to serve additional loads along the route. The next available pipe size could transport up to 7 MW of additional supply from the WTEF. The incremental costs and benefits of increasing the pipeline size and altering the routing to serve loads in Burnaby would be considered during the more detailed design and implementation of the pipeline and Parklane expects any incremental costs would be borne by incremental loads along the route. 6 The recovery of heat from WTEF will increase total energy recovery from municipal solid waste but reduce the amount of electricity produced by the facility. The foregone electricity production is included in the opportunity cost of waste heat recovery.

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The reference (base) case assumes the waste heat is available for a levelized rate of $25 per MW.h, which ensures a competitive thermal energy service for River District residents. Metro Vancouver and Parklane are pursuing a variety of strategies to offset the capital costs of the waste heat source and reduce the required rate to this level. With the price of waste heat reduced to $25 per MW.h, it could be economic to install the waste heat pipeline as early as 2017.

The high bookend scenario assumes no grants and allocates the full cost of the waste heat supply to the customers of the River District DEU, including all projected capital costs for the pipeline and heat recovery equipment, as well as operating costs and compensation to Metro Vancouver for reductions in electricity generation at the WTEF. With all costs included, the waste heat supply has a levelized cost of $56 per MW.h, and it is not economical to connect to the WTEF until 2027. The costs of the WTEF portion of the project and strategies being pursued to reduce or reallocate these costs are discussed further below.

The 100% gas scenario assumes the DEU operates indefinitely on natural gas, and excludes any purchases of heat from the WTEF. This is provided as a technically feasible fall back option in the event Parklane, Metro Vancouver and Burnaby cannot negotiate acceptable terms, conditions and pricing for the WTEF alternative, including routing and sizing of the pipeline. In the event an agreement cannot be reached in the next 3 years, Parklane will reconsider other alternative energy sources to supply River District. One of the advantages of the district energy system is the ability to integrate different sources of supply over time.

The capital and operating costs of the River District DEU are identical for the first five years under all three supply scenarios. Only gas boilers and initial DPS and ETS equipment costs are included. A levelized approach to rates is proposed and, as with other new district energy systems, initial rates are set according to competitive benchmarks, which are lower than actual revenue requirements. This is intended to ensure initial customers are not disadvantaged by equipment installed to serve future loads. Parklane proposes to track all under-recoveries and recover these in future years. The financial model includes an allowance for financing under-recoveries. Future rates (beyond five years) will depend in part on actual under-recoveries in the first five years as well as the final selection and pricing of the alternative energy source. Several scenarios are provided as context for this Application.

Unless otherwise indicated, all costs and revenues are in nominal dollars and all energy prices are levelized.

3.5.1 Capital costs DEU reference case capital costs are shown in Table 5 below. Note that this does not include the pipeline and heat recovery equipment costs. The reference case assumption is that Metro Vancouver will own and operate the pipeline as well as the heat recovery equipment at the WTEF . The R-ETS between the DEU distribution system and the waste heat pipeline would be financed by the River District DEU, and is included in the DEU’s capital costs.

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Table 5: Total DEU capital costs (thousands 2011$)

Buildings 367 Energy centre – temp plant 553 Energy centre – permanent plant 6,380 ETS with waste heat pipeline 624 DPS 7,442 ETS 7,156

Subtotal 22,523 Contingency 2,252 Total 24,774

The first five years of nominal capital costs for the reference case is shown below in Table 7. These include interest during construction.

Table 6: Nominal capital costs, 2012 – 2016 (thousands $)

2012 2013 2014 2015 2016 Total, as spent Buildings 0 0 106 0 0 106

Energy Centre 564 0 6,771 0 0 7,335

DPS 1,743 47 48 49 50 1,937 ETS 197 200 204 208 213 1,022 Contingency 250 25 713 26 26 1,040 Interest 83 8 235 8 9 343 Total 2,838 280 8,077 291 297 11,783

Parklane has pursued direct sources of grant funding such as BC Hydro’s Power Smart Sustainable Communities Program which may provide grants to offset DEU capital costs. Parklane may be eligible for as much as $2 million in funding from this program7. As the status of Parklane’s application is not clear, this grant has been excluded from the reference case.

7 Given the payment terms, the present value of this grant is approximately $800,000.

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3.5.2 WTEF waste heat cost The estimated direct capital costs for the waste heat pipeline and the heat recovery equipment at the WTEF are shown in Table 6. For the purposes of estimating rates, depreciation rates of 4% (25 years) and 2.5% (40 years) per year are assumed for the heat recovery equipment and pipeline, respectively.

For the high bookend scenario, the cost of waste heat includes capital costs based on the utility accounting method. The pipeline is depreciated over 40 years and the heat recovery equipment over 25 years, and financing is assumed to be 100% at Metro Vancouver’s cost of debt of 5.25%.

Table 7: Pipeline and heat recovery equipment (thousands 2011$)

Heat recovery equipment 2,200 Pipeline 8,322 Contingency 1,052 Total 11,574

In addition to capital costs, there are also incremental operating costs associated with the scheme. There is also an opportunity cost associated with foregone electricity revenues. Projected operating costs and foregone electricity sales for the waste heat supply are shown in Table 8.

Table 8: Waste heat operating costs

Pipeline maintenance 1% of capital Heat recovery equipment maintenance 3% of capital Pipeline pumping energy 3% of delivered heat Reduced electricity generation 202.2 kW(e) per MW(t)

Metro Vancouver sells electricity generated at WTEF to BC Hydro. The electricity purchase agreement expires in 2013, and Metro Vancouver currently assumes that the future agreement will value electricity at $90 per MW.h in 2014, with 1% nominal escalation per year.

Electricity consumed for pumping in the waste heat pipeline is priced at BC Hydro’s Medium General Service rate.

At Metro Vancouver’s debt rate of 5%, the current full levelized cost of waste heat from the WTEF is $56 per MW.h. The levelized cost of waste heat breaks down as shown in Figure 5.

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Figure 5: Levelized cost of waste heat by component, NPV basis

The reference case assumes a target levelized cost of waste heat from the WTEF of $25 per MW.h. This is the rate that would be necessary to achieve Parklane’s target levelized retail rate of $150/MW.h, as discussed further below.

Parklane and Metro Vancouver are actively exploring a variety of strategies to reduce the cost of the waste heat, advance the timing of the pipeline, and achieve the target levelized DEU retail rate of $150 per MW.h. Strategies include pursuing external grants, allocating some costs to general waste management activities within Metro Vancouver and pursuing low-cost financing of the project. Metro Vancouver has also indicated it will consider offsetting costs for the waste heat consistent with policy for its own projects that reduce GHGs. Parklane applied to the BC Innovative Clean Energy Fund for a $3 million grant in August 2010. . However, on July 22, 2011, Parklane was finally informed its application was not successful. The project may be eligible for a grant and/or low cost loan under the Green Municipal Fund administered by the Federation of Canadian Municipalities. 8

8 Historically, FCM has offered loans of up to $10 million (and up to 20 year terms) combined with grants of up to $1 million. The loans have been offered at rates 1.5% below the comparable Government of Canada bond, with a floor of 2%, compared

$-

$10

$20

$30

$40

$50

$60

$ / MW.h

Reduced Electricity Generation

O&M and Pumping

Capital Charges

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Finally, Parklane will be pursuing a property tax exemption or holiday from the City of Vancouver to help achieve the target DEU retail rate. The present value of property taxes assumed in the pro forma is $800,000 over 20 years. The DEU must compete with other on-site sources of energy that do not attract the same property tax treatment (because they do not involve infrastructure in public rights of way). Other district energy systems in B.C. have been granted exemptions (Dockside Green) or holidays (Lonsdale Energy Corporation).

3.5.3 DEU operating costs Operations and Maintenance costs include the costs for the utility’s employees, training, office equipment and supplies, subcontractors and maintenance and repair services provided by maintenance personnel. All operations and maintenance costs are escalated annually at inflation; estimates below are starting assumptions for 2012 unless otherwise indicated.

Management and staff costs, including overheads, are estimated at $177,000 per year starting with the completion of the permanent EC in 2014. Before the permanent EC, Parklane will rely on a full-service maintenance contract from the supplier of the temporary EC. This contract, plus overheads, has been budgeted at $84,000 per year.

Liability and property insurance costs are budgeted at 0.33% of annual gross revenues.

DPS and ETS maintenance costs are estimated at 1% of up-front capital costs. Non-fuel operating and maintenance costs for the heat plant are initially estimated at $2.99 per MW.h. After the installation of the waste heat pipeline, this will increase to $3.76 per MW.h.

Imputed land rent for the permanent EC and R-ETS is included as an operations and maintenance cost as land costs are not typically depreciated when using the utility accounting method. Land rent is estimated at $135 / m2 on a triple-net basis in 2011, and is escalated at inflation. The calculation is described in Table 10. The temporary EC would not require any significant land area, so no land rent is included during the utility’s first two years of operation.

with the 5.25% debt rate assumed for Metro Vancouver. FCM is not currently taking new applications but their website indicated they will make some announcement on their future funding at the end of July 2011.

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Table 9 - Calculation of EC rent

Gas-fired EC R-ETS TOTAL

Rental base Land & Building &

TI's Land only Size of building (ft2) 7,000 1,600 Hard costs per ft2 130 95 Soft costs per ft2 50 40 Construction cost – Total 1,260,000 217,600 Land area (ft2) 7,000 3,200 Value of land per ft2 50 60 Value of land – Total 350,000 192,000

Total value for rent purposes 1,610,000 192,000 1,802,000 Cap rate

7.1%

Annual rent

127,924 Annual rent per ft2

12.54

Annual rent per m2

135.00

Working capital is estimated as 4% of annual gross revenues, with annual carrying costs equivalent to 2.5% of working capital.

All estimated operations and maintenance costs are escalated at 2% per year for inflation.

Reference case operations and maintenance costs are shown in Table 11.

Table 10: Reference case operations and maintenance costs (thousands $)

2012 2014 2017 2026 2031

Management and staff, plus overheads 84 177 188 224 248

Liability and property insurance 0 2 5 25 45 DPS and ETS maintenance 19 25 55 149 236 Heat plant maintenance and non-fuel ops 4 19 47 184 289 Land rent 0 92 142 170 188 Carrying costs on working capital 0 1 1 6 9 Total Operations and Maintenance Costs 108 316 438 758 1,015

Operations and maintenance costs for the high bookend case are shown in Table 12.

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Table 11: High bookend scenario operations and maintenance costs (thousands $)

2012 2014 2017 2026 2031



Operations and maintenance costs for the 100% gas case are shown in Table 13.

Table 12: 100% gas scenario operations and maintenance costs (thousands $)

2012 2014 2017 2026 2031



3.5.4 Fuel Costs Fuel consumption for the early years of the project, as well as the year of the pipeline connection (2017) and the 15th and 20th years of the project is shown below in Table 14. Natural gas consumption reflects the assumed plant efficiency of 85%. WTEF heat consumption reflects the pipeline transmission efficiency of 91%.

Table 13: Annual fuel consumption (MW.h)

2012 2014 2017 2026 2031

Natural gas 1,634 7,099 0 2,001 6,202 WTEF Heat 0 0 12,565 38,835 52,135 Electricity 27 116 220 712 1,014 Fuel costs are based on best available projections. Natural gas costs are based on a natural gas commodity forecast for BC provided by Sproule. This forecast is through 2021; for years thereafter natural gas prices

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are assumed to escalate at inflation. Midstream and delivery charges are based on current Commercial Rate 3 charges from FortisBC for the Lower Mainland, and are assume to escalate at inflation. Carbon taxes are included at the current rates, and are anticipated to escalate at inflation.

Electricity rates (for DEU operations) are based on BC Hydro’s current Medium General Service rate. Through 2015, we have applied BC Hydro’s announced rate increases, though for the time being these increases have only been announced for residential users, as the expectation is that other rates will also be increased.

As noted, for the reference case, the cost of waste heat from the WTEF is assumed to be levelized at $25 per MW.h at the heat pipeline / DPS energy transfer station.

Initial reference case fuel rates, as well as 20 year levelized rates, are shown below in Table 15. Rates are levelized using the utility’s proposed weighted average cost of capital. Annual fuel costs for indicative years are shown in Table 16.

Table 14: Fuel rates per MW.h

2012 20-year levelized Natural gas w/carbon tax 37 49 Waste heat (Target) 25 25 Electricity (general service) 67 92

Table 15: Annual fuel cost ($000s)

2012 2014 2017 2026 2031

Natural gas 61 312 0 111 377 Waste Heat 0 0 314 971 1,303 Electricity 2 9 21 88 138

In the high bookend case, the only difference in assumptions is around the cost of waste heat. Based on currently available information, the full levelized cost of the waste heat supply is $56 per MW.h, as discussed above in section 3.5.2. Given the higher costs to deliver waste heat under this scenario, it does not become economical to connect the pipeline until 2027. Fuel consumed in indicative years under this scenario is shown in Table 17. Annual fuel costs are shown in Table 18. Please note that pipeline pumping electrical costs, as well as the value of reduced electricity generation at the WTEF, are reflected in the cost of waste heat, and not in the DEU’s electricity costs.

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Table 16: Annual fuel consumption – high bookend scenario (MW.h)

2012 2014 2017 2026 2031

Natural gas 1,634 7,099 13,452 2,001 6,202 Waste Heat 0 0 0 38,835 52,135 Electricity 27 116 220 712 1,014 Table 17: Annual fuel costs – high bookend scenario (thousands $)

2012 2014 2017 2026 2031

Natural gas 61 312 543 111 377 Waste Heat 0 0 0 2,121 2,848 Electricity 2 9 21 88 138

In the 100% gas scenario, all thermal energy is provided with natural gas. Annual fuel consumption and fuel costs for this scenario are shown below in Table 19 and Table 20.

Table 18: Annual fuel consumption – 100% gas scenario (MW.h)

2012 2014 2017 2026 2031

Natural gas 1,634 7,099 13,452 43,577 62,017 Waste Heat 0 0 0 0 0 Electricity 27 116 220 712 1,014 Table 19: Annual fuel costs – 100% gas scenario (thousands $)

2012 2014 2017 2026 2031

Natural gas 61 312 637 2,422 3,770 Waste Heat 0 0 0 0 0 Electricity 2 9 21 88 138

3.5.5 Property Taxes The DEU will have property tax liability for the EC, as well as for the distribution piping. There is no property tax liability associated with the ETS. The budgeted tax rates are shown below in Table 21. The tax rate on the EC is Business – Class 6, and is inclusive of all provincial, regional and city taxes.

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Table 20: Tax rates

Tax rate on energy centre $18.11 per thousand $ assessed value Tax rate on DPS 1.25% of gross revenue

3.6 Capital structure Parklane proposes a deemed capital structure of 60% debt and 40% equity for rate setting purposes, similar to district energy utilities approved for UniverCity and Dockside Green. The interest rate on the debt is expected to be 6%.

The development of this DEU involves exposure to many of the same risks which apply to other new thermal energy utilities, including:

• Property development risk due to changes in demand in the Vancouver area; • Small company size risk due to the limited customer base for the project; and • Construction cost risk due to the large capital costs involved in connecting the waste heat source.

Due to these risks, Parklane is proposing a return on equity of 10%, or a 50 basis point premium over the benchmark ROE of 9.5%, in keeping with the Commission’s recent decision regarding the UniverCity CPCN application. Parklane anticipates revisiting the return on equity once the waste heat pipeline is implemented, as this will change the project’s risk profile.

The capital structure and financing rates are summarized in Table 22 below.

Table 21: Summary of capital structure

Share of capital Nominal Rate Debt 60% 6% Equity 40% 10% 3.7 Depreciation rates Depreciation charges are based on commonly-used depreciation rates for different asset types. Annual rates, as well as the equivalent overall depreciation periods, are shown below in Table 23.

Table 22: Depreciation rates

Depreciation Period Annual Depreciation Rate

Building 40 years 2.5% Plant 25 years 4% DPS 40 years 2.5% ETS 25 years 4%

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3.8 Income taxes The combined federal and provincial corporate tax rate in BC is currently 25%. This has been assumed for the duration of the project. Class 1 CCA expenses are depreciated at 4% per year, and Class 17 expenses at 8% per year. Most of the utility’s capital costs are Class 17 expenses. Due to initial operating losses and depreciation, the utility has no tax liability until 2026.

3.9 Revenue requirements Table 24 below summarizes the annual revenue requirement for the first 10 years of operations under the reference case. This revenue requirement includes the carrying costs of the proposed deferral account to finance levelized rates, as described below. Table 23: Revenue requirements, 2012 – 2021 (thousands $)

2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 Operating costs 108 118 316 330 401 439 460 480 502 532 Waste Heat - - - - - 314 351 380 415 490 Natural gas 61 139 312 403 543 - - - - - Electricity 2 4 9 12 17 21 24 28 32 38 Property taxes – building - - 30 30 31 50 51 52 53 54

Property taxes – distribution - - 7 10 14 17 19 21 24 29

Depreciation 99 108 390 400 410 529 548 568 587 608 Interest - 104 122 425 468 508 652 698 745 789 Return on equity - 116 135 472 520 564 725 776 827 877 Income tax - - - - - - - - - - Total Revenue requirement 270 590 1,320 2,082 2,351 2,442 2,831 3,003 3,186 3,417

3.10 Levelized rate proposal Build out of the River District development is projected to take 23 years. Large capital investments are required at several early stages of the project and significant declines in overall costs per MW.h are anticipated later in the project once the WTEF pipeline has been installed.

Parklane is proposing a levelized rate structure to reduce energy rates for early customers of the DEU and distribute the costs of developing this project over all customers for a 20 year period. This levelized rate will under-recover the carrying costs of the utility during the early years of operation. A deferral account is proposed to capture under-recoveries. Rates are set to ensure the deferral account will be fully recovered by the 20th year of operation.

The proposed effective rate would initially be $86.65 per MW.h, and would escalate at 8% per year through 2016 to reach $117.88 per MW.h in 2016. The higher escalation to 2016 is less than BC Hydro’s projected electricity rate increases. Parklane considers electricity the competitive benchmark for rates. Under the reference case, the rate would then escalate at 3.04% per year through 2031. Under this scenario, the overall levelized rate over 20 years would be $150 per MW.h.

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Under the high bookend case, the initial effective rate and the escalation through 2016 would be the same as under the reference case. For the period 2017 – 2031, the rate would need to escalate at 4.87%. The overall levelized rate under this scenario would be $175 per MW.h.

The 100% gas scenario also has an overall levelized rate of $176 per MW.h. The rate escalation for each scenario is shown in Figure 4.

Figure 6: DEU per MW.h rates by supply scenario vs. electricity benchmark

3.11 Rate design Parklane is proposing to adopt a rate with both fixed and variable components to reflect the cost structure of the utility. As the system has high capital costs and relatively low variable costs, the utility will be less likely to over-recover in periods of high demand and under-recover in periods of low demand with a fixed rate component. This will also reduce the volatility in customers’ energy bills.

On a net present value basis, the utility’s costs over the first 20 years of operation under the reference case are split roughly 70 / 30 between fixed costs and variable costs, assuming that the waste heat supply is considered a variable cost. Parklane is proposing that the rate design reflect this split, with 70% of costs recovered through a fixed charge and 30% through a variable charge based on energy consumption. The fixed charge would likely be based on connected floor area.

The DEU would bill individual buildings connected to the system. The strata association for the building will allocate charges to strata owners via sub-metering or some other method it chooses.

-

50

100

150

200

250

300

High Bookend Scenario

100% Gas Scenario

Reference Case

Electricity

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3.12 Rate stabilization account The rate stabilization account would cover shortfalls in revenue during the DEU’s early years of operations. Under the reference case, the maximum value of the stabilization account would be $10.9 million in 2023. Thereafter revenues will exceed annual costs and the stabilization account would be eliminated by year 20.

3.13 Rate benchmarks Parklane considers electricity to be a competitive benchmark for thermal energy for this project. Electricity is a widely-understood fuel in British Columbia, its price has relatively low volatility, and it is a common source of in-suite space heat. In addition, the comparable levelized cost of natural gas heat for building types comparable to the River District, taking into account fuel, carbon taxes, maintenance costs and capital costs is currently very similar to electricity under a typical residential load profile.

Parklane considers that a rate up to 10% above electricity may be justified when considering additional intangible benefits to consumers such as the higher quality of service associated with hydronic heat, environmental benefits, reduced exposure to future commodity price changes (through higher efficiency and the ability to switch fuels / technologies over time), and the additional floor space freed up within individual projects. The City of Vancouver has approved rates for its own DEU in SEFC that are up to 10% above the electricity benchmark.

Table 24 compares the levelized price of the DEU (reference case) with the levelized price of electricity. Levelized rates are calculated by discounting projected prices and sales at the DEU’s WACC over 20 years. The electricity rate projections are based on forecasts provided by BC Hydro and assume a weighted average mix of 50% Tier 1 and 50% Tier 2.

Table 24: Levelized rate comparisons ($/MW.h over 20 years)

DEU reference case $150 Residential electricity $144 DEU premium over electricity 4.2%

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3.14 Financial projections The projected operating expenses, financing charges, and balance sheet for select years under the reference case are shown in Table 25.

Table 25: Operating cash flow and balance sheet (thousands $)

2012 2013 2014 2015 2016 2017 2021 2026 2031

Earnings Fixed charges 81 190 410 550 787 935 1,644 3,966 6,555 Variable charges 35 82 176 236 337 401 705 1,700 2,809 Total revenue 116 272 586 786 1,124 1,335 2,349 5,665 9,365 Operating costs 108 118 316 330 349 439 532 758 1,015 Fuel 63 143 321 415 560 335 529 1,170 1,819 Property taxes 0 0 37 40 45 67 83 130 182 Total operating expenses 171 261 674 785 954 841 1,144 2,058 3,015

Operating cash flow (55) 11 (87) 1 170 495 1,205 3,607 6,350 Depreciation 99 108 390 400 410 529 608 780 972 Interest 0 104 122 425 468 508 789 924 659 Return on Equity 0 116 135 472 520 564 877 1,027 732 Income tax - - - - - - - - 1,135 Earnings before deferral (154) (318) (734) (1,296) (1,227) (1,107) (1,169) 876 2,869

Revenue deficiency deferral 154 472 1,206 2,502 3,729 4,836 9,741 9,593 -

Balance sheet Plant in service 2,838 3,118 11,194 11,486 11,783 15,213 17,461 22,402 27,937 Accumulated depreciation (99) (207) (597) (996) (1,407) (1,936) (4,247) (7,738) (12,152)

Revenue deficiency deferral 154 472 1,206 2,502 3,729 4,836 9,741 9,593 -

Net rate base 2,893 3,382 11,803 12,991 14,105 18,113 22,955 24,257 15,785 Debt 1,736 2,029 7,082 7,795 8,463 10,868 13,773 14,554 9,471 Equity 1,157 1,353 4,721 5,197 5,642 7,245 9,182 9,703 6,314 Total Financing 2,893 3,382 11,803 12,991 14,105 18,113 22,955 24,257 15,785

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3.15 Sensitivity analysis We have assessed the DEU’s sensitivity to variations from the reference case including changes in gas prices, the development’s buildout schedule, capital costs, and annual energy demand. The results of the sensitivity analysis on the DEU’s overall levelized rate are shown in Table 26.

Table 26: Sensitivity analysis results, levelized $ / MW.h

Reference case $150 Higher gas prices (8% nominal escalation from current levels) $151

Flat gas prices (2% nominal escalation from current levels) $149

Faster buildout (20 years) $144 Slower buildout (30 years) $156 Capital + 10% $158 Capital – 10% $142 Annual energy demand + 10%, no capital adjustment $140

Annual energy demand -10%, no capital adjustment $163

We have also assessed the impact of further rate increases on the benchmark residential electricity rate. Given current forecasts, the levelized residential electricity rate is $144 per MW.h. If real rate increases of 2% continue beyond 2020 (which is the final year of currently-forecast real rate increases), then levelized residential electricity rates for a project with this energy use profile would be $160 per MW.h.

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4 Public consultation The public consultation process for the River District commenced in 2002. Early on the prospect of a DEU was discussed and emerged as a key element in the community sustainability strategy. A sample of a story board used at public open houses is shown in the Appendices at Figure 13. The commitment to a DEU increasingly grew so that now it is a zoning requirement that all buildings will connect with the exception of the River Walk townhomes.

4.1 Community Community consultation for the development of the River District began in 2002 when the former land owner, Weyerhaeuser Canada, decommissioned its White Pine saw mill and commenced the process to seek approval for a mixed residential and commercial development. Parklane became involved in 2003 and subsequently purchased the site in 2004. The land area grew when Parklane acquired additional land from the City of Vancouver and from the former owners of the Spools lumber yard located in the northwest corner.

Early on in Parklane’s involvement with River District a DEU was considered. The prospect became a requirement in the Official Development Plan developed by Parklane, the community and the City and approved by council in 2006 that all buildings would be designed to connect to a DEU should one be available. .

The commitment to a DEU continued to strengthen through the public rezoning process so now it is a zoning condition that all buildings will connect to a DEU, with the exception of River District’s only ground oriented townhouses.

The prospect of a DEU was disclosed throughout the planning and rezoning process which included:

66 Public meetings

2 Design charrettes spanning a total of 8 days and involving 1,100 participants

7 Full and half-day community workshops

2 Workshops with Vancouver City Council

2 Public hearings

In large measure as a result of the public consultation process the Vancouver Fraserview Killarney Residents Association wrote a letter of support to the Mayor and Council of the City of Vancouver preceding the initial rezoning.

River District has also received the following awards:

2007 Canadian Institute of Planners Award For Excellence Best Neighbourhood Plan in Canada for the East Fraserlands ODP.

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2007 B.C. Smarty Award Best Public Consultation Process and Development Proposal for the East Fraserlands ODP

2007 Canadian Urban Institute Brownie Awards Best communications and public engagement in Canada for the East Fraserlands

Canadian Society of Landscape Architects National Honor Award The society’s highest award and honours excellence in landscape design and urban planning.

Links to samples of the references to the DEU included in materials presented to the public are included in Appendix 9.2.

4.2 First Nations First Nations have been welcomed in the public consultation process and were formally consulted by the Department of Fisheries and Oceans for the design of the foreshore. Every First Nation registering intent over lands including the River District on the Provincial land claims registry was contacted. The Musqueum were the only band to respond. Development plans including the prospect of a DEU were shared with the Musqueum. The band’s concerns were addressed and changes made to the design of the marine works.

Development of the DEU does not impose a further duty to consult First Nations. All DEU infrastructure at the River District will be installed on titled land owned by Parklane or the City. The pipeline to connect to the Metro Vancouver WTEF will be installed in rights of way on municipal or private lands. The energy capture equipment will be installed within Metro Vancouver’s WTEF.

4.3 Other stakeholders Key stakeholders have also been specifically consulted on the DEU.

4.3.1 City of Vancouver Vancouver City Mayor, Council and staff have been supportive of the River District and of the DEU. Council has voted on The River District on four separate occasions. Each time the vote has been unanimous. Staff have, and are continuing to provide, input into system design. The City has written a letter of support which is contained in Appendix 9.4.1.

4.3.2 Metro Vancouver Metro Vancouver has been consistently supportive of supplying heat for a DEU. The turbine installed in 1995 contains a stubbed-off port for extracting the energy. The technical and business aspects have been

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studied by internal and external resources. A 2002 report produced by FVB Energy concluded that a DEU, then intended to supply new developments in the Big Bend area of Burnaby, would be technically and financially viable.

Metro Vancouver remains supportive and engaged Ausenco Sandwell Engineering at a budgeted cost of $150,000 to carry out detailed design of the energy capture equipment needed to supply the River District DEU. This has been done in advance of signing a MOU or energy supply agreement. It has written a letter of support which is contained in Appendix 9.4.2

4.3.3 City of Burnaby Parklane and Metro Vancouver staff met with City of Burnaby officials on November 19, 2010 to discuss rights of way along the proposed pipeline route. In December 2010 City of Burnaby staff provided a copy of its standard Utility Access Agreement to form the basis for an agreement for the WTEF pipeline. On January 20, 2011 the City of Burnaby Director of Planning and Director of Engineering submitted a report to the Finance and Civic Development Committee recommending the City of Burnaby develops a memorandum of understanding with Metro Vancouver and Parklane.

The MOU is to contain the alignment of the pipeline, establishment of the repair and maintenance responsibilities for the pipeline, a commitment from Parklane and Metro Vancouver for the system design to reflect the opportunity for the DEU to serve existing and future Burnaby businesses along its alignment and that these businesses are permitted to connect to the DEU.

The report was tabled pending more information from staff. It is expected Metro Vancouver will recommence discussions with the City of Burnaby as the system design and pipeline alignment is further developed.

4.3.4 Prospective home owners Presently there are no residents on Parklane’s lands at the River District. Polygon Homes will be constructing the first two developments to be built.

The first is a project, called River Walk, of approximately 150 townhouses and will start construction in summer 2011. Marketing and sales has not yet started. Heat and DHW will be supplied by conventional gas-fired appliances. The townhouses will not be connected to the DEU but provisions will be made so that connection will be possible in the future. These provisions include adoption of hydronic heat, mechanical stub-offs for future connection to the DPS and registered rights of way to protect the DPS alignment and EC locations.

The second is a project of approximately 156 apartments contained in two four-storey, wood frame buildings called New Water. Construction will commence in August 2011. Marketing has commenced and as of July 12, 2011 approximately 70 homes had been sold. Purchasers have been advised in the project disclosure statement that energy for heat and DHW will be supplied by a DEU. The relevant extracts from the disclosure statement are provided in Appendix 9.2.4.

Parklane produced a document describing DEU’s and the specific design specifications to be met by builders at EFL to ensure seamless integration of building mechanical systems with DEU infrastructure. Polygon

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requested a copy of this document to inform its sales staff and to provide to prospective customers. A copy is provided in Appendix 9.3

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5 Project Description

5.1 Overall project This section provides a more detailed description of the River District DEU.

The system will circulate hot water through a closed loop distribution piping system for space heating and domestic hot water for buildings at the River District. Energy will be provided by gas-fired boilers, initially from a temporary trailer-mounted source. When the permanent EC is constructed the temporary source will be decommissioned and sold. When sufficient energy load is connected a pipeline will be constructed to connect to Metro Vancouver’s WTEF (Figure 8). Energy will be supplied to the R-ETS via hot water circulated through a closed loop, supply and return pipeline. The permanent EC (gas-fired boilers) will be retained for peaking and back up.

A table of the system components and the party responsible for the ownership, installation, operation and maintenance follows:

Temporary, trailer-mounted EC located on Parcel 8A RDE Permanent gas-fired EC located on Parcel 5B RDE Main trunk distribution pipes RDE Branch connections RDE Energy Transfer Stations RDE Internal energy distribution system installed in buildings (downstream of ETS)

Building owner

Renewable ETS located on Parcel 47 RDE Pipeline to Metro Vancouver WTEF Metro Vancouver Heat capture equipment installed within WTEF Metro Vancouver

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5.2 Project phasing 5.2.1 Development phasing Development of the DEU will be phased and timed to coincide with installation of roads, sewers and general services. Development will commence in Area 2 in the west then proceed eastward to Area 1 in the center before continuing on to Area 3 in the east. The areas outlined in black represent the rezoning Areas 1, 2 and 3.

1A – 13, 14, 15, 16, 17, 18, 19

2A – 1,2,3,4,5,6,7,9

2B – 8, 10, 11

1B – 26, 27, 29/30

2C – 23, 24, 25, 28

3A – 40, 41, 42

1D – 31, 32, 33/34, 35/36, 39 1C – 18, 20, 21, 44 (45)

1E – 43

3B – 46, 47, 48, 49, 50, 51, 52, 53, 54

Trigger TBD

Trigger TBD

Complete by OP of 11



Trigger TBD

Road Phasing

Shoreline Phasing

Figure 7- Development Sequencing

Area 2 Area 1 Area 3

Future load

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5.2.2 Location of key components of Phase 1 The key components of Phase 1 include the DPS in Area 2, temporary EC, permanent EC and conduit installed to connect future loads west of Kerr Street. These components are indicated in Figure 8.

The first buildings to connect will be the two apartment buildings located on Parcel 7 and being marketed as New Water. The builder, Polygon Homes, will commence construction in August 2011 and will be calling for construction heat in February 2012 with occupancy scheduled for summer 2012.

The townhouses located on Parcels 2/4/6 are also under construction by Polygon. Heat and DHW will be supplied by conventional means. They will not be connected to the DEU although provisions will be made to facilitate connection in the future should it become economic to do so.

Figure 8 - Key components of DEU Phase 1

Permanent EC

Temporary EC

Conduit to connect Kerr St. sites

Pcl 7 – New Water First buildings to connect

Pcl 2/4/6 – River Walk townhomes that will not be connected

Future load

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5.2.3 Heat capture equipment and pipeline to Metro Vancouver WTEF It is expected the heat capture equipment and pipeline will be owned by Metro Vancouver. The proposed alignment of the pipeline is depicted in Figure 9. The City of Burnaby may prefer to extend the alignment to serve other potential loads. The financial model in this CPCN application assumes any incremental costs to extend the alignment would be borne by other users to be served.

Figure 9 - Proposed alignment of pipeline

5.3 System components 5.3.1 Distribution Piping System The DPS pipe specification calls for Logstor pre-insulated steel pipes and fittings P235GH or St. 37.0BW, tolerances comply with EN 253, Series 1, with LR warning copper wires, 12 meters lengths (39.4 ft). Pipe diameter varies according to location and ranges from 110mm to 450mm.

RDE will pre-order and inventory the pipe and supply it to the selected installation contractor. Installation contractors must be certified by the manufacturer. During installation the pipe and connections will be independently inspected. Following independent certification the installed DPS section will be capped, evacuated and pressurized with nitrogen to prevent contamination or oxidation prior to commissioning. An extract from the detailed design of Phase 2A DPS is located at 9.7.2.

5.3.2 Energy Transfer Stations ETSs will be designed by the building developers’ mechanical engineer and verified by FVB on behalf of RDE.

EFL

Pipeline

WTEF

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The general design specifications are set out in the Information for Developer document at 9.3. The first ETSs to be designed will be installed at New Water on Parcel 7. The specific design schematic is set out in Figure 10.

Figure 10 - Parcel 7 New Water ETS Design

5.3.3 Temporary Energy Centre The temporary EC will consist of gas-fired boilers mounted in a standard 8’ by 40’ shipping container. It will be mounted on a concrete pad and connected to conventional electrical and communication services.

The general design specification are set out in Table 27 below. The design cross section is shown in 9.7.1.

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Table 27 - Temporary EC specification

Boiler Capacity 1080 kW each at site conditions Max Heating Surface Area per Boiler To be provided by Contractor Water Temp. out °C/in °C 95°C/55°C (winter) Water Temp. out °C/in °C 65°C / 45 °C (normal) Boiler Pump VFD (Each) 6.5 l/s against TDH 20m Boiler Relief Valve Setting 207 kPag (To be confirmed by Contractor) Gas Pressure On site Terasen Gas connection point 34 kPa Expansion Tank Volume 900 mm dia x 2000 high

5.3.4 Permanent Energy Centre and Renewable Energy Transfer Stations Conceptual building design for Parcel 5B is underway. The design criterion includes a provision for 7000 square feet of vacant space within the attached parking structure to house the permanent EC. The R-ETS is to be housed within a stand-alone structure funded and constructed by RDE on a portion of Parcel 47 secured under a long term lease.

Detailed design of the permanent EC and R-ETS will commence in mid 2012. The general requirements are set out in Table 28 below. Only the permanent EC is included in approvals sought in this Application.

Table 28 - EC and R-ETS specifications

Gas-fired EC R-ETS

Location Pcl 5B Pcl 47

Land area N/A - Co-located with parking structure 300 m2 (3200 ft2)

Building size 656 m2 (7000 ft2) 150 m2 (1600 ft2)

Tenure Leased from building owner including TI's for admin office

Building constructed and owned by RDE on leased

land

Major components 4 - 6 MW high efficiency gas-fired boilers ETS with side pumps

Thermal output 24 MW 10 MW

Electrical service 600 kVA 500 kVA

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Construction costs for the EC and R-ETS have been estimated by FVB and are set out in Table 30. The costs for the permanent gas-fired EC include system components only and a provision for integrating with the building systems. The building is to be constructed and leased from the developer of Parcel 5B.

Table 29 - EC and R-ETS construction costs excluding contingency (2011$)

Gas-fired EC R-ETS TOTAL

EC construction costs

Building - Hard and soft costs 217,600 217,600

Building - Tenant integration costs 100,000 100,000

Electrical 911,000 110,100 1,021,100

Mechanical 2,568,000 171,900 2,739,900

Major equipment 1,677,000 208,000 1,885,000

Construction soft costs 544,000 85,300 629,300

5,800,000 792,900 6,592,900

Engineering Services 680,000 99,100 779,100

6,480,000 892,000 7,372,000

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5.4 Implementation schedule Figure 11 - Development & approval timelines

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5.5 Human resources requirements The RDE workforce will vary over the course of its development according to its needs. Parklane’s Chief Financial Officer will remain as the overall project manager to oversee the approval, development and financing processes. Ms. Petri, PEng, will remain as the manager to oversee design, tendering, construction, commissioning and operation of the system. Ms. Petri will be assisted by one of Parklane’s senior site managers, Mr. Bob Boky, to oversee all on-site activities.

RDE will draw on Parklane’s extensive construction management experience, practices and procedures to ensure efficient and effective delivery of the system. RDE will establish and maintain separate accounting records from Parklane. Annual verification of accounts will be conducted by Parklane’s current auditor, Ernst & Young. Tendering of DEU work will be done independently of general site services where practical. Where efficiencies or lower costs can be obtained by jointly tendering site services and DEU work, contracts will segregate scopes of work such that all disbursements can be appropriately reflected in the accounting records.

Design and engineering of the DEU has been subcontracted to FVB who will also be retained as Owner’s Representative to ensure integration of building systems with the DEU.

Supply and installation of system components will be subject to competitive tendering. Contractors will be pre-qualified based on demonstrated capacity and experience.

Operational staffing will be dependent on BC Safety Authority (“BCSA”) requirements determined pursuant to the Power Engineers, Boiler, Pressure Vessel and Refrigeration Safety Regulation. On May 11, 2011 an introductory meeting was held with staff from BCSA. RDE is proposing that the EC be classified as a Low Pressure Fluid Plant and that it be eligible for general supervision rather than 24 hour supervision. Determination of staffing requirements will be made once further design of the EC is complete.

Billing and customer care will be performed under contract by Wesgroup’s property management department.

5.6 Risk analysis RDE will strive to minimize all risks to DEU and its customers. Parklane, as the land developer, is highly motivated to ensure the River District is successful in all areas, including the DEU. The key risks and mitigating factors are described below.

5.6.1 Timing of development is slowed There is a risk that development does not occur as quickly as forecast.

Mitigating factors:

1. RDE will build a temporary EC to supply the first buildings to connect until the permanent EC is constructed. The temporary system components are designed and sized to fit inside a standard 8’ by 40’ sea can. The design is intended to be modular so that an additional unit can be constructed in the event the permanent EC is not completed when and if additional energy is needed.

2. Development of the DEU will be done in phases to defer capital costs and provide flexibility to match community development phasing.

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3. The pipeline to Metro Vancouver’s WTEF will only be constructed when there is sufficient load to support Metro Vancouver’s capital spending and an energy supply agreement is reached.

4. With the exception of the townhouses on parcels 2/4/6, all buildings in the River District will be required to connect to the DEU as a condition of rezoning. Enforcement of this requirement occurs through the building Development Permit and Building Permit processes.

5. RDE will continue to pursue capital grants. If successful, these grants will serve to reduce customer rates and advance the timing of construction of the WTEF pipeline.

5.6.2 Unable to secure energy supply agreement with Metro Vancouver There is a risk that an energy supply agreement with Metro Vancouver cannot be obtained

Mitigating factors:

1. The system will be designed and constructed to operate on natural gas, initially from a temporary energy source then from a permanent EC sized to supply the entire load at River District. If an agreement cannot be reached to source energy from the WTEF then the DEU will continue to operate on gas until another suitable alternative energy source can be identified and developed.

2. The hydronic heating in each building provides flexibility to accommodate different alternative energy sources. The initial 2007 feasibility study completed by Compass determined that other energy sources may be feasible, including biomass and sewer heat recovery. Should it appear that an agreement with Metro Vancouver were not feasible, engineering work would be carried out to identify an alternative energy source.

3. The DEU is being developed in phases and the pipeline is not projected to be constructed until 2017 at the earliest. This should provide sufficient time in which to negotiate an agreement with Metro Vancouver and secure the necessary ROW from Burnaby.

5.6.3 Unable to secure pipeline ROWs from Burnaby There is a risk that Burnaby may oppose granting the necessary ROW for the proposed pipeline route.

Mitigating factors:

1. Metro Vancouver is granted powers as a Regional District which could be used to obtain the required ROW.

2. If a CPCN were granted for RDE to operate the DEU, the Commission can issue orders granting a required ROW.

3. Metro Vancouver currently holds a number of existing ROW extending from the WTEF to River District. The ROW are not completely contiguous and would require a realignment of the pipeline but could serve in place of the preferred route.

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5.6.4 System does not perform as designed There is risk the system does not perform as designed, constructed and operated

Mitigating factors:

1. RDE has retained recognized experts with local experience to design the system and will continue that practice through to construction and operation.

2. Wherever possible “off-the-shelf” solutions and components will be chosen and unproven technologies avoided.

3. Parklane is the land developer of River District and the owner of RDE. It will use its powers and influence to ensure that building developers cooperate to ensure building systems integrate seamlessly with the DEU infrastructure.

5.6.5 Construction cost overruns There is a risk that construction and equipment costs may be higher than projected.

Mitigating factors:

1. RDE will draw on the expertise of its owner, Parklane, to bring tight cost controls and project management to the development of the DEU.

2. All significant cost items will be sourced through a competitive tendering process with third party suppliers.

3. RDE will work with the City, and be open to working with other DEU operators, to source parts and materials efficiently through sharing of information and, potentially, group purchases to reap improved economies of scale.

5.7 Environmental and social impacts Once connected to the WTEF, the DEU will result in substantial greenhouse gas emissions (“GHG”) reduction as compared to typical building-scale thermal energy systems. A comparison of DEU and business-as-usual (“BAU”) GHG emissions for select years is provided in Table 30. The BAU configuration for residential buildings is in-suite electric baseboard heaters, gas-fired make-up air (“MAU”) units in hallways and common areas, and gas-fired DHW boilers. In-suite space heat accounts for ~50% of space heat in residential buildings. Commercial space heat and DHW are assumed to be 100% gas. Boilers are assumed to have an average lifetime efficiency of 80%. The emissions factor for natural gas is 180 kg CO2 per MW.h.

As noted above, at buildout the waste heat pipeline would supply 87% of the DEU’s annual energy needs, so natural gas consumption would be significantly reduced following construction of the pipeline to the WTEF. Prior to the installation of the pipeline to the WTEF, 100% of the DEU’s energy is supplied with natural gas, so GHG emissions will be higher than BAU during the initial years of the system’s operation. The DEU’s boilers are assumed to have an average lifetime efficiency of 85%, reflecting the operational benefits of a large, centralized facility with full-time operators.

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Table 30: GHG emissions (annual tonnes CO2e)

2012 2014 2017 2026 2031 2034

DEU 294 1,278 - 360 1,116 1,880 BAU 207 895 1,712 5,446 7,721 10,092 GHG Reduction / (Increase) (87) (383) 1,712 5,086 6,605 8,212

By capturing waste heat from Metro Vancouver’s WTEF, the DEU will increase the overall efficiency of the WTEF. While electricity production is slightly negatively impacted by additional waste heat capture at the plant, the overall amount of energy captured (both thermal and electrical) will increase, leading to better utilization of the WTEF.

By reducing the use of electricity for space heating, the DEU will also result in lower electricity consumption. DEU and BAU electricity consumption for select years are compared in Table 32.

Table 31: Electricity consumption (annual MW.h)

2012 2014 2017 2026 2031 2034 DEU 27 116 220 712 1,014 1,313 BAU 485 2,131 3,965 12,398 17,710 22,938 Electricity Reduction / (Increase) (459) (2,015) (3,745) (11,685) (16,696) (21,625)

There are no significant employment impacts from the DEU. The DEU will employ several operators and some administrative staff, but employment levels are not likely to be significantly different from BAU.

5.8 Permits and approvals The RDE DEU will require a CPCN to operate.

A Municipal Access Agreement (“MAA”) to permit installation of the DEU infrastructure has been drafted and is being reviewed by the City. Alternatively the City is considering adopting a city-wide bylaw governing installation of DEU infrastructure. If adopted the bylaw would supercede the provisions of the MAA.

Development and building permits will be required to construct the EC and R-ETS.

Approval and determination of staffing requirements by the BC Safety Authority will be required prior to operation of the temporary and permanent EC.

An air quality permit is not required.

Metro Vancouver will need to secure the ROW for the pipeline.

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6 Project Cost Estimate Capital costs have been estimated by FVB based on experience and from tenders received for construction of the temporary EC and Area 2A DPS installation. Operating costs used in the financial model have been estimated by Compass from its experience consulting to other DEU owners in the region. Unless otherwise stated all costs are expressed in $2011.

6.1 Project cost assumptions The capital cost estimates are based on varying degrees of design completion.

6.1.1 General assumptions • All costs are expressed in CAD $2011 • Inflation at 2% per year • All costs subject to competitive tenders • Engineering costs are included and separately disclosed • No contingency contained in individual line items. Overall contingency of 10% provided separately

6.1.2 DPS The DPS costs are based on detailed designs and contractors tenders for Area 2A. The results for Area 2A were compared to initial estimates, necessary adjustments made, and the results extrapolated for the balance of the DPS.

• All component costs FOB at River District • Logstor two-pipe pre-insulated steel pipe buried at 900 mm to top of pipe • Pipe installed in excavated trenches with standard provisions for shoring and no excessive

dewatering • All work reinstated to pre-landscaping conditions

6.1.3 ETS • Costs are for primary side heating only • Assumes one ETS per building located at grade or basement level • Where ETS located at basement level, any requisite costs for tanking or alternate flood-proofing are

considered building costs to be borne by building developer • DHW storage supplied by developer on secondary side • Mechanical rooms sized to accommodate ETS and equipment • Metering to ETS included. Any secondary side or suite metering to be provided by developer.

6.1.4 ECs The permanent EC costs are estimated from high level design. Temporary EC cost based on detailed design and tenders received from qualified contractors.

• Temporary EC consists of 2 boilers housed in shipping container to be mounted on concrete pad. • Services delivered to the site by the developer • Permanent gas-fired EC co-located in parking structure for Parcel 5B • Developer to construct and fund structure to RDE DEU specifications

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• High efficiency boilers • Developer to provide utility services to the structure

6.2 Project capital cost budget The capital costs expressed in $2011 and excluding contingency are detailed in Table 32 below.

Table 32 - Capital costs (2011$)

Area 1 Area 2 Area 3 Total

DPS

Construction Costs 3,460,000 1,855,000 1,289,000 6,604,000

Engineering Services 415,000 260,000 163,000 838,000

3,875,000

2,115,000

1,452,000

7,442,000

ETS

Construction Costs 2,959,000 1,645,600 1,513,000 6,117,600

Engineering Services 502,000 279,700 257,000 1,038,700

3,461,000

1,925,300

1,770,000

7,156,300

Temporary Boiler

Construction Costs 0 443,000 0 443,000

Engineering Services 0 110,000 0 110,000

- 553,000 - 553,000

Permanent ECs

Construction Costs 792,900 5,800,000 0 6,592,900

Engineering Services 99,100 680,000 0 779,100

892,000

6,480,000 -

7,372,000

Total

8,228,000

11,073,300

3,222,000

22,523,300

Number of ETS 25 15 13 53

Cost per ETS 138,440 128,353 136,154 135,025

Trench metres of DPS 2,145 1,624 1,103 4,872

Cost per trench metre of DPS 1,807 1,302 1,316 1,528

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7 Provincial Energy Policy Considerations

The River District DEU Project aligns with several provincial government objectives under the 2007 BC Energy Plan and the Clean Energy Act.

1) The Province has set ambitious goals to reduce the growth in electricity demand so that, by 2020, 10,000 GWh of currently forecast needs will be met through demand reduction measures. By implementing hydronic heating systems in buildings and using the proposed WTEF heat supply, this project will eliminate 4.4 and 22.2 GW.h of electricity demand per year by 2020 and 2034, respectively, relative to business as usual heating with electric resistance heaters. Heating is one of the lowest value uses of our highest value (and cost) source of energy. Electric heating has a low load factor so contributes a disproportionate amount to the Province’s requirements for peaking electrical capacity. Further, because the proposed long-term thermal energy will come from Metro Vancouver's WTEF, this project eliminates electricity demand while also drastically reducing natural gas demand for heating, even more than other comparable projects because of the high percentage of annual heating energy that will be displaced by this particular energy source.9

2) In the Standing Offer provisions of the 2007 BC Energy Plan, the government includes co-generation as an eligible option with an overall efficiency (heat and electricity production) in excess of 80 per cent. Although the Metro Vancouver WTEF does not sell power under the Standing Offer program, the addition of waste heat recovery is generally consistent with the Province’s stated aims to encourage co-generation with high total efficiency. As illustrated in Section 5.7 of this Application, sales to the River District would increase total energy recovery from existing municipal solid waste handled by the WTEF by as much as 5%.

3) In the 2007 BC Energy Plan, the Province commits that all new natural gas or oil fired electricity generation projects developed in BC and connected to the integrated grid will have zero net GHG emissions. Under the proposed cap and trade program for large GHG emitters, combustion of municipal solid waste is considered a source of GHG emissions. According to some preliminary estimates, the Metro Vancouver WTEF could emit as much as 120,000 tonnes per year of GHG, a portion of which would presumably be allocated to electricity production. In general, the recovery of thermal energy from the plant not only increases total useful energy production for each tonne of GHG emitted by the plant, but the sold thermal energy will reduce emissions from natural gas heating. As a result thermal energy sales should reduce the residual emissions of GHG per unit of

9 As noted elsewhere in this application, in buildings with in-suite electric resistance heating, about 30% of total annual heating load is met by electricity. The remainder (domestic hot water and ventilation air) is normally supplied by natural gas.

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electricity that would need to be offset under the government’s net zero GHG emission policy for existing electricity production.

4) Consistent with the constraints and directions of the Province for Solid Waste Management, Strategy 3.1 in Metro Vancouver's Draft Integrated Solid Waste and Resource Management Plan is to increase energy recovery from waste remaining after recycling in order to provide the highest beneficial use to society, in particular through Waste-to-Energy systems that provide both electricity and district heating. River District demonstrates the potential for district heating to increase total resource recovery from waste-to-energy plants. This project increases overall resource efficiency in the province by enhancing the recovery of useful energy from residual municipal solid waste.

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8 New Service Areas The RDE DEU financial model includes the supply of heat and DHW to River District and the city-owned sites west of Kerr Street (bolded in Table 33). A review of potential customers outside of these areas has identified the following opportunities. These other opportunities may be considered in future through individual extension or expansion tests. 8.1 Areas within Vancouver Table 33 - Potential new loads in Vancouver

Area Description

Potential annual load

(MW.h) City-owned sites west of Kerr Street

• Rezoning of this vacant land has received third reading. The City is agreeable to the buildings once developed being served by the DEU

• Included in the RDE DEU forecasted demand starting in 2021

1260

Remnant land at River District

• Two single family lots and a commercial building in northwest corner comprising approximately 1.1 acres.

• Will require rezoning to realize 76,000 buildable square feet of residential density outlined in 2006 Official Development Plan

650

Existing private high rises west of Kerr Street

• High rise towers constructed in 1980’s and supplied by conventional heat sources

• Unlikely to convert to hydronic heat or connect to RDE DEU

1700

8.2 Areas within Burnaby The City of Burnaby staff indicate there may be loads between the WTEF and River District that could be supplied by energy from the pipeline and other benefits:

The proposed East Fraser Lands Development provides the required number of immediate and futures connections, over the next 25-30 years, to make the district heating utility through the Big Bend feasible in the near to medium term. The NEU has the potential to deliver benefits to Burnaby, both environmentally in terms of reduced energy consumption

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and GHG reductions, as well as improved access to services for a number o existing and new developments along the proposed alignment in Burnaby’s Big Bend area10.

As the likely owner and operator of the pipeline, it is expected that Metro Vancouver will work with the City of Burnaby to identify possible service opportunities along the pipeline route and will consider those opportunities in an incremental business case during the detailed design phase for the project. Additional loads would require an upsizing of the pipeline from the assumptions in this Application and sufficient loads would be required to support the full increment of capacity available from the next size of piping available. It is expected this work will be completed or updated closer to construction of the heat capture equipment and pipeline. Possible loads include both new development and existing development. The City of Burnaby has yet to identify significant new development potential along the proposed pipeline. Compass conducted a very preliminary analysis of possible existing loads along the proposed pipeline route using the BC Safety Authority’s Boiler Database. There are weaknesses to the dataset but a preliminary review identified about 3.5 MW of existing boiler capacity within an approximately 500 m radius of the proposed pipeline alignment. Some of this capacity may be redundant (and therefore not reflect actual customer peak demands) and/or may no longer be in service, but it provides a starting point for a survey. The database does not provide any information on annual energy use. It is unlikely that the existing and new loads in Burnaby along the proposed pipeline alignment would be sufficient in and of themselves to justify a pipeline of this distance. However, as a large anchor load on the other end, the River District opens up potential opportunities for district energy in Burnaby.

10 Page 4, Report from the Director of Planning and Building and the Director of Engineering to the Chair and Members of the Finance and Civic Development Committee, City of Burnaby, January 20, 2011.

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9 Appendices

9.1 Appendix 1 - Financial statements of Parklane Provided in confidence under separate cover

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9.2 Appendix 2 - Public consultation chronology and examples of materials 9.2.1 Chronology of public consultation The DEU is a key element of the River District sustainability strategy and has been consistently referenced in the development approvals process. The following is a partial list of public meetings and links to presentations on public websites where the DEU was described in varying degrees of detail.

- May 6 and 9, 2006. In the EFL Public Open Houses the story board refers to a “community-wide energy generation system based on renewable sources is being investigated” http://vancouver.ca/commsvcs/currentplanning/current_projects/east_fraserlands/newopenhousepdf/3_Sustainability.pdf

- May 27 and 30, 2007. In the Area 1 Rezoning Open House the DEU was described on the Green Buildings story board http://vancouver.ca/commsvcs/currentplanning/current_projects/east_fraserlands/open2/4_Sustainability%20overview.pdf

- March 8, 2008. The City organized a meeting and made a presentation to the EFL Committee (formerly Vancouver Fraserview Killarney Association) to describe the DEU in detail. See Presentation to EFL Committee at section 9.2.2.1

- September 16, 2008. The DEU was described by the Deputy Director of Planning at the Public Hearing to approve the rezoning of Area 1. K:\Development\Projects\Current Projects\7000 - EFL Land Global\General File Index 7000\Div 00 - 6000 Presentations\006200 - External Presentations\2008\Matt Shiloh - EFL Rezoning Public Hearing Presentation_final - 2008.10.24.ppt

- July 8, 2008. The Report to Council for the Area 1 rezoning references the DEU on page 19 as a measure for sustainability. http://vancouver.ca/ctyclerk/cclerk/20080916/documents/ph9.pdf

- June 22 and 23, 2009. In the Area 2 Rezoning Open House the DEU was described on the story boards http://vancouver.ca/commsvcs/currentplanning/current_projects/east_fraserlands/pdf2009/16_Sustainability.pdf

- December 1, 2009. The Report to Council for the Area 2 rezoning references the DEU on page 20 and 21 under the Environmental Sustainability section as well as part of the Green Building Strategy. http://vancouver.ca/ctyclerk/cclerk/20091215/documents/p5.pdf

- December 1, 2009. Also in the Report to Council for Area 2 rezoning the DEU is also detailed under the Proposed Conditions of Approval section (page 4 of Appendix J) at this link http://vancouver.ca/ctyclerk/cclerk/20091215/documents/p5AppendixA-J.pdf

- The DEU is referenced in the Area 2 Design Guidelines which were approved by council

http://vancouver.ca/commsvcs/currentplanning/current_projects/east_fraserlands/newopenhousepdf/3_Sustainability.pdf

http://vancouver.ca/commsvcs/currentplanning/current_projects/east_fraserlands/newopenhousepdf/3_Sustainability.pdf

http://vancouver.ca/commsvcs/currentplanning/current_projects/east_fraserlands/open2/4_Sustainability%20overview.pdf

http://vancouver.ca/commsvcs/currentplanning/current_projects/east_fraserlands/open2/4_Sustainability%20overview.pdf

http://vancouver.ca/ctyclerk/cclerk/20080916/documents/ph9.pdf

http://vancouver.ca/commsvcs/currentplanning/current_projects/east_fraserlands/pdf2009/16_Sustainability.pdf

http://vancouver.ca/commsvcs/currentplanning/current_projects/east_fraserlands/pdf2009/16_Sustainability.pdf

http://vancouver.ca/ctyclerk/cclerk/20091215/documents/p5.pdf

http://vancouver.ca/ctyclerk/cclerk/20091215/documents/p5AppendixA-J.pdf

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9.2.2 Presentation to Vancouver Fraserview Killarney Residents Association The presentation in Figure 12 was given on March 8, 2008 by Brian Crowe, Assistant City Engineer, at a public meeting to the Vancouver Fraserview Killarney Residents Association.

NEU Expansion Opportunities in East

Fraser Lands

Overview

• Business case analysis for EFL NEU conducted in fall 2007 by Compass Resource Management

• Study identified two feasible heat source options:– Metro Vancouver Waste-to-Energy Plant (preferred)– Bio-mass (next lowest cost)

Heat Sources

Metro Waste-to-Energy Plant (Preferred)• Located 4.5km away in Burnaby • Excess heat available for >25years.• 90 - 95% of annual heat from W-to-E.• Requires small Energy Centre (1/3 acre)

at EFL for heat transfer and back-up boilers

• Economics depend upon cost of heat from the plant, requiring further analysis and negotiation.

• Pipeline routing and cost are challenging, but could also serve customers in Burnaby.

Biomass (Next Lowest Cost)• Locally available resource (park waste,

forestry residues) priced significantly lower than pellets

• 65 – 75% of annual energy from biomass

• Requires large Energy Centre (1 acre) at/near EFL

• Fuel deliveries of 4 trucks per week in peak winter period.

• Emissions comparable to natural gas.

A screening analysis of numerous heat sources (including sewer heat recovery, ground source, etc.) was undertaken. The two most viable sources for EFL are:

GVRD WTE Plant and Possible Pipeline Route

NEU Challenges (City-wide)• Funding

– High initial capital cost (est’d $26 M for EFL; $28M for SEFC)– City vs. private ownership?

• Expansion– Only economical for large

developments– Public acceptance

difficult for some heat sources

– Old steam systems difficult to modernize

– City-wide energy strategy needed

EFL NEU Study Conclusions

• An EFL energy utility served by Metro Vancouver’s W-to-E Plant could be financially viable and environmentally beneficial, when compared with SEFC and other energy utilities in B.C.

• Viability is sensitive to many variables, such as pace of development, capital costs, and heat pricing from the Waste-to-Energy Plant.

• Metro Vancouver and ParkLane are motivated to continue developing the proposal.

EFL NEU Study Next Steps

• Report to Council (Spring 2008) and to Metro Vancouver Board

• Develop Memorandum of Understanding between City and Metro Vancouver to confirm viability and costs of heat recovery from Waste-to-Energy Plant

• Incorporate NEU into EFL Rezoning

Figure 12 - City presentation to VFK Residents Association

EFL NEU Study Next Steps Cont’d

• Establish Heat Supply Contract with Metro Vancouver

• Determine Ownership & Operations– EFL NEU– Pipeline from WTE Plant to EFL Site

• Begin infrastructure design & development (first heat delivery late 2011)

Questions & Answers

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9.2.3 Sample story board from open houses

Figure 13 - Sustainability story board

9.2.4 New Water disclosure statement Polygon Homes is the builder of New Water and has commenced marketing. Purchasers are provided with a disclosure statement in accordance with the Real Estate Development Marketing Act. The following are the references to the DEU taken verbatim from the disclosure statement. The full disclosure statement will be provided under separate cover.

In the ‘Utilities’ section 3.9(f)f (p20) “District Energy Utility – The heat and domestic hot water needs of the Development including the Strata Lots will be met by hot water pumped through insulated pipes. The District Energy Utility will be a private utility, will be operated by a private entity, and will be regulated by the British Columbia Utilities Commission, a regulatory agency of the Provincial Government. Initially, following occupancy of the Development, hot water will be generated and used to heat the Strata Lots by an off-site high efficiency natural gas powered boiler(s). At some point in approximately three to seven years it is anticipated that the source of hot water will change to an alternate source generated from a permanent facility which may or may not be located within the River District Masterplanned Community. The operator of the private utility will bill the Strata Corporation which will allocate the costs in accordance with each Strata Lot’s entitlement and the budgets

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attached to this Disclosure Statement have been prepared accordingly. The estimated costs of heat and domestic hot water for each Strata Lot are included in the amounts shown on the Exhibits entitled “Temporary Unit Entitlement and Monthly Contributions: and “First Annual Unit Entitlement and Monthly Contributions”

In the ‘Title and Legal Matters’ section 4.3.2(f) (p25) Covenant in favor of the City of Vancouver to “provide that prior to the issuance of any occupancy permit, the Developer must build the mechanical system of the buildings in such a way that will enable the most efficient connection to a district energy utility, and complies with the design and technical requirements specified in the agreement therein, all subject to the City’s approval. The owners will be obligated by contract or by statute to connect to and make exclusive use of the district energy system”

In the ‘Title and Legal Matters’ section 4.3.2(g) (p25) Statutory Right of Way in favor of the City of Vancouver to “grant to the City and its personnel, with workers, vehicles, equipment and materials, the right to enter on the Lands to inspect, conduct investigations, install, maintain, repair or remove the district energy utility system and do anything incidental or desirable in connection with the district energy”

In the Common Expenses Proposed Interim Operating Budget (Exhibit F, p59) the District Energy Utility is listed at $90,000

In the Common Expenses Proposed First Annual Operating Budget (Exhibit H, p66) the District Energy Utility is listed at $180,000

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9.3 Appendix 3 – DEU Information for developers The following document was prepared for stakeholders as a general overview of DEUs and to provide developers with performance standards to be met by buildings constructed at River District. Polygon requested a copy to inform its sales staff and to provide to prospective homebuyers.

River District District Energy Utility

Information for Developers May 2011

Disclaimer: The following information is provided for general use and the user assumes all responsibility. The information contained within is general in nature and does not substitute for the execution of detailed engineering relative to specific projects or problems. River District Energy nor any of their contractors or employees give any warranty expressed or implied, or assume any legal liability or responsibility for the accuracy, completeness, or usefulness of any information, product application, or process disclosed within this document. Nor are they liable for consequential damage whatever (including, without limitation, damages for loss of business profits, business interruption, loss of business information, or other losses) arising from the use of inability to use this document.

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Table of Contents 1. Document Overview ............................................................................................ 3

2. Summary ............................................................................................................. 4

3. DEU Description.................................................................................................. 7

4. Billing and Cost of DEU Service ........................................................................ 12

5. Technical Requirements for Buildings ............................................................... 13

6. Requirements for Hydronic Systems Connected to the DEU ............................ 16

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1. Document Overview This document provides preliminary information to allow developers to anticipate the thermal service conditions that will be provided in the River District (RD) development and to enable developers to make appropriate provisions in designs to take full advantage of the benefits offered by the District Energy Utility (DEU). As a follow-up to this document, the DEU will work closely with the RD development community, to ensure good design integration between new buildings and the energy utility.

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2. Summary 2.1 What is District Energy?

District Energy, also known as community energy, neighbourhood energy, and district heating, is a cooperative effort between local communities and developers to provide heating for an entire development in the most efficient and sustainable way, balancing factors such as cost, exposure to fuel price fluctuations, reliability, and local air and GHG emissions.

In RD, there is ongoing cooperation between River District Energy, ParkLane Homes, Polygon Homes, other developers, the City of Vancouver, and other stake holders in the area to develop a district heating system to serve space heating and domestic hot water needs of new buildings in the development.

2.2 Why Do We Want It?

Over the last 50 years, community energy has significantly reduced consumption of fossil fuel in many communities around the world. This has often been achieved by starting with conventional technology (e.g. boilers) at higher efficiencies, then eventually supplementing or replacing fossil fuel with renewable resources. The DEU system proposed for RD is expected to follow a similar path.

The capability of community energy to access renewable energy is a crucial advantage. In contrast, the business-as-usual approach builds in long-term dependence on fossil fuel and electricity.

Eliminating the capital, maintenance, operational, and repair/replacement cost of in- building heating equipment allows developers and building owners to make buildings greener at a lower total cost than green buildings without community energy. Moving heating equipment out of the buildings significantly reduces risks associated with maintaining that equipment and frees up areas that would normally be part of a mechanical room for other uses. The risks associated with delivering heat reliably are transferred to the DEU, while the Owner benefits from the assured cost of reliable service from the DEU.

Community energy is aligned with the principles of quality and higher standards. The primary heating supply will always be available. It is more reliable than in-building or in- suite mechanical systems and is quieter, safer and more durable. Service calls will be less frequent. The buildings can be free from combustible fuels. Electrical service can be downsized. There will be more useful space both inside the building and on the roof with no stacks or make-up air heaters. Hence the roof space will be less cluttered and available for other uses.

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2.3 How Will the DEU Work in RD? The heat and Domestic Hot Water (DHW) needs of the buildings in RD will be met by hot water pumped through buried pre-insulated pipes supplied by one or more central Energy Centres (ECs). The ECs may employ different technologies to produce hot water. This will evolve over time in response to changing fuel prices and technologies. Such changes would be more challenging in the business-as-usual approach, as it would entail disruptive retrofits to numerous individual buildings.

The first EC will use high efficiency natural gas fired boilers. It is intended the second EC, which would be built once RD is sufficiently developed, will recover waste heat from the Metro Vancouver Waste to Energy Facility (MV WTEF). This heat will provide the base load heat energy to RD, supplying most of the heating needs in the community. Once the second EC is operational and the waste heat is available to the DEU, the natural gas boilers in the first EC would be used mainly to provide additional capacity during peak heat demand periods (i.e. extreme cold weather events) and as backup in the event the waste heat source is temporarily not available.

2.4 How Will the DEU Change Building Design?

Developers will be required to heat their buildings using hot water only, but they will have flexibility in designing the building internal heating systems in accordance with their preferences and specific requirements. They will receive support and guidance from River District Energy in designing their HVAC systems to derive the most benefit from the DEU.

Thermal energy will be delivered to the buildings via heat exchangers, thereby eliminating boilers, furnaces, hot water heaters, and all such equipment, along with auxiliary systems such as stacks, natural gas service, and related controls and alarms.

The DEU will design and install the necessary pipes, heat exchangers and associated controls and energy meters to interface with the buildings. This equipment, usually referred to as the Energy Transfer Station (ETS), would be owned and operated by the DEU and located inside the customers’ buildings. The preferred location for the ETS is in the basement or ground floor, and it will occupy approximately 20% of the space typically occupied by conventional boiler plants in buildings. See Figure 2 as an example of a typical ETS.

The DEU distribution pipelines will be buried in the roads throughout RD. Branch lines from the DEU distribution pipelines will be connected to each building’s ETS.

2.5 How Much Will It Cost?

The capital cost of the DEU will be financed by the DEU and recovered through rates charged to customers, subject to limits imposed by the BC Utilities Commission. DEU charges are expected to be more stable and less sensitive to changes in broader

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electricity and natural gas prices because alternate heat sources are intended to be utilized.

As with conventional systems, the Developer / building owner will be responsible for the in-building hydronic system.

2.6 Who Will Own The DEU And Bill Customers?

River District Energy will own the DEU and will bill customers. Customers will include all owners of new buildings in RD except for the townhouse development in Area 2.

River District Energy is a privately owned company regulated by the British Columbia Utilities Commission (BCUC). This BCUC regulation ensures that the DEU is operated such that customers receive safe and reliable energy services at fair rates. The BCUC also regulates BC Hydro, Fortis BC and other utility service providers in BC.

River District Energy is related to a group of diverse businesses that also include Parklane Homes and Wesgroup Properties.

2.7 DEU Contact Information

For more information, contact Robin Petri of River District Energy at 604-648-1867.

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3. DEU Description

The DEU will supply the entire thermal energy demand for each new building in RD, and will consist of three main systems:

• Central Energy Centre(s) (EC) • Thermal Distribution System • Energy Transfer Stations (ETS)

The DEU involves a closed loop hot water distribution system: the same water is heated in the EC(s), distributed to the buildings, through the ETS, and returned back to the EC to be reheated and redistributed. No water is drained or lost in the system and no additional water is required during normal operation.

3.1 Central Energy Centre(s)

The concept for the East Fraser Lands DEU involves two permanent EC’s. The first EC will use natural gas boilers only, similar to those used in large commercial buildings. A second EC will be built once RD is sufficiently developed, and is intended to recover waste heat from the Metro Vancouver Waste To Energy Facility (WTEF).

This second EC will become the primary heat source, serving the majority of the community’s heating needs. The natural gas boilers in the first EC will provide supplemental heat to meet peak and back-up demand requirements. The gas-fired boilers will be sized to supply 100% of the energy needs of the community in the event the heat from the MV WTEF is temporarily unavailable.

The production equipment and controls will be state-of-the-art, based on the best of today’s commercially proven technology. Other energy conversion technologies will be continually evaluated in light of new and emerging opportunities. The DEU infrastructure will be designed to facilitate the future use of new renewable energy sources for heating and power.

Prior to final commissioning of any new building in RD, all the thermal energy that it will need will be available through the DEU, from either interim or permanent energy supply facilities. The first few buildings in RD will be served by an interim EC while the first permanent EC is being constructed.

The capacity of the DEU will be gradually increased throughout the development of RD and will be sufficient to meet the total thermal energy needs of all connected, in-service buildings with a higher level of reliability than is generally found in standalone heating systems in individual homes or commercial and multi-use residential buildings.

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Hot

Wat

er T

empe

ratu

re (º

C)

3.2 Thermal Distribution System The distribution system will employ a two-pipe system: one to supply water to each customer building, and one to return the water to the EC(s). The distribution will generally be composed of pre-insulated direct bury piping with welded valves and fittings. Piping will be routed through underground parking lots or buildings as necessary.

Flow through the distribution system is maintained by variable speed pumps controlled to maintain sufficient pressure and flow at every ETS. The supply and return temperatures of the DEU distribution system for heating will be as listed in Table 1.

Table 1: DEU Thermal Distribution System Temperatures

Winter Summer Supply 95°C 65°C Return 55°C 45-50°C Difference (∆T) 40°C 15-20°C

The DEU supply temperature set point will be automatically adjusted based on the Outdoor Air Temperature (OAT), as shown in Figure 1. Achieving a large ∆T is important in order to minimize the DEU capital and operating costs for a given level of capacity. Low heating return water temperatures are important for the optimal use of renewable and low grade heat sources.

Figure 1: Temperature Reset Curve for Vancouver (typical)

90

80

70

PRIMARY SUPPLY

60

50 PRIMARY RETURN

40

TYPICAL SECONDARY RETURN*

30

TYPICAL SECONDARY SUPPLY*

20

10

0

-10 -5 0 5 10 15 20 25 30

Outside Ambient Temperature (ºC)

* - Space heating only, direct primary DHW heating with Max. 60ºC DHWS.

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3.3 Energy Transfer Stations

Each building will normally have its own ETS that is owned by the DEU. The key components of an ETS generally include:

1. Hot water supply and return pipes from the building penetration (interface with

distribution system); 2. Heat exchangers to transfer the heat to the building’s hydronic heating systems.

Generally, two heat exchangers are used: one for space heating and the other for generation of domestic hot water (DHW);

3. Controls to regulate the flow required to meet the building’s energy demand and maintain the DEU return temperatures; and

4. Energy meters to monitor the energy used by each customer for billing and system optimization purposes.

Figure 2: Typical ETS Installation in Building Basement

As shown in Figure 3, flow though the ETS is controlled to achieve the design supply temperature to the building on the secondary side (i.e. on the building internal hydronic heating system).

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DISTRICT HEATING SYSTEM

OFFICES OR INDUSTRIAL BUILDING

Figure 3: Typical In Building ETS Flow Schematic

The thermal energy metering system is an important component of the ETS. Thermal energy meters (Figure 4) consist of flow rate meters, temperature sensors on both supply and return pipes, and an integrator/calculator/data logger.

Figure 4: Thermal Energy Metering System

DEU Building The energy meter will collect data on cumulative water flow (in litres), cumulative energy (in Megawatt-hours thermal – MWht), peak thermal power demand (in kilowatts thermal – kWt), flow rate (in litres per second), supply and return temperatures, and temperature difference (∆T). The data from each meter will be transmitted to a central DEU computer, to monitor and optimize performance of the DEU and buildings, as well as determine the energy used by each customer for billing purposes.

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Sub-metering of individual suites or premises is the Developer's or building owner's choice and its implementation would not affect the DEU system as it would be installed on the secondary side (i.e. building owner's side) of the heat exchanger. The building owners may, at their option, install meters on each individual unit or suite. The building owner would be responsible for installation cost, operation and maintenance of the sub- metering system. This would not affect the obligation for the building owner to pay the DEU bill for the whole building based on the DEU thermal energy meters that are part of the ETS.

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4. Billing and Cost of DEU Service

The DEU will be responsible for the installation and operation of the ETS metering to measure total thermal energy supplied to each building and for submitting monthly bills to each building owner for DEU service to their buildings. The building owners may allocate the bills to the individual units within each building as they see fit. This is analogous to the usual practice in natural gas billing of multi-unit residential buildings, whereby Fortis bills the landlord of an apartment block or a condominium corporation.

4.1 General Principles

The DEU will be regulated by the British Columbia Utilities Commission (BCUC). The BCUC is a regulatory agency of the Provincial Government, operating under and administering the Utilities Commission Act. The Commission is responsible for ensuring that customers receive safe, reliable and non-discriminatory energy services at fair rates from the utilities it regulates and that shareholders of these utilities are afforded a reasonable opportunity to earn a fair return on their invested capital. The Commission's function is quasi-judicial and it has the power to make legally binding rulings. Decisions and Orders of the Commission may be appealed to the Court of Appeal on questions of law or jurisdiction. The BCUC is responsible for regulating all privately owned utilities in BC including Fortis BC, Corix and others.

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5. Technical Requirements for Buildings

The following sub-sections outline technical requirements and identify the respective responsibilities of the Developer and the DEU to ensure that all the new buildings in RD are designed and constructed in a way that maximizes the DEU’s operational efficiency.

5.1 HVAC Systems – Developer Prime Responsibility

The building developers will be responsible for designing and installing their HVAC systems. There will be some differences and similarities with conventional systems, as explained below.

The following conventional building elements will not be required:

1. Boilers, furnaces, heat pumps, domestic hot water heaters or any heat

production equipment 2. Auxiliaries to heating systems such as stacks 3. Natural Gas service

The building will require internal thermal distribution systems, including:

1. Internal distribution pumps 2. Internal distribution piping 3. Heating elements, e.g. fan-coil units, air handling unit coils, and/or perimeter or

radiant heating The following are some design conditions that are specific to district energy:

1. The building will host branch lines from the DEU distribution pipelines. The DEU

branch lines will enter the building, similar to other utilities, and transfer heat via pipes to the ETS. To reduce DEU piping inside the building, it is best if the ETS is as close as possible to the DEU’s branch pipe line entering the building – generally on an exterior wall at ground level or in the basement of the building.

2. The building owner in conjunction with the DEU will agree to a suitable position for the ETS. The ETS will invariably require less space than the heat production equipment (e.g. boiler, heat pump) that the ETS displaces.

3. Whereas buildings not connected to the DEU may or may not have hydronic systems, buildings connected to the DEU are always hydronically heated.

4. The DEU will operate most effectively and efficiently with the use of low temperatures in the building heating systems. The building secondary side temperatures listed in Table 3 below should be considered the maximum allowable at design conditions, with appropriate outdoor air resets in place to reduce the supply temperature at higher outdoor air temperatures.

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Table 3: Building HVAC Heating Temperatures in Relation to DEU (For Fan Coils)

DEU (Primary Side) Temperatures

Maximum Allowable Building (Secondary Side) Space Heating Temperatures1

Winter Summer Winter Summer Supply 95°C 65°C 70°C 60°C Return 55°C 45-50°C 50°C 45°C Difference (∆T) 40°C 15-20° C 20°C 15°C

The DEU will provide a peer review of each building HVAC design, but will not be responsible for the design, which will be executed by the builder. The DEU will make suggestions as deemed necessary for achieving the required temperature profiles. Some potential design strategies for achieving the specified building secondary side temperatures are outlined in Section 6.

5.2 ETS Connection – DEU Prime Responsibility

The DEU will design, install, operate and maintain the ETS at a location agreed upon by the DEU and Developer. Due to hydraulic considerations, the preferred location is in the basement or ground floor levels.

The space required for an ETS varies with circumstances, but generally should be no greater than 10 m2 (not including the piping from the wall penetration to the ETS).

The DEU will require easements to install and maintain the ETS. The DEU will produce the required easement drawings during the detailed design stage. The building contractor will connect the building HVAC system to the load side of the ETS at demarcation points that distinguish the builders’ responsibility from that of the DEU.

A single ETS may serve a group of town houses or other small buildings via secondary systems, owned by the building owner. In this case, heat exchangers for space heating are not required in each building that is served by the secondary system, though a heat exchanger is required for domestic hot water (DHW), unless that is piped directly from the main ETS.

5.3 Branch Connections – DEU Prime Responsibility

The DEU will install, own and maintain the primary distribution pipes up to the ETS. Branch pre-insulated pipe lines will generally be direct buried from the mainline to the building penetration. From that point, primary piping will be run inside the building to the ETS.

1 These values are the maximum allowable in any situation. Note that maximum temperatures for specific equipment or designs may be lower. See Section 6.3 for further details.

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Easements will be required for installation and maintenance of the service entries and branch connections. The DEU will submit drawings of the required easements to the developer, after consultation with the Developers' architects and engineers.

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6. Requirements for Hydronic Systems Connected to the DEU 6.1 Introduction

This section provides technical information for hydronic space heating and domestic hot water systems for new developments in RD. The design information provided in this specification should be regarded as a general guideline only, and the Developer’s Engineer shall be responsible for the final (building specific) design. The DEU will provide technical assistance to building developers to ensure an effective integration between building mechanical design and the DEU.

6.2 Pumping and Control Strategy

The building heating system shall be designed to maximise ∆T over all conditions.

It is preferable that the building heating system be designed with a variable volume hot water flow (preferably with variable speed pumps to minimize pumping energy), using 2- way modulating (or on/off) control valves at terminal units (radiators, fan coil units, etc). Alternatively, 3-way mixing valves that re-circulate return water to the terminal units can be used. Bypass valves (e.g. 3-way bypass valves) are not permitted.

The secondary supply temperature (from the ETS) shall be reset based on outside air temperature.

6.3 Hydronic Heating and Domestic Hot Water Systems (Minimum) Requirements

6.3.1 Hydronic (Space) Heating The hot water hydronic heating system shall be designed to provide all space heating and ventilation air heating requirements for the whole building, supplied from a central ETS location within the building. Gas fired ventilation equipment (roof top units, air handling units, etc.) are not compatible.

Hot water generated by the ETS shall be distributed, via a 2-pipe (direct return) piping system, to the various heating elements (sinks) throughout the building. The building (secondary) heating system shall be designed within the maximum allowable temperatures specified below.

The specified differential temperature (∆T) shall be regarded as a minimum requirement, and larger ∆T is desirable. The building return temperatures must be kept to a minimum to allow the DEU central Energy Centre to take advantage of alternate technologies.

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Hydronic Radiant Floor Heating

Radiant floor heating shall be provided by tubing installed within the floor structure just below the surface. The floor heating shall be designed for the following maximum temperatures: (HWS = hot water supply, HWR = hot water return):

Secondary System: HWS: HWR:

45oC 35oC

Fin Type Baseboard Convectors / Perimeter Radiators

The radiant heating requirements shall be provided by commercial fin-type baseboard convectors with a minimum of 2 passes, or perimeter style radiant panels (i.e. radiators) mounted on the perimeter (i.e. on exterior walls). The baseboard convectors and wall mounted radiant panels shall be designed for the following maximum temperatures:

Convectors Secondary System: HWS: HWR:

Radiators Secondary System: HWS:

HWR:

70oC 50oC 60oC 45oC

Fan Coils

Packaged fan coil units designed with hot water coils mounted on the inside walls can be used to provide individual unit heating. Alternatively, these fan coil units could be in the form of reheat coils in the supply air stream of air handling units (e.g. in a variable air volume system). The fan coil units or reheat coils shall be designed for a minimum of a two row coil and the following maximum temperatures:


70oC 50oC

Ventilation Make-Up Air Units

Heating coils for ventilation (make-up or outside air) shall be designed for the following maximum temperatures:


65oC 45oC

6.3.2 Domestic Hot W ater

The Domestic Hot Water (DHW) system shall be designed to provide all DHW requirements for the building, supplied from a dedicated DHW heat exchanger from the central ETS in the building. The DHW system shall be designed to minimize storage, and instantaneous DHW heating implemented where agreed upon by the DEU and Developer. The DHW system shall be designed such that domestic cold water (DCW) enters the system immediately before the DEU heat exchanger, to help reduce DEU

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return water temperatures. The DHW shall be designed and capacity selected based on: Domestic Hot Water System DCH: 5oC DHW: 60oC

River District Energy Application to the BC Utilities Commission For a Certificate of Public Convenience and Necessity

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9.4 Appendix 4 - Letters of support 9.4.1 City of Vancouver


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9.4.2 Metro Vancouver


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9.5 Appendix 5 - Technical studies The following technical studies are provided under separate cover

• NEU Update for EFL Area 2 Rezoning, Compass Resource Management Ltd, August 11, 2009

• Business Analysis for a Neighbourhood Energy Utility in the East Fraserlands of Vancouver, Compass Resource Management Ltd, September 2007

• Potential Heat Sources For a Neighbourhood Energy Utility at City of Vancouver East Fraser Lands, FVB Energy Inc., March 21, 2007


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9.6 Appendix 6 - Financial model A working copy of the full financial model has been provided in confidence under separate cover. The following tables contain the key outputs.

9.6.1 Capital and rate base


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9.6.2 DEU Earnings and taxes


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9.6.3 Revenue requirements


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9.7 Appendix 7 - DEU system designs 9.7.1 Temporary boiler design


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9.7.2 Phase 2A DPS design The following is an extract from the detailed design of the Phase 2A DPS. The full set of design drawings issued for construction are available on request.

Business Analysis for a Neighbourhood Energy Utility

in the East Fraserlands of Vancouver FINAL REPORT

Prepared for:

Engineering Services Department City of Vancouver

Contact person:

Brian Crowe, Assistant City Engineer, Water and Sewers

And

Parklane Homes / WesGroup Income Properties

Contact person:

Brent Tedford Development Manager, WesGroup

Prepared by:

Compass Resource Management Ltd. # 200 – 1260 Hamilton St.

Vancouver, B.C. V6B 2S8 Canada

In association with FVB Energy Inc.

Contact Person:

Trent Berry, Partner, Compass Resource Management Ltd. 604-641-2875

September, 2007

Compass Resource Management Ltd. September, 2007

EFL NEU Business Analysis Page i

Executive Summary

East Fraserlands (EFL) is a 51 ha parcel of waterfront land situated in the South East corner of Vancouver, between Boundary and Kerr, on the Fraser River (Figure 1). Under a development plan prepared by Parklane/WesGroup, the site would comprise a mix of housing types and services. EFL is being designed to achieve a high level of environmental performance. One alternative being considered to improve environmental performance is the creation of a Neighbourhood Energy Utility (NEU) to provide space heating and domestic hot water within the site using high-efficiency natural gas boilers and alternative energy sources. A similar NEU is currently being developed by the City of Vancouver to serve the Southeast False Creek (SEFC) ODP area using a combination of high-efficiency natural gas and sewer heat recovery. Parklane/WesGroup partnered with the City of Vancouver to sponsor this study on the feasibility of an NEU for EFL. The study was conducted by Compass Resource Management Ltd. and FVB Energy Inc. This report summarizes the business analysis, including key input assumptions derived from the various technical analyses prepared to support the business analysis. The detailed technical memoranda prepared for this study are consolidated in a companion report. The business analysis assumes a stand-alone utility with its own management, insurance and working capital requirements. The business analysis considers three demand forecasts – high, base and low – which were prepared in consultation with Parklane/Wesgroup. A wide range of possible heat sources were considered including groundsource heat pumps, sewer heat, biomass and waste heat from the Metro Vancouver Waste-to-Energy (WTE) plant in Burnaby.1 The Metro Vancouver WTE plant was selected as the preferred alternative and used in the base case analysis. A biomass plant using local woodwaste, including waste residues from City parks, was considered as the next best alternative in terms of GHG emissions and costs. Utilization of waste heat from the Metro Vancouver WTE plant would require the installation of a ~4.5km pipeline to the site, as well as heat extraction equipment at the Metro Vancouver WTE plant. The costs of this equipment are included in the business analysis. Preliminary discussions regarding this opportunity have taken place between the City of Vancouver, Parklane/Wesgroup, Metro Vancouver and the operator of the Metro Vancouver WTE plant, Veolia Environmental Services. While Metro Vancouver and Veolia have expressed interest in this opportunity, the cost of heat from the plant is not known at this time. The extraction of heat for district energy would increase overall utilization of waste energy from the plant, but would have some impact on electricity production at

1 Metro Vancouver is the new name of the Greater Vancouver Regional District or GVRD.

The Metro Vancouver WTE plant is also referred to in some documents as the Burnaby Waste Incinerator or BWI.


EFL NEU Business Analysis Page ii

the plant. For the purposes of the business analysis, a cost of heat from the plant was calculated that would achieve a rate of return for the NEU comparable with other energy utilities in B.C. given projected demands and other capital and operating costs that were estimated for this alternative. Based on the capital costs of the pipeline and the demand forecasts and utilization expectations, the optimal timing of the installation of the pipeline to the Metro Vancouver WTE plant is in approximately 2015 under the base (moderate) demand growth scenario. To achieve a target real (unlevered) return of 5.3%, the NEU could pay Metro Vancouver up to $13.75/MW.h for the heat (real levelized cost at the plant gate) under the various assumptions for other capital and operating costs, including the cost of the pipeline. For comparison under the base case assumptions for a biomass plant, the NEU would achieve a real (unlevered) return of 3.9% over 25-years. Sensitivity analyses demonstrate that the project is highly sensitive to load assumptions. Low load growth could make the project uneconomic. Returns are generally favourable for all sensitivity assumptions under the moderate and high load scenarios, as well as more early development of loads within each of these scenarios. As expected, viability is highly sensitive to capital cost assumptions. These estimates will need to be refined in the next phase of detailed design work. However, the analysis also shows that the addition of a small rate premium will improve viability in the event of higher capital costs. A major issue to be resolved is the cost of heat from the preferred heat source – the Metro Vancouver WTE plant. The maximum viable cost of heat from the Metro Vancouver WTE plant varies depending upon the scenario. The WTE plant alternative warrants further analysis by the City, Developer and Metro Vancouver. Recommended next steps are as follows:

• Confirm interest of City and Developer in seeing an NEU proceed within the development.

• Report to Vancouver City Council and Metro Vancouver Board on proposed NEU concept.

• Develop a Memorandum of Understanding between City, Developer and Metro Vancouver to confirm viability and costs of heat recover from Waste-to-Energy (WTE) Plant. Specific recommendations for MoU:

o Metro Vancouver fund / lead assessment of heat recovery options and costs at the WTE plant

o Metro Vancouver, City of Vancouver and Developer co-fund more detailed assessment of pipeline routing and costs

o Metro Vancouver consider incremental opportunities, costs and benefits for capturing additional heat customers along


EFL NEU Business Analysis Page iii

pipeline route, relative to base case assessment focusing strictly on EF.

o Studies be concluded before March 2008 o Issues of pipeline ownership and business structure be

addressed following technical and economic analysis, and tentative heat sales contract

• Public/NGO Consultations. • Finalize Heat Supply Contract with Metro Vancouver (pricing,

terms and conditions) by October 2008. • Determine Ownership & Operations roles & responsibilities by

March 2009. o EFL NEU o Pipeline from WTE Plant to EFL Site

• Begin infrastructure development (first heat deliveries expected in July 2011).


EFL NEU Business Analysis Page iv

Table of Contents

Executive Summary ..................................................................................i Table of Contents .................................................................................... iv List of Figures.......................................................................................... iv List of Tables........................................................................................... iv 1.0 Introduction................................................................................... 1 2.0 Basic Concept and Services ......................................................... 2 3.0 Rationale for a Neighbourhood Energy Utility ............................... 3 4.0 General Approach to the Business Analysis ................................. 5 5.0 Key Assumptions in Business Analysis ......................................... 7

5.1 Energy Demand Forecasts........................................................ 7 5.2 Fuel Price Forecasts ................................................................10 5.3 NEU Revenue Assumptions .....................................................12 5.4 Neighbourhood Heat Distribution System.................................13 5.5 Heat Sources ...........................................................................19 5.6 Staffing.....................................................................................24 5.7 Taxes, Insurance and Working Capital .....................................24 5.8 Grants ......................................................................................25 5.9 Emissions.................................................................................26

6.0 Financial and Environmental Analysis..........................................26 6.1 Base Case Outputs ..................................................................26 6.2 IRR Comparables.....................................................................29 6.3 GHG Reductions ......................................................................30 6.4 Sensitivity and Scenario Analysis .............................................31 6.5 Other Risk Considerations........................................................35

Appendix 1 – Base Case Cashflow Summary ........................................36

List of Figures

Figure 1: East Fraserlands Site ............................................................... 1 Figure 2: East Fraserlands Sub-Areas and Phase 1 Rezoning Application

Boundaries ....................................................................................... 1 Figure 3: Natural Gas Price History and Forecast...................................10 Figure 4: Proposed Layout of Heat Distribution System* ........................15

List of Tables

Table 1: High Build-out Projection (thousands m2).................................. 7 Table 2: Low Build-out Projection (thousands m2)................................... 7 Table 3: Space Heating Energy Use Intensity by Building Archetype ...... 8 Table 4: DHW Energy Use Intensity by Building Archetype ..................... 8 Table 5: High Demand Scenario.............................................................. 9 Table 6: Low Demand Scenario .............................................................. 9 Table 7: Base Demand Scenario............................................................. 9 Table 8: Delivered Fuel Prices ($2007/MW.h) ........................................12


EFL NEU Business Analysis Page v

Table 9: Estimated Length and Diameter of Distribution Pipes by Phase in High Growth Scenario .....................................................................16

Table 10: Distribution Piping Capital Cost Estimates (thousands of $2007)* ...........................................................................................17

Table 11: ETS Capital Cost Estimates – High Load Scenario.................17 Table 12: ETS Capital Cost Estimates – Low Load Scenario..................18 Table 13: Heat Plant Performance and Cost Assumptions (High Growth

Scenario Build-out Capacities and Costs) .......................................23 Table 14: GHG Emission Factors ...........................................................26 Table 15: Summary Results for Base Case - Metro Vancouver WTE

Plant* ..............................................................................................28 Table 16: Summary Results for Base Case– Biomass Plant...................28 Table 17: Benchmarks for Evaluation of NEU Returns ...........................29 Table 18: GHG Emission Reduction Scenarios* .....................................31 Table 19: Summary Results - High Load Growth, Metro Vancouver WTE

Plant................................................................................................32 Table 20: Summary Results Under Low Load Growth, Metro Vancouver

WTE Plant .......................................................................................33 Table 21: Sensitivity Results on Unlevered IRR with Metro Vancouver

WTE Plant (Fixed Heat Cost)* .........................................................33 Table 22: Sensitivity Results on Cost of Heat from Metro Vancouver WTE

Plant with a Fixed Unlevered IRR* ..................................................34 Table 23: Sensitivity Results on Unlevered IRR with Biomass Plant.......34


EFL NEU Business Analysis Page 1

1.0 Introduction

East Fraserlands (EFL) is a 51 ha parcel of waterfront land situated in the South East corner of Vancouver, between Boundary and Kerr, on the Fraser River (Figure 1). A Canadian Pacific Rail corridor bisects the site. The land south of the rail corridor was in use by the Canadian White Pine Sawmill until its closure in 2001, and is now owned by ParkLane Homes / WesGroup Income Properties. The City of Vancouver is the major land owner north of the tracks. Parklane/Wesgroup currently hold an option to purchase these lands. In addition, several small parcels, comprising about 3.6 ha in total, are privately owned and are either vacant or have industrial uses. Under a development plan prepared by Parklane/WesGroup, the site would comprise a mix of townhomes, low- and mid-rise apartments and high-rise towers, together with a retail / commercial Town Centre, High Street and Waterfront Plaza featuring a mix shops and services, including at least one school and a community centre. In November 2006, the East Fraserlands (EFL) Official Development Plan (ODP) received unanimous approval by Vancouver City Council. In February 2007, ParkLane/Wesgroup submitted a rezoning application for the first phase of EFL (Figure 2). Proposed in the first phase of development are a variety of housing types, a neighbourhood retail district, parks, cycling and pedestrian ways, daycare facilities, a 2,790 m2 community centre, enhancements to the Fraser River foreshore, public art and transit service improvements. In April 2007, the first phase rezoning submission received unanimous approval from the Vancouver Urban Design Panel.

EFL is being designed to achieve a high level of environmental performance. One alternative being considered to improve environmental performance is the creation of a Neighbourhood Energy Utility (NEU) to provide space heating and domestic hot water within the site using high-efficiency natural gas boilers and alternative energy sources. A similar NEU is currently being developed by the City of Vancouver to serve the Southeast False Creek (SEFC) ODP area using a combination of high-efficiency natural gas and sewer heat recovery. Parklane/WesGroup partnered with the City of Vancouver to sponsor a study on the feasibility of an NEU for EFL. Compass Resource Management Ltd. was engaged to prepare a business analysis, similar to one it prepared for the SEFC NEU. To complete the business analysis, Compass engaged FVB Energy Inc. to conduct a technical analysis of loads, potential heat sources, and heat distribution alternatives and costs for the NEU. This report summarizes the business analysis conducted for the EFL NEU, including key input assumptions derived from the technical analyses prepared by FVB. The detailed technical memoranda prepared by FVB are consolidated in a companion report.



Figure 1: East Fraserlands Site

Figure 2: East Fraserlands Sub-Areas and Phase 1 Rezoning Application Boundaries



2.0 Basic Concept and Services

The proposed NEU would supply the space heating and domestic hot water (DHW) needs of all buildings throughout EFL via a network of insulated, low-temperature hot water distribution pipes. The NEU may also be able to capture existing or new buildings on sites adjacent to EFL, but given uncertainty over the possibility of retrofitting existing buildings and the timelines for new development on adjacent sites these are not considered in this analysis. Heat would be produced and/or distributed from a central heat plant. The heat plant would ultimately use alternative technologies such as waste heat from the existing Metro Vancouver WTE plant or biomass to provide between 70 and 95% of annual heat demand, with peaking / back-up heat supplied by high-efficiency natural gas-fired boilers. Given the anticipated rate of development, natural gas boilers would be relied on exclusively in the first few years of the system. The alternative energy system would be added when load has reached a suitable threshold to allow high levels of dispatch of the plant, likely between 3 and 5 years after start-up, but this will vary depending upon the rate of load growth and the type of alternative heat source selected. The use of natural gas boilers in early years and for ongoing peaking / back-up helps to ensure the NEU is competitive with other traditional heating alternatives, while still providing significant environmental improvements in the near-term and a platform for adoption of additional alternative technologies in the future. Individual buildings would be served via Energy Transfer Stations (ETS) located on the customer premises that are owned and operated by the NEU. The NEU would meter and bill for consumption at the ETS. Building owners / landlords would be responsible for allocating costs to individual residents and businesses within the building. No sub-metering costs are included in this analysis. Utility-grade sub-metering (metering individual suites with CSA-approved meters) is currently an expensive proposition but there are non-utility-grade metering alternatives that could be used by individual stratas to better allocate NEU charges among residents based on actual heat usage. A district cooling system has not been included in the concept for serving EFL at this time. It is currently estimated that about 15% of the residential units will be cooled, with the majority of cooling being provided along the river-front and in the high-rise towers. Commercial buildings typically have space cooling but these represent a small portion of the total floor area planned for EFL. Based on 15% penetration of cooling in residential units, the total annual energy required for cooling in EFL is less than 10% of the total annual energy required for heating.2 Even with higher penetration of cooling in

2 Increasing the penetration of cooling in the residential sector to 25% would increase the total

cooling load to roughly 20% of the annual energy required for heating. This is still not considered significant in relation to heating loads and would not drastically alter the economics of centralized cooling.



residential units, cooling is likely to be modest relative to heating requirements.3 FVB has found residential district cooling projects to be marginal in Ontario; therefore in Vancouver, where the cooling degree-days are significantly less, they will not make sense financially. Given the dispersed layout of the cooling load, combined with modest cooling requirements, FVB does not believe district cooling to be a cost effective means for space cooling in this development. Cooling would likely be provided on a building-by-building basis using conventional technologies. However, there may be some potential synergies with district heating. For example, excess heat from the Metro Vancouver WTE plant in Burnaby could, depending upon the price, be used cost-effectively in adsorption chillers to provide cooling from a central location, or more likely at individual parcels. The focus of this report is to establish the viability of district heating. Alternatives for delivery of cooling can be considered once the decision to proceed with district heating is made and the heat source is selected.

3.0 Rationale for a Neighbourhood Energy Utility

The NEU being contemplated for EFL would consist of a small central centre that produces hot water through an alternative energy source and high-efficiency natural gas boilers (for peaking and back-up). Hot water from the central plant would be distributed in insulated buried pipes to customers throughout the site. Heat would be extracted from these pipes at a small energy transfer station located in the basement of the buildings and then distributed throughout the building through another set of hot water distribution pipes within the buildings. Cool water is returned from the buildings to the central energy centre to be re-heated. An NEU offers a variety of potential benefits, including:

• Reduced costs – Centralization of heating offers possible cost savings through reduced equipment requirements (due to load diversification),4 economies of scale in equipment costs, savings in operating costs from more efficient equipment and optimized operations, lower financing rates, and longer amortization periods for capital. These potential cost savings must, however, be weighed against any additional costs associated with centralization, such as the cost of the neighbourhood heat distribution system and the additional costs of

3 Climate change could increase cooling degree-days in Vancouver, although the exact effects

of climate change on this region are highly uncertain. For example, precipitation is also expected to increase in this region. In addition, even if more cooling degree-days are expected, the rate of change is uncertain. Current and projected cooling loads are insufficient to justify the large capital outlays for district cooling relative to district heating in the region. 4 Load diversification refers to the fact that the peak demand in different buildings will typically

occur at slightly different times. As a result, the peak demand on the central system will typically be lower than the sum of the peak demands for individual buildings.



establishing and administering a utility. In addition, some of the cost savings associated with centralization could be used in part to invest in more environmentally-friendly forms of heat production.

• Improved quality of service – Because the NEU would deliver hot

water to customers throughout the site, hydronic heating would be used within the buildings. Hydronic heating is generally considered more comfortable than other forms of space heating and a utility can normally undertake more timely and regular maintenance of equipment than individual building owners.

• Improved environmental performance – Economies of scale and other

cost savings from centralization of heat sources can facilitate the use of more efficient technologies or technologies consuming alternative fuels for the same or in some cases lower costs as more conventional on-site technologies. Furthermore, with longer amortization periods and lower financing rates, a utility can more easily use alternative technologies with higher capital costs and lower operating costs while remaining competitive with conventional on-site technologies.

• Reduced risk and increased flexibility – Financial and operating risks

can be pooled across a larger number of customers; implementation of more efficient and alternative technologies can further reduce customer exposure to fluctuating fuel prices; hydronic heating systems are also more adaptable to new technologies over time.

The viability of an NEU in EFL is enhanced by the following factors:

• Fairly large and assured long-term loads; • The ability to coordinate installation of distribution piping and heat

plants with other major site servicing work;

• There are several viable sources of alternative and/or waste energy that could be used by the site; and

• A strong policy framework to support environmental and energy goals

for the site. There are numerous neighbourhood energy systems in operation around the world. In British Columbia, some examples of a utility models for heat delivery include the Lonsdale Energy Corporation (North Vancouver); Revelstoke; and Sun Rivers outside Kamloops.5 A neighbourhood energy system is being developed to serve the Dockside development in Victoria’s waterfront. Whistler is developing a neighbourhood energy system to serve Whistler’s Athlete Village for the 2010 Winter Olympics. The City of Vancouver is

5 Sun Rivers is based on distributed groundsource heat pump systems owned and operated by

a utility.



currently developing an NEU to serve the SEFC ODP area, which includes Vancouver’s Athlete Village.

4.0 General Approach to the Business Analysis

For the purposes of the business analysis presented in this report, no assumption is made about the ownership of the utility. All cash flows and returns are estimated based on a stand-alone entity with its own dedicated management, operators, insurance and working capital requirements. All cash flows and returns are estimated on a pre-income tax basis. Decisions regarding ownership and operation can be made once the fundamental viability of an NEU has been established. The City of Vancouver has committed to develop and initially operate the SEFC NEU. Ongoing City ownership and operation of the SEFC NEU will be evaluated within three years of its commercial operation date. As in SEFC, City and/or developer involvement in the NEU would be valuable during the initial development of the EFL NEU given potential coordination synergies with site planning and servicing. If the City continued to own and operate the SEFC NEU, City ownership of the EFL NEU could have several advantages for customers in both SEFC and EFL, in particular potential synergies and cost savings from shared management, operating staff and administrative functions. City ownership of both utilities also provides additional room for cost savings or environmental investments as a result of the City’s favourable income tax treatment in comparison with a private owner. The following are some key features of the financial analysis conducted to determine the viability of the NEU.

• Revenues for the utility are equated with customer avoided costs using conventional technologies. A sensitivity analysis is conducted using a premium over conventional technologies of up to 10%.6 These revenues are intended to test the viability under a revenue cap and are not intended to reflect an actual rate proposal. Rates would ultimately be set based on the utility’s actual cost of service. Specific revenue assumptions are described more fully below.

• Returns are calculated on a cash flow basis. That is, cumulative

returns are estimated from forecasts of annual revenues, operating costs and capital expenditures, as incurred. In internal rate of return (IRR) is calculated for each year based on cumulative cash flows up to that year. The 25-year IRR is used to test business viability.

• The analysis focuses on the unlevered IRR (i.e., the IRR on total cash

flows, ignoring the effects of financing). As discussed further below,

6 Vancouver City Council has established rate setting principles that allow a premium of up to

10% over the BAU costs to the customer to reflect the qualitative advantages of the system.



the unlevered IRR may be compared to a target or benchmark return. Two benchmarks are considered for comparison purposes – the City’s cost of debt (assuming 100% debt financing) and the weighted average cost of capital for a comparable small energy utility.

• Load forecasts were developed to reflect loads at build out and the

expecting rate of development. High and low forecasts were prepared based on slightly different build out assumptions and rates of development (e.g., 15 years vs. 25 years to full build out). The base case reflects a mid-point between the high and low forecasts. For the purposes of the business analysis, a linear rate of development was assumed within each five-year load increment. In addition, loads were capped at Year 10 for the financial analysis. This simplified the financial analysis. Utility returns are generally expected to stabilize or improve for any load growth beyond 10 years.

• Except for the pipeline to the Metro Vancouver WTE plant, which is

discussed further in the assumptions below, the cash flow analysis assumes no terminal value for utility assets at year 25. This is somewhat conservative since some assets will not have been fully depreciated and would have some residual value if the business remains an ongoing concern at that time.

• GST was excluded from the analysis based on the assumption that the

effect of any GST collection and remittance by the NEU would be neutral on an annual basis. PST and property taxes are considered in the analysis as discussed below.

• All capital cost estimates provided by FVB included a contingency.

Contingencies are excluded from base cash flow analysis and included in the sensitivity and scenario analysis.

• Buildings will be required to have internal hydronic heat distribution

systems to connect to the NEU. These are the responsibility of the developers. Hydronic heat distribution systems would have been required in gas-heated buildings and so there is no incremental cost for connecting these buildings to the NEU. In fact, there are incremental savings associated with the elimination of boilers and associated space within the buildings. In electrically heated buildings, there may be some incremental construction costs associated with converting to a hydronic heat distribution system for connection to the NEU. There is considerable uncertainty and disagreement in the development community regarding the magnitude of the incremental (net) costs. One recent study has estimated a construction premium of up to $11.5/m2 for hydronic heating.7 However, some developers report lower costs and some have even found hydronic heating can add to the sales value. In addition, it is unlikely that green building

7 Compass Resource Management et al. 2003. The Costs and Benefits of Hydronic Heating in

New Multifamily Residential Construction in the Lower Mainland of British Columbia. Prepared for the City of Vancouver, Terasen Gas Inc., and Natural Resources Canada.



performance targets could be met with electric heat. As a result, we have not included any incremental costs associated with in-building hydronic heat distribution systems in this analysis.

• Sensitivity and scenario analysis were prepared to evaluate key risks

and uncertainties.

5.0 Key Assumptions in Business Analysis

5.1 Energy Demand Forecasts The first step in the assessment of the viability of an NEU is to prepare a demand forecast. The starting point for the demand forecast is a forecast of floor area. Two forecasts of floor area were prepared for this analysis. The high build out projection assumes all parcels are developed according to the current ODP floor area targets (Table 1). The low build out projection excludes development of parcels that are currently not owned by the City or Parklane/Wesgroup (Table 2). In addition to the ultimate floor area projection, the scenarios reflect different rates of development. Floor area was allocated among five-year phases in consultation with Parklane/Wesgroup.8 The high scenario in Table 1 assumes a rapid build-out over the first 15 years. The low scenario in Table 2 assumes a slower build-out over 25 years.

Table 1: High Build-out Projection (thousands m2)

Table 2: Low Build-out Projection (thousands m2)

The floor area forecast was converted to an energy demand forecast using energy multipliers derived from energy performance models for representative building archetypes. These archetypes represent an average building. These archetypes and multipliers were originally developed as part of the loads

8 The phases referred to throughout this report are intended to reflect the approximate timing of

development. Phase 1 referred to in the demand forecast does not correspond directly with the areas in the Phase 1 re-zoning application, which is much larger.



analysis for the SEFC NEU feasibility study, which were assumed to exceed the requirements of ASHRAE 90.1-2001 by 20%. The energy use intensity multipliers by building archetype used in this analysis are summarized in Table 3 and Table 4.9

Table 3: Space Heating Energy Use Intensity by Building Archetype

Archetype Peak Space Heating

(W/m2) Annual Net Space Heating

Energy (kW.h/m2)

Retail 30 36

Office 55 58 School/Community Centre 55 44

Live Work 55 58

Row House 40 47

Low rise residential 40 67

Mid rise residential 45 78

High-rise residential 45 78

Table 4: DHW Energy Use Intensity by Building Archetype

Segment Energy Use Intensity (kW.h/m2)

Retail 14

Office 8

School/ Community Centre 20

All Residential 30

The resulting high and low energy demand forecasts at five-year intervals are summarized in Table 5 and Table 6. For the base case analysis, a moderate load growth scenario was created mid-way between the high and low scenarios (Table 7). The coincident peak capacity reflects peak space heating loads for all floor area multiplied by a coincidence (diversity) factor of 90%.10 The forecasts assume that load growth in each phase is evenly distributed across years. In reality, load additions will likely be more lumpy from year-to-year. In particular, the analysis may be conservative with respect to the start-up load in Year 1 given current construction plans.

9 Cooling loads were also estimated in the demand forecast. These are summarized in the

technical memoranda prepared by FVB. However, cooling loads, which are estimated at less than 10% of heating loads, were not considered in the business analysis. 10

When on-site DHW storage is used, DHW typically does not contribute to the system peak in a district heating system – i.e., the system peak is derived entirely from the space heating peak demand. When storage is not used (i.e., instantaneous DHW service), FVB typically allows for 20-25% extra capacity above the peak space heating demand when calculating the system peak for the district energy system. For the purposes of this analysis, on-site storage of DHW has been assumed and DHW is not included in the coincident peak demand on the system.



For the purposes of the pro forma analysis, loads were capped after 2020. This simplifies the analysis. Given the large initial capital outlays, district energy systems are typically very sensitive to load assumptions for the first 10 years. Beyond 10 years, financial returns typically remain stable or increase with further load growth.

Table 5: High Demand Scenario

2010 2015 2020 2025 2030 2035

Floor area (m2) 51,600 310,800 560,400 717,600 735,200 748,000

Annual energy demand (MW.h)

Space heat 3,557 21,393 38,329 48,566 49,697 50,555

DHW 1,470 8,876 16,126 20,786 21,314 21,698

Total 5,027 30,269 54,455 69,352 71,011 72,253

Coincident peak demand (MW) 2.0 11.9 21.6 27.6 28.2 28.7 Note: Load is capped at 2020 for the purposes of the pro forma analysis.

Table 6: Low Demand Scenario

2010 2015 2020 2025 2030 2035

Floor area (m2) 20,400 133,400 288,400 438,400 592,800 692,000


Space heat 1,330 8,883 19,834 30,216 41,058 47,112

DHW 561 3,716 8,188 12,464 17,082 20,002

Total 1,891 12,599 28,022 42,680 58,140 67,114


Table 7: Base Demand Scenario

2010 2015 2020 2025 2030 2035

Floor area (m2) 36,000 222,100 390,500 578,000 664,000 720,000


Space heat 2,443 15,138 26,824 39,391 45,378 48,834

DHW 1,015 6,296 11,175 16,625 19,198 20,850

Total 3,459 21,434 37,999 56,016 64,576 69,684




5.2 Fuel Price Forecasts Fuel prices are an important input to the pro forma analysis. They determine in part revenues (i.e., customers’ avoided costs under BAU scenario) and also NEU operating costs. Using existing prices or tariffs for a long-term investment analysis is not appropriate because these prices are likely to change over the timeframe of the investment. Forecasts of fuel prices were prepared for the purposes of this analysis. However, it is important to recognize the uncertainty surround future fuel prices, particularly the commodity (vs. transportation) component of fuel prices. Natural gas commodity prices in particular are very volatile and current prices may not be a reasonable indicator of long-run average price trends. Figure 3 provides an illustration of historical price volatility at two trading hubs in North America. As shown in Figure 3, long-term forecasts of natural gas commodity prices typically consider only long-term trends and do not attempt to predict cyclical patterns. While price spikes (and valleys) are likely, long-term price trends are adequate for a long-term investment analysis.

Figure 3: Natural Gas Price History and Forecast

Source: Sproule Associates Ltd., March 2007

Terasen’s rates for natural gas include a delivery charge and a commodity cost. The gas commodity cost is a flow-through of average market prices for natural gas. For the purposes of this analysis, real delivery charges for natural gas were assumed to increase at 0.5% per year over the 25-year investment analysis. This was considered conservative given the modest rate



of growth anticipated in natural gas consumption in the region and the age of the existing infrastructure. The average delivery charge for the commercial customer class was used for both the NEU’s gas delivery costs and avoided customer costs (multi-family residential construction is typically included in the commercial class). The delivery charge includes both capacity and energy billing determinants. We calculated separate average delivery charges for situations where all energy would be provided by natural gas and situations where natural gas is used only for peaking purposes. Because of the capacity charge, the average delivery rate for peaking supplies is higher than for full energy requirements, reflecting the intermittent nature of peaking and back-up requirements. The long-term gas commodity cost, which is a flow-through in Terasen’s rates, was estimated using a publicly available forecast from March 2007 prepared by Sproule Associates Ltd. in Calgary. Many long-term price forecasts, such as those from Sproule and the U.S. Energy Information Administration, show a near-term decline in natural gas prices from recent highs followed by a resumption of moderate long-term real upward price growth.11 BC Hydro electricity rates are not currently separated into delivery and commodity components. However, we developed separate assumptions for commodity costs and delivery cost (i.e., transmission and distribution) to facilitate forecasting. The commodity cost is based on the estimated average embedded cost of generation that was provided in BC Hydro’s recent Heritage Contract Hearing (~$26/MW.h). The delivery portion is estimated as the difference between existing average bundled residential rates (~$65/MW.h) and the embedded cost of generation. The provincial government froze BC Hydro rates for more than 8 years prior to 2003. Since 2003, BC Hydro rates are now again regulated by the BCUC. Some significant rate increases are anticipated for electricity in the next few years based on the need to refurbish and replace aging facilities (e.g., the transmission system to Vancouver Island) and to recover significant incremental (higher cost) investments in new transmission, generation and distribution infrastructure to meet load growth. Load has been growing at an increasing pace in recent years. The provincial government has also announced policies to increase green generation and reduce GHG emissions, enhance domestic production, support new technologies, and support remote community electrification, all of which could put additional upward pressure on rates. For the purposes of this study, we assumed real increase in both the electricity commodity and delivery costs of 1.0% per annum for the entire study horizon. Table 8 summarizes the base case forecast for delivered natural gas and electricity on an equivalent $/MW.h basis. Natural gas costs less than electricity on a $/MW.h of fuel basis but there are efficiency losses and additional capital costs for producing heat with natural gas. Currently, the levelized cost of space heating with natural gas is approximately equal to electricity on an all-in basis.

11

EIA forecasts can be found at http://www.eia.doe.gov/oiaf/aeo/pdf/trend_4.pdf.



The business analysis considers biomass as a potential heat source for the NEU. There are two main types of biomass fuel. One is wood residues from city parks, commercial operations (e.g., warehouse pallets), and local forestry and milling operations. These residues are chipped but otherwise unprocessed. Another alternative is wood pellets, which are processed and dried wood wastes from milling operations. Processing reduces the moisture content and increases the energy density of the fuel, reducing shipping and storage costs and improving the combustion efficiency. However, most pellets produced in B.C. are currently shipped overseas and prices tend to be only slightly lower than natural gas (on an equivalent heating value basis). Unprocessed wood residues are typically much cheaper than pellets, although the price of residues can still vary considerably, ranging from revenue stream (tipping fee) to a significant cost. Transport costs can also be a large contributor depending upon source. However, there is a reasonable volume of local park wastes that are currently landfilled and would have little or no cost for an energy facility. For the purposes of this analysis, an average cost of $3.30/MW.h is assumed for unprocessed wood residues. This price is assumed constant (in real dollar terms) as few competing uses are anticipated.

Table 8: Delivered Fuel Prices ($2007/MW.h)

2010 2015 2020 2025 2030 2035

Natural gas burner tip

Residential 32.11 32.09 32.14 32.35 32.56 32.78

Commercial full energy 31.06 31.01 31.04 31.22 31.41 31.60

Commercial peaking 36.84 36.94 37.12 37.45 37.79 38.14

Delivered electricity

Residential 71.91 75.58 79.44 83.49 87.75 92.23

Commercial 54.43 57.21 60.13 63.20 66.42 69.81

Delivered biomass

Wood residue 3.30 3.30 3.30 3.30 3.30 3.30

Pellets* 27.96 27.91 27.94 28.10 28.27 28.44 *Indexed to natural gas.

5.3 NEU Revenue Assumptions For the purposes of the business analysis, NEU revenues are indexed to the business as usual (BAU) energy costs of customers. In the absence of the NEU, each building would be responsible for its own heating system. Traditionally, heating systems are installed by developers and owned and operated by the ultimate building owners. Under the status quo or business as



usual scenario, about 70% of residential buildings would be heated with electricity.12 Most commercial buildings would be heated with natural gas. For simplicity, all revenues from commercial customers are tied to the price of natural gas heat while all revenues for residential customers are tied to the price of electricity. Commercial revenues reflect the delivered price of natural gas adjusted for average equipment efficiency (~70%). In addition, commercial revenues reflect the avoided cost of boiler equipment and maintenance, currently estimated at $30/MW.h based on a recent study comparing natural gas and electricity heating. The base case assumes no premium over BAU costs. The resulting average revenue from residential and commercial customers in 2010 is $74/MW.h and $72/MW.h, respectively. Average revenues are indexed to the underlying fuel price forecasts. For comparison, the projected average rate in 2007 for Central Heat in downtown Vancouver is $68 / MW.h, including fuel recoveries. The current rates for Lower Lonsdale Energy Corporation in North Vancouver range between $80 and $90 / MW.h after their recent rate redesign. A premium of up to 10% over BAU gas and electricity costs is considered in the sensitivity analyses. This level of premium is consistent with a target ceiling established by City Council for the SEFC NEU. A premium is not desirable but is considered acceptable based on the qualitative differences between the NEU service and BAU heating (e.g., higher service quality, lower long-term fuel price risk, lower environmental impacts, etc.).13 Using these assumptions, average revenues for both the commercial and residential customers start at $79/MW.h in 2010 and are indexed to natural gas and electricity price forecasts beyond 2010. The assumption for average revenues is used to test the viability of the NEU relative to gas and electric heat (with a small premium to reflect qualitative benefits). Final rates would be determined based on actual costs of service and could be lower than the revenue cap used for the purposes of this screening analysis. Furthermore, final rates would likely include at least two components – a capacity charge and a variable energy use charge. 5.4 Neighbourhood Heat Distribution System The heat distribution system has 4 distinct components:

1) Main Trunk Distribution Pipes; 2) Branch Connections;

12

In electrically heated buildings, DHW and make-up are typically met using natural gas. 13

Any additional costs associated with the in-building hot water distribution systems is not considered in this analysis.



3) Energy Transfer Stations (ETS) in each building / strata; and 4) Internal Heat Distribution Systems inside Buildings.

The neighbourhood heat distribution system is based on a low temperature design, similar to the design for the SEFC NEU. Heat will be supplied at 65°C for most of the year. However, when ambient temperatures fall below 0°C, the district heating supply temperature will be ramped up to a maximum of 95°C to increase ∆T and thereby increase supply capacity as necessary. In the Vancouver climate, there will be only a few days per year when the supply temperature reaches its maximum design level of 95°C. At the maximum supply temperature the district heating ∆T will be 40 °C. This design is used to maximize both efficiency and staffing flexibility. The distribution system flow is varied to maintain a desired pressure differential at the furthest point. The maximum flow will be 2.5 m/s. The type of pipe should be European Standard EN 253, with integral leak detection system. The maximum pipe size required is recommended to be 300 mm (12 inches) nominal diameter, which translates to 450 mm (16 inches) with insulation and jacket for both supply and return pipes. The pipe size would taper down according to the anticipated load on each section. Most of the branch connections would be at 80 mm. The distribution system will be situated along the edges of roads and in ditches as much as possible. Generally, we have assumed a depth of burial to the top of the pipes of 1,200 mm (maximum) cover for the steel pipes. This target depth is necessary to ensure sufficient cover during subsequent road construction. Based on the site layout and demand forecast, a preliminary layout of the distribution piping system was developed. An example of the proposed layout under the high demand scenario is provided in Figure 4. A detailed description of the heat distribution system layouts and scenarios is provided in the technical memoranda that accompany this report.



Figure 4: Proposed Layout of Heat Distribution System*

*Phasing is based on high growth scenario in this illustration.



Phasing plans and costs were estimated for the first two development phases in the high and low development scenarios. Phasing plans and costs also depend on the location of the central Energy Centre. Two possible sites for a central Energy Centre were considered - Lot 5 in the Northwest and Lot 44 to the East. Lot 5 was initially selected for the purposes of developing cost estimates by phase. However, after further discussion, revised cost estimates were produced based on an Energy Centre located in Lot 44.14 Due to the amount of land required for the biomass alternative, offsite locations should also be investigated if this alternative is selected for further study. Table 9 summarizes the estimated length and average diameter of distribution pipes in Phase 1 and Phase 2 under the high growth scenario.

Table 9: Estimated Length and Diameter of Distribution Pipes by Phase in High Growth Scenario

Scope

Phase 1 (0 – 5 years) 1,965 m 184 mm avg. diam.

Phase 2 (6 – 10 years) 1,460 m 107 mm avg. diam.

Total 3,425 m 151mm avg. diam.

FVB prepared a cost estimate for distribution piping by phase under the high and low demand scenarios (Table 10). The base case, which is based on a medium load forecast, uses the mid-point between the high and low scenarios. FVB’s cost estimate includes both main trunks and branch lines. The main trunks represent about 80% of the total capital costs in Table 10 and these costs would be incurred in two lumps. The exact timing of installation of the main trunk distribution pipes would be optimized during design concept development with the aim of delaying investment as long as possible while taking advantage of any possible economies from coordination with other infrastructure development. For the purposes of the business analysis, the cost of the main trunks is added in 2010 and 2015. Given lead times, installation is assumed to take place the preceding years and one year of interest during construction is added to the capital cost estimates for main trunks. The branch lines, which represent 20% of the capital costs, would be installed

14

FVB developed revised costs for the high demand scenario and revised costs for the low demand scenario were estimated based on the ratio between the revised and original cost estimates for the high demand scenario.



on a “just-in-time” basis (i.e., commissioning of buildings). The capital associated with branch lines is therefore added as load grows.

Table 10: Distribution Piping Capital Cost Estimates (thousands of $2007)*

Phase 1 Phase 2

Base Case 2,398 1,170

High Load Forecast 2,863 1,690

Low Load Forecast 1,934 649 * Includes main trunks and branch lines. The latter represent ~20% of total capital costs shown here.

The point of transfer or interface between the NEU and a building’s own internal heating system is called an Energy Transfer Station or ETS. The ETS typically consists of an assemblage of components that meter and control the heat energy passed between the NEU and the building. The ETS is typically located in each building. For the purposes of this analysis, it is assumed that there will be one ETS per Lot. There may be one or more buildings within a Lot, but it is assumed all buildings will be served through the one Lot ETS. This would be preferable if each Lot is a single strata. The scope and cost of ETSs by phase for the high and low load scenarios are summarized in Table 11 and Table 12. These mid-point of these costs was used in the base case analysis. These costs were spread across years to follow load growth. It is assumed that all necessary piping downstream of the ETS is “secondary” piping and is outside the scope of the NEU. As with branch lines, ETS capital would be installed on a “just-in-time” basis to allow buildings to be commissioned. The ETSs along with the main distribution pipes and branch lines would be owned and operated by the NEU. Therefore, access rights must be obtained for their installation and maintenance.

Table 11: ETS Capital Cost Estimates – High Load Scenario

Scope Cost ($)

Phase 1 13 ETS 1,044 KW/ETS

$2,042,000

Phase 2 19 ETS 760 KW/ETS

$2,571,000

Total 32 ETS 875 KW/ETS

$4,613,000



Table 12: ETS Capital Cost Estimates – Low Load Scenario

Scope Cost ($)

Phase 1 5 ETS 940 KW/ETS

$756,000

Phase 2 8 ETS 1,109 KW/ETS

$1,317,000

Total 12 ETS 875 KW/ETS

$2,073,000

The internal heat distribution systems inside buildings (Secondary Side) are the responsibility of building developers. They must be designed to provide the district heating system (Primary Side) with delta T of at least 40° C on peak winter days and 15 to 20° C in summer. The internal heat distribution system should be designed to provide the space heating and ventilation requirements for the individual suites, hallways/stairwells and other common areas in the building, supplied from the ETS for each site. The DHW system should be designed to provide all DHW requirements for the individual suites, and for all common areas in the building, supplied from the ETS for each site. The analysis assumed the DHW system is designed with storage tanks (by developer).15 Within individual suites, space heat may be provided via one of three general approaches at the discretion of the developer: 1) hydronic radiant (under-floor) floor heating; 2) fin type baseboard convectors / perimeter radiators, and 3) fan coils. The NEU would meter and charge for energy delivered to each ETS. Any sub-metering for individual suites would be the responsibility of building owners. Utility-grade sub-metering is costly relative to the total amount of heat consumed annually but would provide an accurate and reliable method for allocating building costs among individual suites. Sub-metering also provides more incentives for customers to manage their heat consumption. Utility-quality sub-meters currently cost about $1,000 per unit to install and $200 / year to read. This is based on ultrasonic meters with radio transmission. In some cases, smart thermostats that measure the time heating is turned on within suites could provide a reasonable tool for allocating NEU charges among strata owners at a fraction of the cost of utility-quality meters. The cost of sub-meters was not included in this analysis. The heat plant operators would operate and maintain the heat distribution system, including ETSs. The maintenance costs for the distribution system and ETSs would be approximately 1% of their capital cost per year. Communications systems would be installed at the same time as the pipe to allow plant operators to monitor all of the ETSs from the control room.

15

Elimination of the DHW storage tanks could result in overall savings but instantaneous provision of DHW by the NEU would increase initial system capacity requirements and costs. This issue should be explored further during the more detailed design phase.



For the purposes of the base case analysis, average heat losses in the neighbourhood distribution system are 4%, which is considered conservative. This is the additional amount of heat that must be produced by central heating plants to serve a given amount of load. 5.5 Heat Sources The business analysis assumes heat is produced at a single Energy Centre. For the purposes of this analysis, the Energy Centre is located at Lot 44. The analysis assumes a sufficient land area and building size is acquired at the outset to accommodate the total plant capacity required in 2020, when load is capped for the remainder of the analysis. The technical analysis initially considered four alternative heat sources:

1. Sewer heat 2. Geothermal

a. Ground-water with Heat Pump (GWHP) b. Ground-source with Heat Pump (GSHP)

3. Biomass (using wood residues or pellet fuels) 4. The Metro Vancouver Waste-to-Energy (WTE) plant located in

Burnaby In general, these alternate energy technologies provide energy at a lower annual fuel cost but have higher initial capital costs than conventional sources of heat such as natural gas boilers. Because of the higher capital costs, it is critical that the alternate energy capacity is utilized as much as possible through the year once installed. The optimal size and timing of the alternate energy capacity is dependent upon the total load and load profile. The winter peak heating demand in EFL under the high load scenario is ~20 MW by 2020. In comparison, the summer baseload demand is only 10% of the winter peak or ~2 MW. Based on this demand profile, the optimal size of the alternative energy capacity would be ~5 MW. The capacity of the alternative energy system allows a high rate of utilization, providing 70 – 80% of the annual energy requirements of the NEU, with the remaining energy requirements met by the natural gas boilers. About 21 MW of additional capacity would be required to meet peak demand and provide reserve capacity in the event of an outage of any single piece of heating capacity. Peaking and back-up capacity would be provided by natural gas boilers. It is recommended that the alternative energy capacity be installed when peak demand reaches approximately 10 MW in order to allow optimal sizing of this



capacity (a single 5 MW plant would be cheaper than multiple increments of smaller capacity equipment) an to ensure high utilization of the costly capacity immediately following installation. This would occur in years 3 – 6, depending upon the load scenario. It is recommended that a 1 MW condensing natural gas boiler be used to meet summer baseload in the early stages of the NEU. With the remaining capacity and load provided by conventional gas boilers. This also allows time to build actual load profiles to best fit the alternate energy capacity at the right time. This “start-up” strategy would reduce initial capital requirements and allows for the best fit of alternate energy capacity. The condensing and conventional gas boilers would revert to meeting peaking and back-up requirements once the alternate energy system is installed. Final decisions about the type and location of heat plants beyond Phase 2 may be deferred to allow revisions in response to changes in technology costs, fuel prices, and load growth. Following a preliminary economic screening of all of the plant alternatives, the business analysis was confined to two alternatives for alternate technologies: 1) waste heat from the Metro Vancouver Waste-to-Energy (WTE) plant located in Burnaby, and 2) biomass using wood residues (e.g., from City parks and local sawmills). These were shown to be the most promising alternatives in terms of both costs and environmental benefits. These two alternatives are described in more detail below. The preferred alternative of the City and Parklane / Wesgroup is the Metro Vancouver WTE plant because it would provide a much larger portion of total annual energy requirement with no net increase in GHG or local air emissions in the region. This alternative, however, is subject to negotiating a cost-effective rate for the heat from the plant. In the event this alternative does not prove viable during detailed design work and price negotiations with Metro Vancouver, the biomass alternative is the next preferred alternative. The biomass alternative would use locally available wastes and would provide substantial reductions in GHG emissions at a competitive price. Modern control technologies would produce local air emissions that are comparable to natural gas. 5.5.1 Metro Vancouver Waste-to-Energy Plant There is a unique opportunity to use heat generated at the existing Metro Vancouver WTE plant in Burnaby. Discussions with Metro Vancouver indicate an interest in the concept of supplying waste heat from the existing plant to a district heating system. Currently, the Metro Vancouver WTE plant produces electricity for sale to BC Hydro and also sells steam to a nearby paper plant at below the commodity price of natural gas. However, there is excess waste heat available from the plant.16

16

The sale of waste heat to a district energy system would increase overall energy uti€lization from the plant, but there could be some reduction in electricity production. The magnitude of



The concept would involve installing equipment at the Metro Vancouver WTE plant to extract up to 10 MW of heat capacity.17 Heat could be extracted from the steam turbine or from condensate returned by the nearby paper plant. A small building (~10mx10m) would be required at the Metro Vancouver WTE plant to house the necessary energy extraction equipment. The exchanger would transfer the energy to a separate hot water loop that would transfer hot water from the Metro Vancouver WTE plant to the EFL Energy Centre. A second exchanger at the Energy Centre would transfer the energy to the district heating network for distribution to customers. Extraction could take place at the existing district energy tap in the plant. A key challenge is identifying a route for the buried pipes (200 mm two pipe closed loop) connecting the Metro Vancouver WTE plant to the EFL Energy Centre. A possible route has been identified along North Fraser Way. The route is approximately 4.5 km long and would likely require some right-of-way easements. The piping is the largest cost of this alternative. The footprint of the EFL Energy Centre would be the quite small based on this heat source alternative. The economic viability of this alternative depends upon the price of the heat from the plant. For the purposes of this analysis, a maximum price of heat is calculated based on the other system costs (including the pipeline) and a target unlevered IRR for the NEU. 5.5.2 Biomass The biomass alternative involves using a locally available, renewable resource that is priced significantly less than other alternatives. Biomass based district heating plants are common in Scandinavia and have been implemented in some recent district heating projects in Canada, including Revelstoke, BC (2005), Oujebougamou, QC (1994), and Charlottetown, PEI (1986). A significant biomass system is operating in downtown St. Paul Minnesota (2001), and one is planned for downtown Seattle (2008). A biomass system based on wood gasification is planned for the Dockside development in Victoria.

electricity reduction (and hence the opportunity cost of the heat will depend upon where in the process heat is extracted. 17

FVB initially developed costs based on a 5 MW steam condenser and a 200 mm pipeline. However, in subsequent discussions, FVB suggested it may be possible to increase the capacity of this alternative to 10 MW by increasing the size of the steam condenser (for an incremental cost of $1 million) with no change in pipeline diameter if the target delta T can be achieved. A 10 MW capacity would allow an average of 95% of the annual load to be supplied by the Metro Vancouver WTE plant in 2020. Further analysis determined that the reduced use of natural gas in the NEU would more than offset the incremental cost of $1 million estimated by FVB for the 10 MW capacity alternative. This alternative was therefore used in the business analysis. This alternative would still require the same amount of natural gas boilers for back-up since back-up capacity must be sufficient to meet demand in the event the pipeline is our of service.



Resources that could be targeted as possible supplies include:

o Forestry residues o City of Vancouver park residues o Wood Pellets

The attractiveness of the fuel types is essentially based on delivered price, security of supply, and environmental performance. Based on the biomass capacity sizing and the heating values of the fuels, the following volumes will be necessary to supply 75% of annual energy demand in 2020:

o Residues = 15,000 – 16,000 green tonnes per year (50% MC, 10.9 MJ/kg)

o Pellets = 9,000 – 10,000 tonnes per year (std grade, 18.5 MJ/kg)

At peak winter conditions less than 4 trucks per week are required for residues and about 2 trucks per week for pellets, assuming 20 Tonne truck capacities. The biomass concept would see the fuel processed offsite to boiler “spec” grade and delivered in covered truck trailers. Either side-dump trailers or “shuffling” floor trailers would automatically dump the fuel into a “live” storage container. The live storage automatically feeds fuel to the boiler as needed. Sufficient storage capacity is provided to meet a three-day peak burn rate (winter long weekend). The live fuel storage would be attached to and of similar architecture as the main Energy Centre. The biomass system produces hot water from the fuel. Flue gas would exit via a flue stack. Emissions cleanup equipment would reduce stack emissions of particulate matter to required limits (assumed < 20 mg/nm3). Bottom ash and fly ash will be automatically collected into an ashbin. Ash is anticipated to be less than 3% by weight for residue fuel and fewer than 2% for pellet fuel – needs to be confirmed once fuel source is chosen. At peak burn rates about 2 Tonnes/week of residue ash and 800 kg/week of pellet ash will need to be hauled away. Technologies available for converting biomass fuel to energy are diverse. By far the most common, well-understood and least risk choice is direct combustion. All the biomass district heating projects noted above are based on combustion technology. Combustion technology has advanced significantly to optimize efficiency over wider operating ranges, while ensuring emissions are minimized. Grate designs and movements, variable speed motors, advanced monitoring, and better computer controls are improving performance. Coupled with advances in post combustion emission cleanup, emissions of particulate of less than 20 mg/nm3 can be achieved.



5.5.3 Heat Source Performance and Cost Assumptions Table 13 summarizes key assumptions for each heat plant. Land and building costs are incurred in Year 1 of operation. Equipment costs are incurred in increments based on load growth and the timing of the alternative energy capacity addition. The alternative energy capacity is installed when load reaches 10 MW (Year 6 in the base case, Year 5 in the high growth case and Year 10 in the low growth case). The price of heat from the Metro Vancouver WTE plant is subject to negotiation and not yet known. The model therefore calculates a viable cost of heat from the Metro Vancouver WTE plant to achieve a target unlevered IRR, given the other known costs associated with this scenario. Because the pipeline to the Metro Vancouver WTE plant represents a large portion of the capital for this alternative and the pipeline would have a much longer life span than other types of heating equipment, we include the residual (undepreciated) value of the pipeline (based on straightline depreciation) in the cashflows for calculating the IRR for this alternative in Year 25.18

Table 13: Heat Plant Performance and Cost Assumptions (High Growth Scenario Build-out Capacities and Costs)

Metro Vancouver

WTE Plant

Biomass

Plant

Energy Centre Land Requirements 1,400 m2

(0.34 acres)

4,000 m2

(0.98 acres)

Alt. System Capacity 10 MW 5 MW

Boiler Capacity 21 MW**** 21 MW

Alt. Fuel Efficiency 95% 70%

Average Gas Boiler Fuel Efficiency 85% 85%

Annual Energy Supplied by Alternative Energy Source*

90 - 95% 65-75%

Land Costs** $443 thousand $1.3 million

Building Costs*** $1.5 million $2.6 million

Equipment Costs*** $17.1 million $11.6 million

*Varies with annual loads. Furthermore, the Metro Vancouver Waste-to-Energy alternative can provide a much higher portion of annual demand because there is virtually no turn-down limit associated with this option. In the case of a biomass plant, the plant would have to be shut-down when the load is below a critical threshold relative to the capacity of the biomass system. **Based on land costs used in SEFC pro forma development analysis of $300 / m2. *** Total plant capital at build-out, excluding contingency and including interest during construction. **** The boiler capacity in the WTE alternative is the same, despite the higher alternative energy capacity. This is to provide full redundancy for the entire pipeline capacity in the event of an outage.

18

The useful life of the pipeline is assumed to be 40 years for the purposes of this analysis.



5.6 Staffing Based on information provided by FVB, two full-time employees were included in the base case assumptions at start-up – one full-time Director (assuming a stand-alone company) and one full-time operator.19 As the plant operates at fairly low temperatures, a chief engineer is not required. The number of operators required is largely a function of the capacity of the heat plant and provincial regulations. FVB expects a single full-time operator, supplemented with contractors to assist with periodic maintenance and holidays, could manage the plant while capacity is less than ~17 MW. Two operators would likely be required when a biomass plant is installed. Above 17 MW of total boiler capacity, continuous oversight may be required – i.e., four full-time staff – based on Code requirements. Inspectors with the B.C. Safety Authority would need to make the final determination regarding staffing requirements. There may also be synergies with the SEFC NEU. Specifically, it may be possible to share operators and/or back-up staff between the two heat plants. Unit cost estimates for staff include expected salary and overheads. A unit cost of $100,000 per year is assumed for the Director and $80,000 per year for operators. 5.7 Taxes, Insurance and Working Capital The pro forma model developed for this analysis can accommodate income taxes. However, the base case analysis was conduced on a pre-income tax basis. As an alternative to explicitly modelling income taxes, it is possible to simply compare the pre-tax return on investment calculated in the base case with an equivalent pre-tax return required by a taxable corporation based on average corporate tax rates. This provides a conservative estimate of the ability of the stand-alone entity to absorb income taxes (i.e., if the IRR is higher than required on a pre-tax basis). In reality, a private company may be able to reduce its exposure to income taxes through the use of accelerated depreciation allowances and possible tax sharing arrangements with other business units. These tax avoidance strategies would be specific to a particular owner and cannot be modelled in a general sense. PST is included in all capital cost estimates, where relevant. There is currently an issue with respect to PST on heating utilities in the Province where residential customers do not pay PST on their natural gas or electricity consumption. Initially, heat sales to residential customers were subject to PST. Based on efforts by the City of North Vancouver in relation to the Lonsdale Energy Corporation (LEC), the Province recently exempted heat sales to residential customers from PST in order to remove this bias.

19 For comparison, the Markham NEU has a President, a chief engineer, and two operators. However, they also operate a cooling system (with additional piping and ETS requirements) and the central plant has considerably more equipment, including a heat pump about 4 times the size of EFL, a similar sized boiler plant, and a 3.5 MW reciprocating engine and heat recovery equipment.



However, LEC still pays PST on gas purchased to produce heat. LEC is also seeking an exemption to remove an apparent bias against centralized heat production for residential customers. Given the recent changes in PST on heat sales and the limited use of natural gas in the proposed EFL NEU, PST on natural gas purchases and heat sales was not included in the base case analysis. In order to reflect a stand-alone entity, insurance and a working capital allowance were also included in the pro forma analysis. Working capital requirements were assumed to equal 2 months of revenues (17% of expected annual revenues). Working capital is added as load grows. Insurance equivalent to 0.33% of annual revenues was also included based on recommendations from City staff. Property taxes of $52.5 per thousand dollars of assessed value on the heat plant (land and equipment) were also included in the base case analysis. The City does not normally levy property taxes on its own utilities. Since the heat plants are most likely to be located on sites what would not normally generate property tax revenues (e.g., parkland or a school site) or would likely have lower commercial value than a heat plant, property taxes could be considered a benefit to the City and therefore excluded from the calculation of base case returns. However, a private entity could be required to pay property taxes.20 The effect of including these property taxes is considered in the sensitivity analyses. 5.8 Grants City Staff believe that the City would be able to secure some federal or provincial grant support for the innovative nature of the project. For instance, the City of North Vancouver received a $2 million grant (tied to a $2 million loan) from the Federation of Canadian Municipalities (FCM) to support the creation of Lonsdale Energy Corporation. Although it is being developed privately, the Dockside NEU also received a grant from Natural Resources Canada. The NEU Base Case assumes grants in the amount of $2 million.21 Low-cost financing opportunities were not considered in this analysis. Because returns are calculated on an unlevered basis (i.e., before financing effects), the analysis is not sensitive to financing assumptions. However, the availability of low-cost financing could be taken into account by altering the threshold return requirements for decision making.

20

For comparison, the City of North Vancouver has exempted the heat plants supplying LEC and owned by Terasen Gas Inc. from property taxes for at least the next 15 years. 21

Government support could also take the form of a low-interest loan, which would lower the benchmark return required by the NEU.



5.9 Emissions GHG emissions were estimated for the purposes of the initial business analysis. GHG emissions are a key environmental issue and represent a reasonable proxy for many other environmental impacts. GHG emissions were calculated for the BAU heating scenario and for the NEU scenario. Table 14 summarizes CO2-equivalent emission factor assumptions for different heat sources. These factors are for delivered heat and reflect the efficiency of different heat sources. The electricity emission factors are based on current targets for maximum emissions from new electricity generation (based on an incremental portfolio of 50% green and 50% thermal sources). The Provincial Government has recently announced targets for a greater proportion of green energy and lower GHG emissions but these have yet to be supported by actual legislation. In addition, it is likely that such policies will also affect electricity prices.

Table 14: GHG Emission Factors

Heat Source Factor

Electricity 205 tonnes / GW.h*

On-Site Natural Gas Boilers 257 kg / MW.h

Centralized Natural Gas Boilers 225 kg / MW.h

Biomass (Hog fuel) 0 kg / MW.h

Metro Vancouver WTE Plant 0 kg / MW.h

*Marginal emission factor assuming 50% clean electricity sources and 50% new natural gas combined cycle turbines. Also reflects average transmission and distribution losses on the province.

6.0 Financial and Environmental Analysis

6.1 Base Case Outputs Table 15 summarizes the Base Case results. The Base Case is based on the moderate load growth scenario and assumes the Metro Vancouver WTE heat alternative (10 MW supply). Peak heat demand reaches 15 MW by 2020 and annual energy sales reach ~38,000 MW.h. The base case assumes no premium over BAU gas and electricity heating costs and an initial grant of $2 million. Because the cost of heat for this option is not known, we have instead computed a maximum cost of heat based on the other capital costs associated with this option and a target real unlevered IRR of ~5.3% (comparable to the weighted average cost of capital of a low-risk utility, as



discussed further below). Under these assumptions, and excluding any contingency for capital costs, the real cost of heat from the Metro Vancouver WTE plant would have to be no more than $13.75 / MW.h.22 Under these assumptions, the optimal timing of the addition of the pipeline (which has a high capital cost) is approximately Year 5 of operation. A lower heat price from Metro Vancouver would be required to compensate for advancing the large amount capital associated with this alternative. GHG emission reductions relative to BAU would be about 8,500 tonnes / year by 2020 under this alternative. Table 16 summarizes the comparable results based on heat supplied by a biomass plant. Demand assumptions are the same. Total capital expenditures are slightly lower than the Metro Vancouver WTE option, which has high capital costs associated with the pipeline to the Metro Vancouver plant. The analysis summarized in Table 15 assumes the biomass heat source is added in Year 6 when load reaches approximately 10 MW. The 25-year unlevered real IRR under the Base Case assumptions is 5.5%. GHG reductions relative to the BAU heating scenario are ~6,300 tonnes / year by 2020. 23 Total capital expenditures (as spent, real $2007) are approximately $21 million by 2020. Under these assumptions, this alternative has a real unlevered IRR of ~3.9%.

22

This is a real (before inflation) levelized cost of heat over 25 years. For comparison, a real cost of heat of $21 / MW.h produces a real unelevered IRR of ~4%, which is roughly equivalent to the City’s real cost of debt. 23

The Metro Vancouver alternative supplies a higher amount of capacity (10 MW versus 5 MW) and would also have a higher turn-down ratio than a biomass option. That is, it could supply periods of extremely low demand (e.g., summer), further eliminating reliance on natural gas during low demand periods.



Table 15: Summary Results for Base Case - Metro Vancouver WTE Plant*

East Fraser Lands Neighbourhood Energy Utility Project Summary

2010 2015 2020 2025 2030 2035All dollar values in thousands of $2007

Annual Heat Sales (MW.h) 3,459 21,434 37,999 37,999 37,999 37,999

Diversified Heat Demand (MW) 1.4 8.4 15.0 15.0 15.0 15.0

Installed Heat Plant Capacity (MW) 7.4 22.8 22.8 22.8 22.8 22.8

Annual Capital Expenditures 8,877 12,775 - - - -

Cumulative Capital Expenditures 8,877 23,753 25,432 25,432 25,432 25,432

Revenues 252 1,634 3,033 3,180 3,334 3,496

$ / MW.h 73 76 80 84 88 92

Operating Costs 440 738 1,121 1,123 1,124 1,125 $ / MW.h 122 33 28 28 28 28

Unlevered Pre-Tax Cash Flow (7,108) (11,934) 1,907 2,052 2,205 2,366

IRR 5.31%

GHG Reductions (tonnes per year) (4) 4,992 8,472 8,472 8,472 8,472 * Heat from Metro Vancouver WTE plant set at $13.75 / MW.h. For the purposes of this analysis, the timing for implementation of the Metro Vancouver WTE alternative is Year 5.

Table 16: Summary Results for Base Case– Biomass Plant








Revenues 252 1,634 3,033 3,180 3,334 3,496

$ / MW.h 73 76 80 84 88 92

Operating Costs 537 1,308 1,506 1,511 1,516 1,521 $ / MW.h 149 59 38 38 38 38


IRR 3.85%

GHG Reductions (tonnes per year) (4) (24) 6,322 6,322 6,322 6,322



6.2 IRR Comparables The unlevered IRR produced in the pro forma analysis can be compared to two different benchmarks. The first benchmark is the City’s long-term cost of borrowing. This represents the minimum IRR required to cover debt service costs under 100% debt-financing, assuming no premium for risk or a debt guarantee. The City Finance Department suggested using 6% as a reasonable benchmark for the City’s long-term cost of debt.24 The second benchmark is the weighted average cost of capital (WACC) for a comparable private utility. The BC Utilities Commission regulates public energy utilities in B.C. Examples include electric utilities such as BC Hydro and FortisBC (municipal electric utilities are currently exempt from BCUC regulation) and gas distribution utilities such as Terasen Gas Inc. (TGI), Terasen Gas Vancouver Island (TGVI), and Terasen Gas Whistler (TGW). The Commission sets rates for these utilities based on approved operating expenses, capital expenditures, and financing costs. Financing costs are based on an approved capital structure, weighted short-term and long-term interest rates, and an approved Return on Common Equity (ROE). For the purposes of this comparison, we have used the capital structure and allowed ROE of TGVI. TGVI’s nominal incremental pre-tax WACC is currently 7.3%. This is based on a 60% debt / 40% equity capital structure with the average debt cost at 5.8% (pre-tax) and allowed return on equity at 9.5%. We use the pre-tax because income taxes are not considered in the analysis. Because the pro forma analysis and returns are in real dollars, these benchmarks must be converted to real values for comparison purposes. The resulting benchmarks are summarized in Table 17. Based on these benchmarks, the Base Case return for the NEU is favourable.

Table 17: Benchmarks for Evaluation of NEU Returns

Comparable Private Utility (Pre-tax)*

City’s Cost of Debt

Nominal 7.3% 6%

Real 5.3% 4%

* Based on Terasen Gas Vancouver Island. This assumes a 60/40 debt to equity ratio, an allowed ROE of 9.5%, and average cost of debt of 5.8%. The equivalent WACC for Central Heat is currently approximately 7.1% (nominal).

24

This is a conservative estimate. For example, the current average cost of debt for Terasen Gas Vancouver Island is 5.8% based on a triple B credit rating.



6.3 GHG Reductions The estimate of GHG reductions requires an assumption about expected emissions under Business as Usual (BAU). BAU GHG emissions are a function of assumptions about fuel splits (i.e., the penetration of gas vs. electric heat) and the emission factor for electricity. The emission reductions shown in Table 15 and Table 16 assume a 100% share of natural gas heat in the commercial sector and a 70% electric share in residential space heating (100% natural gas share for DHW). Table 15 and Table 16 use a marginal emission factor for electricity.25 The marginal emission factor for electricity is based on the provincial government’s current voluntary commitment for 50% of new electricity supplies to come from clean sources. The remaining 50% is assumed to be supplied from combined cycle gas turbines. This produces a marginal emission factor from electricity of 205 kg / GW.h. The provincial government recently released an updated Energy Plan that suggests 100% of new supplies will eventually come from clean sources, but this has not yet been backed by any legislation. If implemented, this would suggest a marginal emission factor for electricity of zero.26 BC Hydro’s average (existing) direct and indirect emissions for the past four years were approximately 130 kg/GW.h. Using different assumptions for the penetration of electric heat and for the emission factor of electricity, absolute GHG reductions range from 4,800 t/year to 9,400 t/year in 2020 under the modest growth scenario and WTE plant alternative (Table 18). The average Canadian directly produces about 5 tonnes of GHG emissions per year so 8,472 tonnes is equivalent to the personal emissions of ~1,700 people.

25

Economic cost benefit analysis is based on the use of marginal costs and benefits. B.C.’s existing electricity capacity is currently fully committed and new construction will necessitate the addition of new supplies. 26

It should be noted that this commitment will likey have impacts on the costs of electricity, which are not reflected in the price forecast used in this report. In addition, the provincial government has also made significant commitments to energy efficiency in general and to electricity efficiency in particular. It is unclear whether the use of electricity, clean or otherwise, is consistent with the provincial government’s policies and targets with respect to electricity efficiency, given electricity is a very high quality source of energy and heat is a very low-quality demand.



Table 18: GHG Emission Reduction Scenarios*

Electric Emission Factor

(kg/GW.h)

NEU Emission Reductions (tonnes / yr)

70/30 Electricity / Gas BAU

Marginal electricity emission factor (50/50 Green / CCGT) 205 8,472

Marginal electricity emission factor (100% Green) 0 4,822

Average (existing) electricity emission factor 130 7,136

100% Natural Gas BAU N/A 9,400

*Reductions in 2020 under moderate demand scenario and heat supplied from Metro Vancouver WTE plant.

6.4 Sensitivity and Scenario Analysis Sensitivity and scenario analyses on the base case were conducted for key input assumptions in order to quantify some of the potential risks faced by the utility. Some of the variables considered in the sensitivity and scenario analyses include the following. - Load Growth. The base case used a mid-point for load growth between

the high and low growth scenarios. Sensitivity analyses were conducted using the high and low growth scenarios. The optimal timing of the implementation of the alternative capacity would differ in these scenarios. For example, in the high growth scenario, the biomass capacity could be implemented in Year 5 (rather than Year 6). In the low growth scenario, the biomass capacity would need to be deferred until about Year 10. In addition to the estimated load by 2020, the analysis is very sensitive to the rate of load growth within the first 10 years. If more of the load in a demand scenario is installed in the early years, it has a dramatic effect on project performance.

- Capital Costs. As noted in the summary of input assumptions, no

contingencies were included in individual capital expenditure. An overall sensitivity analysis was conducted that assumed a 10% contingency in all capital expenditures for the project.

- Grants. A $2 million grant was included in the base case analysis for

Phase 1. A sensitivity analysis was conducted without this grant. - Premium over Gas and Electricity Costs. The base case assumes no

premium over BAU gas and electric heating costs in estimating NEU revenues. A sensitivity analysis was conducted with a 10% premium over BAU gas or electric heating costs.

- Property Taxes. Property taxes were included in the base case analysis

but in reality these also represent an incremental benefit to the City assuming the heating plant is located on land that would not normally



generate property taxes (e.g., City parkland). In addition, the considerable capital investment for a heating plant could generate more value than a typical commercial building alone. Property taxes represent a considerable portion of operating expenditures of the NEU – more than a third of annual operating costs at start-up and ~15% of annual operating costs by 2015.

- LEED Gold Energy Centre. The City of Vancouver is considering

implementing the LEED Gold Standard for all City-owned buildings. LEED standards are more costly to meet in unoccupied buildings, such as the NEU Energy Centre. FVB estimates this could add up to 25% to the cost of the Energy Centre Building. A sensitivity analysis was conducted using this higher building cost.

Table 19 and Table 20 summarize the detailed results for the high and low load growth scenarios based on the Metro Vancouver WTE plant. In both cases, we leave the cost of heat from Metro Vancouver constant at $13.75/MW.h. Table 21 summarizes the returns under all of the different sensitivity analyses, again with the cost of heat from Metro Vancouver constant at $13.75/MW.h. Table 22 summarizes the maximum cost of heat from Metro Vancouver that would provide an unlevered IRR of 5.3% under the various scenarios.

Table 19: Summary Results - High Load Growth, Metro Vancouver WTE Plant








Revenues 366 2,306 4,055 4,252 4,459 4,676

$ / MW.h 73 76 80 84 88 92

Operating Costs 510 935 1,473 1,475 1,477 1,480 $ / MW.h 98 30 28 28 28 28


IRR 7.33%

GHG Reductions (tonnes per year) (6) 6,933 10,815 10,815 10,815 10,815



Table 20: Summary Results Under Low Load Growth, Metro Vancouver WTE Plant

Table 21: Sensitivity Results on Unlevered IRR with Metro Vancouver WTE Plant (Fixed Heat Cost)*

Moderate Load Growth

High Load Growth

Low Load Growth

Base Case Assumptions 5.3% 7.3% 2.4%

10% Contingency Added to All Capital Costs 4.7% 6.5% 1.9%

No Property Taxes 6.0% 8.0% 3.2%

LEED Gold Energy Centre 5.2% 7.2% 2.3%

10% Premium Over Gas and Electricity Heat 6.7% 8.9% 3.6%

No Grant 4.5% 6.5% 1.7%

More Load Added in Early Years of Load Growth Scenario**

6.2% 8.3% 3.2%

Metro Vancouver WTE Pricing

$10/MW.h 5.9% 8.0% 3.0%

$15/MW.h 5.1% 7.1% 2.3%

$20/MW.h 4.2% 6.2% 1.5%

$25/MW.h 3.3% 5.2% 0.7%

*Heat price from the Metro Vancouver plant is fixed at $13.75/MW.h, the same level as in the base case.








Revenues 138 963 2,011 2,108 2,210 2,317

$ / MW.h 73 76 80 84 88 92

Operating Costs 370 551 804 804 805 805 $ / MW.h 188 42 31 31 31 31


IRR 2.44%

GHG Reductions (tonnes per year) (1) 2,940 5,862 5,862 5,862 5,862



**Optimal timing of pipeline decreases to first 2-3 years if load addition is condensed to first 6 years of development.

Table 22: Sensitivity Results on Cost of Heat from Metro Vancouver WTE Plant with a Fixed Unlevered IRR*


High Load Growth

Low Load Growth

Base Case Assumptions $13.8 $24.5 N/A**

10% Contingency Added to All Capital Costs $10.0 $20 N/A**

No Property Taxes $18.0 $27.5 N/A**

10% Premium Over Gas and Electricity Heat $22.0 $33.5 $0

No Grant $8.5 $20.5 N/A**

*Heat price from the plant is varied to achieve target rate of return of 5.3%. **Price of zero still does not achieve the target return of 5.3%

Table 23: Sensitivity Results on Unlevered IRR with Biomass Plant


High Load Growth

Low Load Growth

Base Case Assumptions 3.9% 5.7% N/A

10% Contingency Added to All Capital Costs 3.0% 4.7% N/A

No Property Taxes 5.4% 6.9% 1.7%

LEED Gold Energy Centre 3.6% 5.5% N/A

10% Premium Over Gas and Electricity Heat 5.5% 7.4% 1.3%

No Grant 3.0% 4.8% N/A

More Load Added in Early Years of Load Growth Scenario**

5.0% 6.8% 0.4%

The sensitivity analyses demonstrate that the project is highly sensitive to load assumptions. Low load growth could make the project uneconomic. Returns are generally favourable for all sensitivity assumptions under the moderate and high load scenarios, as well as more early development of loads within each of these scenarios. As expected, viability is highly sensitive to capital cost assumptions. These estimates will need to be refined in the next phase of detailed design work. However, the analysis also shows that the addition of a small premium will improve viability in the event of higher capital costs. Viability is also very sensitive to property tax assumptions. If the plant is located on land that would not have generated property taxes for the City, these taxes represent an incremental benefit to the City and could be considered as a benefit rather than a cost in the analysis. A major issue to be resolved is the cost of heat from the preferred heat source – the Metro Vancouver WTE plant. The maximum viable cost of heat from the Metro Vancouver WTE plant varies depending upon the scenario, but generally falls



between $10 and $25 / MW.h which is within the range of the estimated opportunity cost of heat for from the plant based on very preliminary discussions with Metro Vancouver. This alternative warrants further analysis by the City, Developer and Metro Vancouver. 6.5 Other Risk Considerations Buildings that connect to the utility’s distribution system present an operational efficiency risk to the utility. Each building’s hydronic system must be properly designed to efficiently handle the utility’s supply and return temperature specifications. To achieve this, the NEU will need to work closely with the developers’ design teams to ensure proper design and equipment specification of in-building hydronic systems.



Appendix 1 – Base Case Cashflow Summary

Unlevered Cashflow Summary 2010 2011 2012 2013 2014 2015

Year ending December 31st, (,000 $2007)

Revenue

Energy Sales 252$ 509$ 770$ 1,036$ 1,307$ 1,634$ GHG Offsets -$ -$ -$ -$ -$ -$

Total Revenue 252$ 509$ 770$ 1,036$ 1,307$ 1,634$

Capital Expenditures

Land 443$ -$ -$ -$ -$ -$

Building 1,520$ -$ -$ -$ -$ -$

Plant Costs (excl. building and land) 4,522$ 154$ 154$ 154$ 154$ 11,369$

Distribution System 2,022$ -$ -$ -$ -$ 986$

ETS and Branch Lines 371$ 371$ 371$ 371$ 371$ 420$

Sub-meters -$ -$ -$ -$ -$ -$ Salvage value of pipeline (GVRD WTE)

Total Capital Expenditures 8,877$ 525$ 525$ 525$ 525$ 12,775$

Annual Operating Expenditures

Distribution System and ETS 24$ 28$ 31$ 35$ 39$ 53$

Heating Plants - Fuel 131$ 264$ 395$ 526$ 657$ 323$

Heating Plants - Non-fuel 11$ 22$ 32$ 43$ 54$ 84$

Management and Staff 170$ 170$ 170$ 170$ 170$ 170$

GHG Offsets -$ -$ -$ -$ -$ -$

Insurance 1$ 2$ 3$ 3$ 4$ 5$

Sub-meter Reading -$ -$ -$ -$ -$ -$

Property Taxes 103$ 103$ 103$ 103$ 103$ 103$ Other Taxes and Credits -$ -$ -$ -$ -$ -$

Total Annual Operating Expenditures 440$ 588$ 734$ 881$ 1,027$ 738$

Working CapitalWorking Capital Additions 43$ 44$ 44$ 45$ 46$ 56$

GrantsGrants 2,000$ -$ -$ -$ -$ -$

Cashflows

Net Unlevered Pre-tax Cashflows (7,108)$ (648)$ (534)$ (415)$ (291)$ (11,934)$

Cumulative Real Unlevered IRR #NUM! #NUM! #NUM! #NUM! #NUM! #NUM!



Unlevered Cashflow Summary 2016 2017 2018 2019 2020


Revenue

Energy Sales 1,967$ 2,307$ 2,653$ 3,005$ 3,033$ GHG Offsets -$ -$ -$ -$ -$

Total Revenue 1,967$ 2,307$ 2,653$ 3,005$ 3,033$


Land -$ -$ -$ -$ -$

Building -$ -$ -$ -$ -$

Plant Costs (excl. building and land) -$ -$ -$ -$ -$

Distribution System -$ -$ -$ -$ -$

ETS and Branch Lines 420$ 420$ 420$ 420$ -$

Sub-meters -$ -$ -$ -$ -$ Salvage value of pipeline (GVRD WTE)

Total Capital Expenditures 420$ 420$ 420$ 420$ -$


Distribution System and ETS 57$ 61$ 65$ 70$ 70$

Heating Plants - Fuel 385$ 460$ 538$ 620$ 620$

Heating Plants - Non-fuel 100$ 116$ 132$ 149$ 149$

Management and Staff 170$ 170$ 170$ 170$ 170$

GHG Offsets -$ -$ -$ -$ -$

Insurance 6$ 8$ 9$ 10$ 10$

Sub-meter Reading -$ -$ -$ -$ -$

Property Taxes 103$ 103$ 103$ 103$ 103$ Other Taxes and Credits -$ -$ -$ -$ -$

Total Annual Operating Expenditures 822$ 918$ 1,018$ 1,121$ 1,121$

Working CapitalWorking Capital Additions 57$ 58$ 59$ 60$ 5$

GrantsGrants -$ -$ -$ -$ -$

Cashflows

Net Unlevered Pre-tax Cashflows 669$ 911$ 1,156$ 1,404$ 1,907$

Cumulative Real Unlevered IRR #NUM! #NUM! #NUM! #DIV/0! #DIV/0!





Revenue


Total Revenue 3,062$ 3,091$ 3,120$ 3,150$ 3,180$


Land -$ -$ -$ -$ -$

Building -$ -$ -$ -$ -$



ETS and Branch Lines -$ -$ -$ -$ -$


Total Capital Expenditures -$ -$ -$ -$ -$






GHG Offsets -$ -$ -$ -$ -$

Insurance 10$ 10$ 10$ 10$ 10$



Total Annual Operating Expenditures 1,122$ 1,122$ 1,122$ 1,122$ 1,123$



Cashflows

Net Unlevered Pre-tax Cashflows 1,935$ 1,964$ 1,993$ 2,023$ 2,052$

Cumulative Real Unlevered IRR #DIV/0! #DIV/0! #DIV/0! #NUM! -3.2%





Revenue


Total Revenue 3,210$ 3,241$ 3,272$ 3,303$ 3,334$


Land -$ -$ -$ -$ -$

Building -$ -$ -$ -$ -$





Total Capital Expenditures -$ -$ -$ -$ -$






GHG Offsets -$ -$ -$ -$ -$

Insurance 11$ 11$ 11$ 11$ 11$






Cashflows


Cumulative Real Unlevered IRR -1.6% -0.4% 0.7% 1.5% 2.3%





Revenue


Total Revenue 3,366$ 3,398$ 3,431$ 3,463$ 3,496$


Land -$ -$ -$ -$ -$

Building -$ -$ -$ -$ -$




Sub-meters -$ -$ -$ -$ -$ Salvage value of pipeline (GVRD WTE) (4,450)$

Total Capital Expenditures -$ -$ -$ (4,450)$ -$






GHG Offsets -$ -$ -$ -$ -$

Insurance 11$ 11$ 11$ 11$ 12$






Cashflows


Cumulative Real Unlevered IRR 2.9% 3.5% 3.9% 5.0% 5.3%

Suite 200, 1260 Hamilton St. Vancouver, British Columbia Canada V6B 2S8

August 11, 2009 Brent Tedford Development Manager WesGroup Properties LP Suite 1774, Four Bentall Centre 1055 Dunsmuir Street, PO Box 49378 Vancouver, BC V7X 1L5 Dear Brent: RE: NEU Update for EFL Phase 2 Rezoning As requested, Compass and FVB are pleased to provide an updated NEU analysis to support your Phase 2 Rezoning application and planning process. We have updated fuel prices, development phasing assumptions, and energy centre locations. The following summary provides the incremental impacts of each of these updates. In order to meet your immediate needs, we have not updated unit costs of distribution piping, energy transfer stations, or energy centre capital. We have simply updated the fuel prices (which affect revenue assumptions and NEU fuel costs), distribution system capacity and phasing (based on alternate development phasing and energy centre locations), and energy centre capacity and phasing (including optimal timing of alternate energy capacity). We have kept all costs in $2007 for simplicity and comparison with the original analysis.

1) Methodology The updated follows the same basic methodology as the original business analysis with updated fuel prices, load phasing and capital phasing assumptions. Key features of the approach:

To simplify the original pro forma analysis, loads (and system capital) were capped after 2020. Given the large initial capital outlays, district energy systems are typically very sensitive to load assumptions for the first 10 years. Beyond 10 years, financial returns typically remain stable or increase with further load growth. For the purposes of the update, we have capped loads at the end of Phase 2 and simply altered the timing of phases. This was required because we had several load scenarios in the original analysis and only one for the update.

NEU revenues reflect avoided customer costs under business as usual (BAU). A 10% premium over BAU costs was included as a sensitivity analysis. The premium is justified based on other intangible benefits from the NEU including more price stability, higher reliability, better service quality, and environmental benefits, among others.

Returns are calculated on a real cash flow basis. That is, cumulative returns are estimated from forecasts of annual revenues, operating costs and capital expenditures in real dollars, as

EFL NEU Business Analysis Update, August 2009 Page 2

incurred. An internal rate of return (IRR) is calculated for each year based on cumulative cash flows up to that year. The 25-year IRR is used to test business viability.

The analysis focuses on the unlevered IRR (i.e., the IRR on total cash flows, ignoring the effects of financing). The unlevered IRR may be compared to a target or benchmark return. Two benchmarks are considered for comparison purposes – the City’s cost of debt (assuming 100% debt financing) and the weighted average cost of capital for a comparable small energy utility.

Two energy supply scenarios were considered: a biomass heating plant and recovery of waste heat from the Metro Vancouver Waste-to-Energy (WTE) Plant. The recovery of waste heat from the Metro WTE Plant would require a pipeline approximately 4.5 km in length to the site. However, a larger portion of the annual load would be captured by the WTE plant, as discussed in the original analysis.

Except for the pipeline to the Metro Vancouver WTE plant, which is discussed further in the assumptions below, the cash flow analysis assumes no terminal value for utility assets at year 25. This is somewhat conservative since some assets will not have been fully depreciated and would have some residual value if the business remains an ongoing concern at that time.

GST was excluded from the analysis based on the assumption that the effect of any GST collection and remittance by the NEU would be neutral on an annual basis. PST and property taxes are considered in the analysis as discussed below.

All capital cost estimates provided by FVB included a contingency. Contingencies are excluded from base cash flow analysis and included in the sensitivity and scenario analysis. The base case analysis includes a year of interest during construction for all large capital outlays.

For simplicity, the updated analysis assumes the same starting year of 2010. Given the analysis is in real dollars and the focus is a 25-year unelevered return, a later starting year will not have a significant impact on the investment analysis. In fact, the rapid rise in electricity prices in the early years would suggest that deferral could have a small positive impact on investment returns.

The table below summarizes the original outputs under base case assumptions for a biomass heating plant and the Burnaby Waste-to-Energy interconnection.


Supply Scenarios* Real Unlevered 25-year IRR

GHG Emission Reductions @ Build Out

Biomass Energy Plant 3.9% 6,300 tonnes / year

Burnaby WTE Plant 5.3% 8,500 tonnes / year

Original Return Benchmarks

WACC for a Comparable Private Utility 5.3%

100% Debt Financing by City 4%

*Alternative energy capacity is installed when load reaches approximately 10 MW (Year 6). Because of higher dispatchability, the WTE supply scenario assumes 95% of annual energy is met from the WTE plant compared to only 75% from biomass plant. The cost of the WTE includes the cost of the pipeline (less a terminal value), the capital cost of additional heat recovery equipment at the WTE plant, and the value of reduced electricity sales as a result of heat recovery.

2) Updated Fuel Prices There have been some important changes in fuel price assumptions since the original business analysis. In addition to some minor changes in the natural gas price forecast, there have been some significant developments in electricity pricing. First, BC Hydro has implemented a stepped residential rate. Under the stepped rate, consumption in excess of 675 kW.h per month will be priced at a much higher Tier 2 rate, which reflects BC Hydro’s marginal cost of new supply. Based on a recent study of energy usage in high-rise residential buildings in the Lower Mainland, we estimate approximately 20% of electricity consumed for space heating will incur the higher Stepped 2 rate. Second, BC Hydro has increased rates in excess of 10% in the past 2 years and has filed its first long-term retail rate forecast which projects further increases of nearly 50% in real terms within the next 10 years. BC Hydro’s long-term rate forecast is similar to the one we prepared in the original analysis except it suggests rates rising more quickly and then levelling off, which has a greater effect on near-term revenues. The table below illustrates the key differences in fuel price forecasts between the original and updated analysis, using the residential rates as a basis for the comparison. Fuel Prices ($2007 / MW.h) 2010 2015 2020 2025 2030 2035

Original

Residential natural gas 32.11 32.09 32.14 32.35 32.56 32.78

Residential electricity 71.91 75.58 79.44 83.49 87.75 92.23

Updated

Residential natural gas 33.91 39.70 40.32 40.69 41.00 41.32

Residential electricity 65.64 88.76 92.34 92.34 92.34 92.34


To help understand the effect of updated fuel prices relative to the effect of updated phasing assumptions, we ran the original analysis using only the new fuel price assumptions.

Real 25-Year Unlevered Returns (Average Demand Scenario) WTE Plant Biomass Plant

Original Fuel Prices 5.3% 3.9%

Updated Fuel Prices 6.7% 5.5%

3) Updated Load Phasing The updated phasing assumptions are shown below. The parcels included in each phase can be seen in the alternate DPS layouts included in Attachments A and B. For the purposes of the pro forma analysis, only Phase 1 and Phase 2 loads / capital are included. The updated phasing assumptions are shown below. The cumulative total of Phases 1 and 2 have not changed but because the order in which parcels are expected to be developed has changed there is a smaller amount of development in the new Phase 1 and a larger amount in new Phase 2. In addition, there is a slightly longer timeframe assumed for each phase (again assuming a 2010 start for simplicity).

Updated Phasing Assumptions

Original Updated

# of Buildings Load (kW) # of Buildings Load (kW)

Phase 1 12 10,868 15 7,215

Phase 2 17 11,527 22 15,346

Phase 3 19 8,666 17 9,192

Phase 4 1 792 1 792

Phase 5 1 692 N/A N/A

4) Alternate Energy Centre Locations The original analysis screened two potential sites for the Energy Centre –Parcel 44 and alternate location near Kinross St. and Kent Ave. Given the phasing scenario, the desire to interconnect with the Metro WTE Plant and other siting considerations provided by Parklane, Parcel 44 was selected for the business analysis. For the purposes of this update, WesGroup requested that an alternate site near Kinross St. and Kent Ave. be considered. This general location is actually a more favourable site in terms of the Distribution Piping System (DPS) capital, particularly if development commences with the western


portions of the site, as suggested by the updated phasing diagram. However, there would be some increase in the cost to interconnect with the Metro WTE Plant, relative to the Parcel 44 location. There are two ways to interconnect a an alternate site near Kinross St. and Kent Ave. with the Metro WTE Plant. One assumes the original pipeline is extended all the way to the alternate site. This would add an additional 1 km to the original 4.5 km pipeline, an increase of approximately $1.7 million relative to the original pipeline budget of $7.8 million. A second option is to add diameter to the mainline going towards Parcel 44 such that the Metro WTE source feeds directly to the distribution system and there are then two different sources feeding customers. This would also require additional pumps and control systems but we estimate the incremental cost would be only 25% of the pipeline extension or $430k. An interim solution is to site a temporary Energy Centre near Kinross St. and Kent Ave and then to move the plant to Parcel 44 when the system is extended east and the WTE Plant is interconnected. However, as we illustrate below, this does not provide any significant savings in DPS capital and there would be costs associated with a temporary plant that could not be salvaged upon relocation to Parcel 44. Siting of the Energy Centre is discussed further below in conjunction with the updated DPS phasing analysis.

5) Updated DPS Phasing We prepared an updated DPS layout and phasing assumptions based on the new development phasing. The tables below show the original and updated phasing assumptions. Only the Phase 1 and 2 DPS and Energy Transfer Station (ETS) costs are estimated as load was capped after Phase 2 for the purposes of the pro forma analysis. Although Energy Transfer Stations are located on customer premises, these systems and costs are borne by the NEU. As illustrated below, the peak loads have been reduced in Phase 1 and increased in Phase 2 as a result of the new development phasing. The total DPS costs (mainlines and branch connections) would be approximately $300k higher if the Energy Centre is retained on Parcel 44. But most of the costs would still be incurred in Phase 1, despite lower loads in this phase. Total costs would be reduced nearly $800k by siting the Energy Centre at an alternate site near Kinross St. and Kent Ave, and more of the costs could be deferred to Phase 2 as load increases. Using a temporary plant near Kinross St. and Kent Ave would help to defer costs to Phase 2 but total DPS costs would still be higher at the end of Phase 2. Furthermore, there would be some additional costs associated with the temporary Energy Centre which could not be salvaged in the re-location. The original and updated DPS phasing assumptions are contained in Attachments A and B.


6) Pro Forma Update We prepared an updated pro forma analysis based on the updated fuel price forecasts, development phasing assumptions, and DPS phasing assumptions. In order to facilitate comparison, we ran the original and updated analyses capping loads at the end of Phase 2 rather than 10 years. This was necessary because there were several alternate load phasing scenarios used in the original analysis and we could not replicate these in the updated analysis based on one development scenario. In addition to the updated DPS and ETS phasing, we have also included an additional $450k for the Metro WTE interconnection to an alternate Energy Centre site near Kinross St. and Kent Ave. These additional costs are for additional pumps and control systems required to integrate the Metro waste heat directly into the DPS system with the back-up and peaking boilers are located at an alternate site. We have not altered our unit cost assumptions or the price of Metro’s waste heat from the original analysis. The original and updated pro forma outputs are summarized below (based on capping loads and costs at the end of Phase 2 in each case). As shown, the alternate phasing has a modest impact on the pro forma if the Energy Centre is located near Kinross St. and Kent Ave, and the Metro WTE Plant is interconnected directly to the DPS rather than an alternate Energy Centre located near Kinross St. and Kent Ave. There is a more significant impact if the permanent Energy Centre is constructed at Parcel 44 under the new phasing assumptions. A temporary plant near Kinross St.


and Kent Ave could defer some DPS capital, but there would also be some additional unrecoverable costs associated with the temporary Energy Centre, which we have not assessed in this update. The results for a temporary plant would likely be somewhere between those for the permanent locations at Parcel 44 and near Kinross St. and Kent Ave. Original Assumptions (Energy Centre Located at Parcel 44) Scenario

Baseload Heat Source Metro WTE

Grants (thousands) $2,000

Timing of WTE Interconnection 2018

2010 2015 2020 2025 2030 2035

All dollar values in thousands of $2007




Annual Capital Expenditures 9,201 457 347 404 - -


Revenues 229 1,436 2,775 4,252 4,459 4,676

$ / MW.h 73 76 80 84 88 92

Operating Costs 430 1,095 1,048 1,475 1,477 1,480

$ / MW.h 132 56 29 28 28 28

Unlevered Pre-Tax Cash Flow (7,442) (158) 1,332 2,321 2,974 3,189

IRR 5.80%



Updated Assumptions (Energy Centre Located at near Kinross St. and Kent Ave) Scenario




2010 2015 2020 2025 2030 2035





Annual Capital Expenditures 7,747 304 12,409 559 - -


Revenues 114 921 2,167 3,995 4,726 4,727

$ / MW.h 66 89 93 93 93 93

Operating Costs 361 817 790 1,281 1,505 1,506

$ / MW.h 201 76 32 29 28 28

Unlevered Pre-Tax Cash Flow (6,012) (233) (11,094) 2,092 3,222 3,221

IRR 5.25%



Updated Assumptions (Energy Centre Located at Parcel 44) Scenario




2010 2015 2020 2025 2030 2035





Annual Capital Expenditures 9,314 349 11,899 530 - -


Revenues 114 921 2,167 3,995 4,726 4,727

$ / MW.h 66 89 93 93 93 93

Operating Costs 376 834 799 1,289 1,512 1,513

$ / MW.h 210 77 33 29 28 29

Unlevered Pre-Tax Cash Flow (7,596) (296) (10,593) 2,113 3,215 3,214

IRR 4.82%


Please do not hesitate to contact me if you have additional questions or comments. Regards,

Trent Berry, Partner Compass Resource Management Ltd.

Attachment A - Original DPS Phasing Under Alternate Energy Centre Locations

1) Lot 44 Energy Centre 2) Illustrative Alternate Energy Centre Location near Kinross St. and Kent Ave.

HEATING CENTER TOHEATING OUTER CENTER TRENCH

SIZE NPS JACKET DIA. DISTANCE WIDTH

48.3/110 40 110 800 30060.3/125 50 125 825 32576.1/140 65 140 850 32588.9/160 80 160 900 350114.3/200 100 200 975 400139.7/225 125 225 1025 425168.3/250 150 250 1075 450219.1/315 200 315 1200 500273.0/400 250 400 1375 600323.9/450 300 450 1475 650355.6/500 350 500 1600 700406.4/520 400 520 1640 720457.2/560 450 560 1720 760

Attachment B – Updated DPS Phasing Under Alternate Energy Centre Locations

1) Lot 44 Energy Centre 2) Illustrative Alternate Energy Centre Location near Kinross St. and Kent Ave. 3) Temporary Energy Centre near Kinross St. and Kent Ave. and Permanent Energy

Centre on Lot 44

HEATING CENTER TOHEATING OUTER CENTER TRENCH

SIZE NPS JACKET DIA. DISTANCE WIDTH

48.3/110 40 110 800 30060.3/125 50 125 825 32576.1/140 65 140 850 32588.9/160 80 160 900 350114.3/200 100 200 975 400139.7/225 125 225 1025 425168.3/250 150 250 1075 450219.1/315 200 315 1200 500273.0/400 250 400 1375 600323.9/450 300 450 1475 650355.6/500 350 500 1600 700406.4/520 400 520 1640 720457.2/560 450 560 1720 760

Potential Heat Sources For a

Neighbourhood Energy Utility At

City Of Vancouver East Fraser Lands

For Compass Resource Management

Prepared by:

FVB ENERGY INC.

Suite 350, 13220 St. Albert Trail

Edmonton, Alberta

T5L 4W1

Phone; (780) 453-3410

March 21, 2007

Fax (780) 453-3682

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COMPASS RESOURCE MANAGEMENT POTENTIAL HEAT SOURCES PAGE 2

VANCOUVER EAST FRASER LANDS FINAL TECHNICAL MEMO MARCH 21, 2007

TABLE OF CONTENTS

1 SUMMARY OF FINDINGS ..................................................................................................... 3 2 INTRODUCTION .................................................................................................................... 6 3 LOAD BASIS.......................................................................................................................... 7 4 ALTERNATIVE ENERGY CONCEPTS ............................................................................... 10

4.1 SEWER HEAT CONCEPT DESCRIPTION............................................................................. 11 4.2 GEOTHERMAL CONCEPT DESCRIPTION ............................................................................ 11 4.3 BIOMASS CONCEPT DESCRIPTION ................................................................................... 13 4.4 BURNABY WASTE INCINERATOR CONCEPT DESCRIPTION .................................................. 15 4.5 PRELIMINARY ENERGY CENTRE FOOTPRINTS................................................................... 15

5 EVALUATION OF ALTERNATIVE ENERGY CONCEPTS................................................. 16 5.1 CAPITAL COSTS.............................................................................................................. 16 5.2 OPERATING COSTS......................................................................................................... 17 5.3 CONCEPT PERFORMANCE ............................................................................................... 19

6 APPENDIX 1: EAST FRASER LANDS NEU SERVICE AREA.......................................... 23 7 APPENDIX 2: PRELIMINARY CONCEPT LAYOUTS ....................................................... 25 8 APPENDIX 3: CAPITAL COST ESTIMATES..................................................................... 32 9 APPENDIX 4: OPERATING COST ESTIMATES ............................................................... 34 10 APPENDIX 5: COSTING ASSUMPTIONS ......................................................................... 36

10.1 GENERAL ....................................................................................................................... 36 10.2 CENTRAL ENERGY CENTRE............................................................................................. 36

Companion Reports This Technical Memorandum is one of a series that comprise a Technical Assessment of a proposed Neighbourhood Energy Utility as part of the East Fraser Lands development. The full assessment requires reference to all of these reports, although each stands alone for its respective subject. These memoranda have the following titles:

1. Demand Forecast For A Neighborhood Energy Utility

2. Potential Heat Sources For A Neighborhood Energy Utility

3. Community Heat Distribution System For A Neighborhood Energy Utility

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1 SUMMARY OF FINDINGS The East Fraser Lands Neighbourhood Energy Utility is seeking potential heat sources that could provide financial and environmental benefits over the “business as usual” case of providing heating through the use of natural gas.

The objectives of this Technical Memorandum was to focus on developing concepts, capital cost estimates, operating cost estimates and performance narratives for the following alternate energy options:

1. Sewer heat

2. Geothermal

a. Ground-water with Heat Pump (GWHP)

b. Ground-source with Heat Pump (GSHP)

3. Biomass (residues and pellet fuels)

4. Heat from Burnaby Waste Incinerator

These technologies are all available with some more proven than others. In general, it can be expected that alternate energy technologies will provide energy at a lower annual fuel cost but at a higher initial capital cost.

It is critical that the alternate energy capacity, once installed is utilized as much as possible through the year.

Hence, it is important to consider these technologies in the context of the energy load to be served for this development (see the companion report on heating loads titled “Demand Forecast”).

The Scenario 1 heating load profile for the East Fraser Lands development is provided in the figure below.

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5.00

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Load

[MW

]

Phase 1Phase 2Phase 3Phase 4Phase 5

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The Phases have been provided and represent 5-year intervals. Due to the uncertain nature of these developments this analysis has been based on a 10-year horizon or up to Phase 2.

The winter peak heating demand is ~20 MW and the summer baseload demand is about 10%.

Given the Phase 2 profile and the fact that alternate energy capacity is relatively expensive, and the need to maximize its use, it is recommended a capacity of 5 MW be targeted for the alternate energy capacity. It is anticipated this capacity would be installed once sufficient load is realized – in years 3 to 5.

It is recommended a 1 MW condensing natural gas boiler be used to meet summer baseloads in the early stages. This also allows time to build actual load profiles to best fit the alternate energy capacity at the right time.

FVB believes this is a good “start-up” strategy as it reduces initial capital and allows for the best fit of alternate energy capacity. However, it is recognized that some form of alternate capacity may be desired very early on, and if so, FVB would recommend installing a much smaller cost effective baseload capacity on the order of 0.5-1.0 MW.

The total capacity within the Energy Centre would be 26 MW, which includes for 5 MW alternate energy boiler, a 1 MW condensing boiler, plus peaking/backup natural gas boilers.

The capital costs for the different options investigated are summarized in the figure below.

Concept Options Capital Cost Estimates

$0

$5,000,000

$10,000,000

$15,000,000

$20,000,000

$25,000,000

All Gas

Boil

ers

GSHP + Gas

GWHP + Gas

SewerH

P + Gas

Biomas

s + G

as

Pellet

+ Gas

BWI +

Gas

5 MW Alt. + 21 MW Gas

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The heat pump options are most expensive, while the biomass options have the lowest capital cost for alternate energy capacity.

The annualized operating costs for the different options are summarized in the figure below.

Operating Cost Comparison

$0

$1,000,000

$2,000,000

$3,000,000

$4,000,000

$5,000,000

All Gas

Boil

ers

GSHP + Gas

GWHP + G

as

SewerH

P + Gas

Biomas

s + G

as

Pellet

+ Gas

BWI +

Gas


Annual Operating CostAnnual Fuel CostLevelized Capital

The figure shows the benefit of low cost biomass residue fuels relative to other alternate energy options and even relative to the business-as-usual case of all gas boilers. Also, of note is the effect of the high cost of pellet fuel. The annual fuel costs are preliminary and based on assumed commodity prices that will be updated in the business case analysis.

The biomass and BWI concepts are most likely to deliver the targeted 75% of annual energy from alternate sources, while the heat pump options are more likely to be less due to their restricted turndown capability.

Biomass residue concept would provide the best combination of low capital and operating costs, greenhouse gas (GHG) reduction and low technology risk for a baseload heat source among the technologies considered.

Biomass, however, will face more stringent permitting requirements.

Subject to permitting, the next best alternative for planning purposes would be to source heat from the Burnaby Waste Incinerator.

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2 INTRODUCTION A new development is being proposed called the East Fraser Lands (EFL) at a location as shown in Appendix 1. In conjunction with this development, the City of Vancouver is considering the viability of a Neighbourhood Energy Utility (NEU) to serve the energy needs of this development.

The NEU would serve the individual building energy needs from a single central Energy Centre and distribute the energy via buried water lines.

At a single central Energy Centre a multitude of capacity alternatives are typically available to meet building energy demands. No longer is it justified, due to their high prices, extreme volatility, and pollution impacts, to assume that fossil fuels are our only choice to meet building heating demands.

Alternative energy choices are available that use non-fossil fuels as their primary fuels.

In the Vancouver region, the obvious resources that should be considered include “waste” heat sources such as sewer heat, forestry biomass residues, post-recycling municipal waste residues, industry waste heat, etc, and renewable resources such as geothermal.

The scope of this report includes considering the following alternate energy types:

1. Sewer heat

2. Geothermal

a. Ground water with Heat Pump (near Fraser River)

b. Ground-source with Heat Pump (closed loop)

3. Biomass

In addition, the concept of using excess heat from the Burnaby Waste Incinerator due to its relatively close location was evaluated.

These technologies are all available with some more proven than others. In general, it can be expected that alternate energy technologies will provide energy at a lower annual fuel cost but at a higher initial capital cost.

Hence, it is important to consider these technologies in the context of the energy load to be served for this development (see the companion report on heating loads titled “Demand Forecast”).

The objective of this report is to:

1. Define the concepts for each alternate energy option

2. Develop preliminary capital and operating costs associated with the concepts,

3. Provide a narrative on relative performance of each option,

The developer provided two possible locations for the Central Energy Centre that was used for this analysis, (1) at Lot 44, and (2) at Lot 5. No preference was given and we have used one or the other depending on the alternative technology.

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3 LOAD BASIS The Demand Forecast and Community Heat Distribution Technical Memorandums show that the development load for heating is much greater than that for cooling, i.e. the annual energy for heating represents 86% of the total annual thermal energy. Options other than district cooling are more suitable for this location and type of development including:

• Focus on “free” cooling through planning and design,

• Packaged DX units offered as an option to individual units,

• Rooftop DX units serving top floors of towers.

Hence, this report has focused on heating demand (space heat and domestic hot water).

Two Load Scenario’s were developed that considers the rate of buildout for the development. Scenario 1 represents buildout to 20 MW heating within 10 years. Scenario 2 represents buildout to 10 MW within 10 years.

Due to the valuable nature of the area, it is assumed Scenario 1 is the most likely and has therefore been used as the basis for this analysis.

For Scenario 1 the Phase 2 peak heating diversified demand is ~20 MW and the annual heating energy is ~50,800 MWh.

The basic design temperatures for the district heating system are anticipated to be as follows:

• When outdoor temperatures are above 0 degrees Celsius, supply = 65°C and return = 45°C,

• When coldest winter days, supply = 95°C and return = 50°C,

A review of the demand profile is necessary to establish the appropriate size of the alternate energy capacity. The objective of this expensive capacity is to maximize the amount of annual energy it delivers. A reasonable target is 75% or higher, or about 38,100 MWh/y.

The expected heating load duration curve for heating is shown in Figure 1.

The load duration curve shows how the heat demand varies throughout the year, with very few hours at the maximum peak demand (coldest winter days) and an extended period of low heating demand through the summer (mainly domestic hot water load).

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Figure 1 - EFL Heating Load Duration Curve – Scenario 1

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[MW

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Phase 1Phase 2Phase 3Phase 4Phase 5

Factors affecting the best selection of alternate energy capacity include the overall load profile, the rate of buildout, the summer baseload, the winter peaking profile, the system temperatures, and the turndown capability of the capacity.

Given the nature of this development (mainly residential), the summer load in the first few years will be quite small and expecting an alternate capacity to turndown to serve this load is questionable.

A small baseload capacity in the range of 2 MW would be more suitable for the summer load, but would not contribute significant energy as the project builds out beyond Phase 1. To increase the energy contribution a second alternate energy boiler would be required. This takes up significant space on the site, plus it is more expensive than just one unit.

A larger capacity in the range of 5-7 MW would be more suitable for delivering a significant amount of annual energy (in the target range of 75%), but would be oversized in the early years and especially during the summer. Hence, it would most likely be shutdown in the summer.

If the goal is to maximize energy delivered, FVB recommends installing 5 MW of alternate energy capacity. This amount of capacity should wait until years 3-5, i.e., until suitable load exists. To serve the early baseload and future summer loads, FVB would install a 1 MW condensing gas boiler.

If the goal is to install alternate energy capacity from the outset, FVB recommends using a smaller unit of 1 MW or less (more commercially available sizes). This unit would cost less, run essentially year round, and provide some nominal level of alternate energy.

For the purposes of this evaluation a 5MW alternate energy capacity size was selected. It is anticipated that this capacity would be added in years 3 to 5 of the development. It is further anticipated that sometime near year 10, additional alternate energy capacity would be added.

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The basis for the 5 MW selection includes:

o Want the first few years to better understand the load profile,

o Contributes ~65-70% of the total energy expected,

o Provides significantly more energy than 2.5 MW as the load builds beyond Phase 1,

o It delays the need for adding more alternate energy capacity enabling a proper assessment based on actual data

o Has a smaller footprint than two 2.5 MW facilities

Summary

The following is a summary of the load basis:

o Use heating service only served from one central Energy Centre,

o Use Scenario 1 Phase 2 loads as the basis for costing,

o Use high-efficiency condensing boiler capacity for early baseloads,

o Use initial alternate energy capacity of 5 MW installed in years 3 to 5.

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4 ALTERNATIVE ENERGY CONCEPTS The following possible sources of energy were considered to provide a sustainable energy solution for East Fraser Lands.

1. Sewer heat (with heat pump)

2. Geothermal

a. Ground water with Heat Pump (near Fraser River)

b. Ground-source with Heat Pump (closed loop)

3. Biomass

a. Residues (forestry or municipal)

b. Pellets

Key to considering alternative energy viability is the ability to displace high priced natural gas with low priced alternative fuels, and its long-term availability. Based on preliminary investigations, these issues are summarized in the table below. Table 1: "Fuel" Prices

Alternate Fuel

“Fuel” Price “Fuel” Availability

Sewer Heat $6-7/GJ equivalent.

Sewer heat input is free, but requires electricity for heat pump (~2/3 free and 1/3 as electricity). At $65/MWh for 1/3, the equivalent price for all energy is on the order of $6-7/GJ.

As long as the development proceeds and the population forecasts are met, the sewer flows will be available. Required flows need to be verified.

Geothermal Heat

$6-7/GJ

Same as above, although COPs are less, and equivalent price is higher.

Same as above. Required flows need to be verified via well testing.

Biomass Residues: $1-3/GJ best estimate

Pellets: $7/GJ estimate

For residues prices vary greatly. Can range from being a revenue stream (tipping fee) to a significant cost. Transport costs can be a large contributor. Required volumes are low so risk is low.

Residues from Forest Industry is uncertain, but large volumes exist relative to need (<20,000 T/y)

Residues from City Parks are a relatively secure source.

Pellets are a burgeoning industry but securing supply for more than 5 years is questionable.

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As is evident from the table, the lowest cost fuel would be from biomass residues

Basic descriptions of the concepts are provided below. A summary and each of the concepts is represented diagrammatically (site and plant layout) in Appendix 2.

Each of the alternate energy options are coupled with natural gas fired peaking/backup boilers, as required to ensure uninterrupted service to customers. To meet the Phase 2 peak demand, the Energy Centre would contain the following boilers:

o 1 x 5MW Alternate Energy Hot Water Boiler

o 1 x 1MW Natural Gas Condensing Hot Water Boiler (for summer baseload)

o 4 x 5MW Natural Gas Standard Hot Water Boilers

4.1 SEWER HEAT CONCEPT DESCRIPTION

The sewer heat concept involves extracting heat energy from available sewer flows and then using a heat pump to elevate the temperatures so that the energy can be used in the district heating network.

Two options are typically available to do this: (1) diverting stable flows from a sewer pump station to a heat exchanger (heat pump evaporator), or (2) by using a special sewer pipe with internal heat exchanger built in.

Option 1 is considered more viable primarily due to:

o Less complications for installation and maintenance,

o Available nearby proposed pump station.

Lot 44 was chosen for this concept due to its location relative direction of sewer flows (west to east), and hence more sewer flow would be available further east. Sewer flows at the new proposed pump station (near Boundary Road and Kent Avenue North) could be in the range of 150-200 litres/second – these numbers are very preliminary and further discussions with the City are required.

Based on our analysis at SEFC, a 5 MW output sewer heat pump concept would require sewer flows of the order of 200 litres/second.

Daily profiles would need to be analyzed to determine the amount of energy available from this concept. A daily profile was not available.

At this time, it is assumed sewer flows to the proposed pump station would be redirected to a “wet-well” system at the central Energy Centre, screened, and then pumped through the heat pump to a transfer wet-well, and then back to the pump station. Capital costs associated with this “interception” are included in the capital estimate.

It is recommended that the sewer heat pump provide a temperature output of 65-70°C at all times, rather than try to meet peak winter requirements. Gas boilers will be used to “trim” up the temperature when necessary.

It is anticipated the heat pump will operate with an overall Coefficient of Performance (COP) of approximately 3 in this setup.

4.2 GEOTHERMAL CONCEPT DESCRIPTION

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The geothermal heat concept involves extracting heat energy from heat available within the ground, either indirectly by a vertical closed loop heat exchange system (ground-source), or directly by pumping ground water to a heat pump (ground-water).

Ground temperatures are typically cooler than sewer temperatures and hence COPs will be less.

FVB has used Natural Resources Canada’s RETScreen model to do the preliminary analysis of the geothermal concepts.

For Vancouver a mean earth temperature of 9°C has been used. Due to the low source temperatures, it is anticipated overall COPs will be about 2.6.

Ground-Source Heat Pump Concept

The GSHP concept extracts heat from the ground via a network or “field” of vertical boreholes drilled into the ground. A non-freeze water based fluid is pumped into through the network through closed loop piping and picks up and transfers the heat from the boreholes to the Energy Centre. A heat pump elevates the temperatures for use in the district heating system.

The key is to have sufficient borehole length and spacing to ensure the ground energy is replenished as fast as it is extracted on a seasonal basis. As cooling is not part of the NEU concept (see technical memorandum “Community Heat Distribution System“ for explanation), the field will not benefit from heat rejection. This will result in a larger field to deliver the same capacity.

The field consists of many vertical boreholes drilled to a depth of about 100m and spaced in a compact configuration to fit in the identified area. The expected footprint of the field is on the order of 6,500 m2 with a total borehole length of about 80-100 km to achieve an output of 5 MW.

It is proposed to locate the geothermal field under the proposed soccer field adjacent to Lot 44.

Detailed investigations beyond the scope of this report will be required to fully evaluate the performance of the field for the chosen location.

Ground-Water Heat Pump Concept

The GWHP concept uses groundwater pumped from “producing wells” directly to the central Energy Centre where heat exchangers extract the energy and the water is pumped back to the ground via “injection wells”. A heat pump elevates the temperatures for use in the district heating system.

The key is to have sufficient well flow and spacing to ensure no interaction between producing and injection wells, i.e. to keep source temperatures as high as possible.

The GWHP system would consist of about 4 producing wells and 4 injection wells. The producing wells would be located “upstream” of the groundwater flow direction. The total well flowrate required to meet the 5 MW capacity is on the order of 235 litres/second – this is a high rate and would need to be confirmed through testing. The expected footprint of the field is on the order of 900 m2 assuming a 6 m radius between wells.

It is proposed to locate the ground-water wells near the Fraser River between Lots 42 and 52.

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4.3 BIOMASS CONCEPT DESCRIPTION

The biomass concept involves using a locally available, renewable resource that is priced significantly less than other alternatives.

Biomass based district heating plants are common in Scandinavia and have been implemented in some recent district heating projects in Canada, including Revelstoke BC (2005), Oujebougamou QC (1994), and Charlottetown PEI (1986). A significant biomass system is operating in downtown St. Paul Minnesota (2001), and one is planned for downtown Seattle Washington (2008).

Resources that will be targeted as possible supplies include:

o Forestry residues

o City of Vancouver woody residues

o Wood Pellets

The attractiveness of the fuel types is essentially based on delivered price, security of supply, and environmental performance.

Based on the biomass capacity sizing and the heating values of the fuels, the following volumes will be necessary to achieve a 75% energy target:

o Residues = 15,000 – 16,000 green tonnes per year (50% MC, 10.9 MJ/kg)

o Pellets = 9,000 – 10,000 tonnes per year (std grade, 18.5 MJ/kg)

At peak winter conditions less than 4 trucks per week are required for residues and about 2 trucks per week for pellets, assuming 20 Tonne truck capacities.

The biomass concept would see the fuel processed offsite to boiler “spec” grade and delivered in covered truck trailers.

Either side-dump trailers or “shuffling” floor trailers would automatically dump the fuel into a “live” storage container. The live storage automatically feeds fuel to the boiler as needed. Sufficient storage capacity is provided to meet a three-day peak burn rate (winter long weekend).

The live fuel storage would be attached to and of similar architecture as the main Energy Centre.

The biomass system produces hot water from the fuel. Flue gas would exit via a flue stack. Emissions cleanup equipment would reduce stack emissions of particulate matter to required limits (assumed < 20 mg/nm3).

Bottom ash and fly ash will be automatically collected into an ashbin. Ash is anticipated to be less than 3% by weight for residue fuel and fewer than 2% for pellet fuel – needs to be confirmed once fuel source is chosen. At peak burn rates about 2 Tonnes/week of residue ash and 800 kg/week of pellet ash will need to be hauled away.

Technologies available for converting biomass fuel to energy are diverse. By far the most common, well-understood and least risk choice is direct combustion. All the biomass district heating projects noted above are based on combustion technology.

Combustion technology has advanced significantly to optimize efficiency over wider operating ranges, while ensuring emissions are minimized. Grate designs and

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movements, variable speed motors, advanced monitoring, and better computer controls are improving performance. Coupled with advances in post combustion emission cleanup, emissions of particulate of less than 20 mg/nm3 can be achieved.

Other technologies are available including biomass gasification technology. Gasification of biomass is an “old” technology that is trying to become “commercial” as a way to convert residues into useable forms of energy.

Gasification is a thermo-chemical conversion of biomass under limited oxidation and moderate temperatures that results in converting biomass into low to mid energy content biogas. The resulting heating value is about 20% to 30% of that of natural gas.

The main benefit of gasification is that the biogas or woodgas can be used in a multitude of end devices such as boilers to produce heat and reciprocating engines and gas turbines to produce power.

However, a key challenge to producing electricity is to cleanup the biogas sufficiently and to modify engines/turbines to use such that the operation is reliable and cost effective. This use of biogas is very much in a research and development phase.

Another key benefit purported is the lower emissions relative to combustion. However, post-combustion cleanup technology has improved such that very low emissions can be achieved with conventional combustion technology.

A BC company, Nexterra (www.nexterra.ca) is testing a demonstration facility in Kamloops BC and is planning the first early commercial plant at a Tolko mill north of Kamloops.

At this time, it appears the technology is focused on generating thermal energy via a two-stage system of gasification and secondary combustion of gases. There are no immediate plans to focus on using the biogas for power production.

Other companies (Westwood, Chiptec) also are developing biomass gasification systems.

This technology is not considered commercial at this time and will possibly be commercial within 5 years.

A "fast pyrolysis" process that converts forest and agricultural residue (including bark) into liquid BioOil and char is under development. BioOil is a clean burning, greenhouse gas neutral fuel that will initially be used to replace fossil fuels to generate power and heat in stationary gas turbines, diesel engines and boilers. The char is a high BTU (heating value) solid fuel that can be used in kilns, boilers and the briquette industry.

Two Canadian companies are active in this area, Dynamotive out of Vancouver and Ensyn Technologies out of Ottawa.

This technology is not considered commercial at this time and will possibly be commercial within 10 years.

In the near term, the use of advanced combustion with heat recovery is the most proven, low-risk way to convert biomass materials to usable heat.

Beyond 2010, gasification and pyrolysis could prove suitable as a means to use biomass to generate power and possibly transportation fuels. However, these technologies need to advance their performance and reliability from demonstration to commercialization.

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4.4 BURNABY WASTE INCINERATOR CONCEPT DESCRIPTION

An opportunity may exist to use heat generated at the existing Burnaby Waste Incinerator. A discussion with the GVRD indicated an interest in the concept of supplying heat to a district heating system. Currently, the BWI sells steam to a nearby paper plant at below the commodity price of natural gas.

The concept would involve installing equipment at the BWI to extract steam from the steam turbine and condense steam in an exchanger to deliver 5 MW of capacity. The exchanger would transfer the energy to a separate hot water loop that would transfer hot water to the EFL Energy Centre. A second exchanger at the Energy Centre would transfer the energy to the district heating network for distribution to customers.

Extraction would take place at the existing steam turbine at a pressure of about 20 psi such that sufficient temperatures of hot water could be achieved.

A small building would be required on the BWI site to house the necessary energy extraction equipment – anticipate about 10mx10m.

A key challenge is identifying a route for the buried pipes (two pipe closed loop) connecting BWI to the Energy Centre.

A possible route has been identified along North Fraser Way (see Appendix 2). The route is approximately 4.5 km long and would likely require some right-of-way easements.

The piping is the largest cost of this option, hence it is recommended to extract only to the baseload of 5 MW.

The estimated footprint of the Energy Centre for each option is summarized below.

4.5 PRELIMINARY ENERGY CENTRE FOOTPRINTS

Table 2: Energy Centre Footprint

Preliminary Estimates Energy Centre Footprint

All Gas Boilers 600 m2GSHP 700 m2GWHP 700 m2Sewer HP 750 m2Biomass Residue 880 m2Biomass Pellets 810 m2BWI 500 m2 + 100 m2The BWI concept has the main Energy Centre at EFL plus a small building at BWI to extract hot water.

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5 EVALUATION OF ALTERNATIVE ENERGY CONCEPTS FVB has evaluated the concepts on the following basis:

1. Capital Costs

2. Operating Costs

3. Concept Performance

5.1 CAPITAL COSTS

FVB has prepared capital cost estimates for each of the alternate energy concept options described. In addition, an estimate is provided for a plant with all gas boilers, including a condensing boiler, for comparison. Details of the capital cost estimates can be found in Appendix 3 and an explanation of the assumptions in Appendix 5.

The capital estimates are based on high-level concepts for screening purposes. These estimates are based on 1st Quarter 2007 Means Costworks and FVB internal proprietary database.

The capital costs include generally the following:

• Building

• Alternate Energy Capacity (5MW)

• Natural Gas Peaking/Backup Energy Capacity (21 MW)

• Balance of Plant Equipment and Installation

• Construction Management, Engineering, PST, Contingency

The capital cost estimates are summarized in the figure below

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Figure 2: Capital Cost Comparisons ($2007)

Concept Options Capital Cost Estimates

$0

$5,000,000

$10,000,000

$15,000,000

$20,000,000

$25,000,000

All Gas

Boil

ers

GSHP + Gas

GWHP + Gas

SewerH

P + Gas

Biomas

s + G

as

Pellet

+ Gas

BWI +

Gas


The lowest capital cost option, as expected, is the all gas boiler option at $9 million.

The highest capital cost options involve the use of heat pumps ($20 million range). This is primarily a result of very high equipment costs and the high costs associated with the geothermal fields/wells. Heat pumps of the 5 MW scale have limited suppliers and preliminary investigations are that these units are orders of magnitude more expensive than equivalent chillers.

Of the heat pump options, the Sewer Heat Pump option is the lowest cost at $18.1 million.

The biomass options are about $14 million with the pellet option being about 5% less than the residue option.

The BWI option is about $16.8 million with a large portion (43%) for the connecting lines to the EFL Energy Centre.

5.2 OPERATING COSTS

FVB has prepared an estimate of the annual operating costs for each of the concepts. A detailed summary is provided in Appendix 4.

The operating costs are summarized in the figure below. The biomass option based on residues for fuel is the lowest cost option due to its much lower fuel cost. The heat pump options are the highest cost options.

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Figure 3: Operating Costs Comparisons

Operating Cost Comparison

$0

$1,000,000

$2,000,000

$3,000,000

$4,000,000

$5,000,000

All Gas

Boil

ers

GSHP + Gas

GWHP + G

as

SewerH

P + Gas

Biomas

s + G

as

Pellet

+ Gas

BWI +

Gas


Annual Operating CostAnnual Fuel CostLevelized Capital

For screening purposes, FVB used assumed delivered prices for natural gas of $8/GJ for natural gas and $80/MWh for electricity.

Capital costs were levelized over 25 years at 6% interest rate.

Other key operating assumptions are summarized in the table below. Table 3: Alternate Energy Key Assumptions

All Gas Heat Pump Biomass BWI Alt. Energy % 0% 75% 75% 75%

Seasonal Efficiencies

80% GSHP COP=2.6

GWHP COP=2.6

Sewer COP=3.0

Residues=70%

Pellets=75%

95%

(Line losses)

Alt. Energy Fuel Cost1, $/MWh

na GSHP COP=29

GWHP COP=29

Sewer COP=25

Residue=4

Pellets=28

24

Incr. Labour (FTE2 at $80,000 pa)

na 1 1 0

1 Dollars per MWh of energy output

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Alternate Capacity Maintenance

Na 1% of alt. capital Residues=1.75%

Pellets=1.5%

0.5%

The alternate energy delivered is a target value used for screening only.

Note the above operating costs are for the central Energy Centre only and do not include for those for the customer distribution system – these are provided in the “Community Heat Distribution System” companion report.

The estimated fuel usage for each of the concept options is summarized in the table below. Table 4: Fuel Usage

All Gas Heat Pump Biomass BWI Natural Gas 227,000 GJ 57,000 GJ 57,000 GJ 57,000 GJ

Electricity (for Heat Pumps)

na GSHP 14,650 MWh

GWHP 14,650 MWh

Sewer 12,700 MWh

na na

Biofuels na na Residue 20,000 T/y

Pellets 11,300 T/y

Na

Purchased Energy as Steam

na na na 40,100 MWh

(180,500 GJeq3)

5.3 CONCEPT PERFORMANCE

Concept performance is based on the following key parameters:

• Ability to achieve 75% of total energy from alternate source

• Proven track record (commercial risk)

• Technical Risk

• Approval Risk

• Fuel (energy source) Risk

• Emissions Risk

Ability to Achieve 75% of Total Energy

FVB is concerned the heat pump options will have difficulty achieving the 75% target of total energy delivered, due to the following:

2 FTE is full time equivalent 3 GJeq is the equivalent natural gas volume in GJ as a fuel.

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• Turndown ratios may not be greater than 2:1, resulting in very limited operation

during summer months,

• Limited information on hourly sewer flows,

• Achieving 5MW from the “compact” GSHP field in later months of the winter,

• Achieving 235 litres/second from the GWHP wells near the Fraser River – need testing to confirm,

• The high level of temperature “lift” required for a central heat pump district heating system versus decentralized systems,

A more realistic value is in the 50-60% range.

For the biomass options, the turndown capability is likely up to 4:1 so achieving the target is more probable. Additional capacity beyond 5 MW may be required as the project builds-out to Phase 2 and beyond.

The BWI option has fully variable control and turndowns sufficient to meet the 75% target. Pipeline heat losses are anticipated to be less than 150 KW.

Proven Track Record

The geothermal heat pump options at the scale desired and in a centralized district heating application are essentially unproven in Canada, although it has some history in Europe. Typically, GSHP/GWHP is implemented at the building scale where both heating and cooling is required, and preferably coincidently.

Sewer heat recovery using a pump station and heat pump at this scale has been implemented with success in Norway and Japan, but generally is not a common solution.

Biomass for energy is used commercially across Canada in both the industrial sector and in district heating. Biomass combustion is well developed in Canada and worldwide. Gasification, although an “old” technology, is still struggling to become commercial, but it is anticipated that over the next 5 years this might be a viable solution.

Heat extraction from a steam turbine is well understood and commercially proven.

Technical Risk

The heat pump options are essentially specialized chillers serving much higher temperature lifts; hence their efficiencies will be relatively lower.

The Sewer heat recovery will be susceptible to variations in sewer flow, the ability to clean the sewer flow prior to the heat pump, and the heat pumps limited turndown capability.

The GSHP option performance will depend on the quality of the “field”. It will be susceptible to the ability of the “field” to deliver the necessary energy over a full winter season without the benefit of cooling heat recharging. In addition, the “field” is large with many grouted boreholes and on the order of 100 km of tubing and associated headers – a significant amount of equipment that will have to be installed with utmost care and attention. Given the limited land availability, borehole interference could be an issue affecting performance.

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The GWHP option performance will depend on the quality of the producing and injection wells. The wells will have to produce on the order of 60 litres/second at a steady temperature without interference from the injection wells.

The Biomass options are relatively low technical risk as they are well proven commercially. However, certain aspects need to be dealt with carefully, including matching the fuel handling system and combustor to the type and quality of fuel available. Skilled operators are required to ensure stable operation of the fuel handling system.

The BWI is a relatively low technical risk option, provided the BWI facility does not experience its own problems.

Approval Risk

The heat pump options appear to have good public opinion and local government support.

In particular, the sewer heat recovery concept is considered favourable and should not have significant approval challenges.

The GSHP option is not expected to have approval problems, once the concept is better understood within the community at this scale.

The GWHP option could face more challenges during approval, as there is an indirect dependency on the flows of the Fraser River, and this could potentially require involvement of the Federal Department of Fisheries and Oceans. Temperature impacts on the Fraser River will need to be examined.

The Biomass option, although very common through rural BC, particularly in the industrial sector, may have the most challenging approval process. The history of poor experiences in the lower Fraser Valley will be a challenge to overcome. It will be paramount to show that the technology chosen is “best available”, highly efficient, commercially proven, and most of all has advanced pollution controls. Biomass is a significant resource that is local, renewable, and offsets significant natural gas and electricity usage.

Pellets may have the advantage in that they seem perceived as a clean fuel.

The BWI option will have the challenge of obtaining required easements for the routing of the buried piping.

Fuel (energy source) Risk

The sewer resource will always be available where there is population, but the key issue is the flowrates availability.

As discussed under Technical Risk, the geothermal resource will have to be confirmed through detailed testing. The “field” and wells will need to be of sufficient size and capacity to deliver the required heat exchange.

Biomass residue from the Forestry Sector should be readily available, however there is also significant competition for this resource within the sector including from other biomass energy plants, OSB plants, particle board manufacturers, reman plants, plus sales to the agriculture industry for bedding, etc.

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Another issue is the overall vulnerability of the Forestry Sector that generates the residue, which has gone through many challenging times recently.

However, it must be stressed that the volumes required for this plant is only on the order of 8,000 BDT4 per year, a small amount compared to BC’s current surplus (estimated at over 1 million BDT5).

The Pellet fuel industry is growing in BC with about 90% of production being sold outside Canada. It relies on the Forestry Sector for whitewood residue for pellet production, hence is faced with some similar pressures as biomass residue (Hog) fuel.

The best biomass option may be to use the woody residues generated within City of Vancouver’s internal departments, e.g. Parks Department. The City would have control over these volumes for long-term security of supply. In addition, the biomass energy plant may be a cheaper disposal option therefore actually generating a savings to the City while giving the NEU a zero cost fuel.

For the BWI option, the supply risk will have to be negotiated with the GVRD.

Emissions Risk

Generally, the heat pump options do not generate any air emissions relative to the alternate energy capacity. However, they do rely on electricity to “lift” the temperature of the source and hence increase electricity usage.

The biomass option does generate emissions. Of particular concern are emissions from the stack of particulate matter and production of “bottom” ash. Bottom ash will be automatically collected in an ash container for disposal.

A perceived concern is high particulate emissions, but with good fuel quality and management, plus the use of advanced cleaning technologies these emissions can be reduced to below 20 mg/nm3.

Another perceived concern is high amount of truck traffic for fuel deliveries. In fact, for the 5 MW facility, it is anticipated that on the order of 4 trucks per week for residue and 2 trucks per week for pellets would be required. These deliveries would be in 20 Tonne covered trucks and can be scheduled at appropriate times.

The use of biomass residue will generate a plume of water vapour out of the stack due to the higher moisture contents in the fuel. This will be noticeable during colder winter days. Pellets, on the other hand, with lower moisture contents in the fuel will have a much smaller water vapour plume. The plume is noticeable when the water vapour condenses as it exits the stack.

The BWI option has no significant emission concerns assuming the existing facility meets current and future requirements.

Each of the alternate energy concepts discussed will displace natural gas, and some will need to use some incremental electricity to do so (heat pump options).

4 BDT – Bone Dry Tonnes 5 Estimated Production, Consumption, and Surplus Mill Wood Residues in Canada – 2004, A National Report; NRCan and Forest Products Association of Canada, November 2005.

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OMPASS RESOURCE MANAGEMENT POTENTIAL HEAT SOURCES PAGE 23

ANCOUVER EAST FRASER LANDS FINAL TECHNICAL MEMO MARCH 21, 2007

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6 APPENDIX 1: EAST FRASER LANDS NEU SERVICE AREA



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East Fraser Lands

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7 APPENDIX 2: PRELIMINARY CONCEPT LAYOUTS

EFL Site

Burnaby

Incinerator

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8 APPENDIX 3: CAPITAL COST ESTIMATES

PLANT CAPITAL COST ESTIMATES

PROJECT NAME: Vancouver East Fraser Lands DevelopmentHeating Plant Options Summary

CLIENT: City of Vancouver

PROJECT No. 206281

PREPARED BY: Jim Manson, P.Eng.DATA SOURCE: Means Cost Works Data & FVB Data BaseREVISION No. AREVISION DATE: 13-Mar-07PRINTED DATE: 13-Mar-07SHEET: 1 of 1

Base Case - Gas Boilers Only Dev Case - GSHP Dev Case - GWHP Dev Case - Sewer HP Dev Case - Biomass Hog Dev Case - Biomass Pellets Dev Case - BWI Heat

Scenario 1 Ph 2: yrs 6-10 Ph 2: yrs 6-10 Ph 2: yrs 6-10 Ph 2: yrs 6-10 Ph 2: yrs 6-10 Ph 2: yrs 6-10 Ph 2: yrs 6-10

Diversified Load 20 MW 20 MW 20 MW 20 MW 20 MW 20 MW 20 MW

Hot Water Production:HW Gas Boiler Capacity Installed 26 MW 21 MW 21 MW 21 MW 21 MW 21 MW 21 MWAlternate Heat Input Capacity 0 5 MW 5 MW 5 MW 5 MW 5 MW 5 MWSource of Alternate Heat Input Ground Source Ground Water Sewage Biomass (Hog) Biomass (Pellets) BWI

Total Plant Capacity 20 MW 20 MW 20 MW 20 MW 20 MW 20 MW 20 MW

Base Building Size 600 m2 500 m2 500 m2 500 m2 500 m2 500 m2 500 m2Alt Building Size incl Fuel Storage 200 m2 200 m2 250 m2 380 m2 310 m2 100 m2Plant Site Footprint

Building $1,614,000 $1,727,000 $1,727,000 $1,823,000 $2,294,000 $2,163,000 $1,360,000Electrical Installation $630,000 $1,511,000 $1,511,000 $1,559,000 $684,000 $606,400 $587,000Mechanical Installation $1,968,000 $2,898,000 $2,898,000 $2,987,000 $3,047,000 $2,953,000 $1,772,000Major Equipment $1,669,000 $4,291,000 $4,291,000 $4,953,000 $3,510,000 $3,303,000 $1,411,000GC OH&P, CM $1,470,000 $2,608,000 $2,608,000 $2,831,000 $2,312,000 $2,211,000 $1,283,000

Construction Sub-Total $7,351,000 $13,035,000 $13,035,000 $14,153,000 $11,847,000 $11,236,400 $6,413,000Soft Costs: Engineering $956,000 $1,694,000 $1,694,000 $1,838,000 $1,486,000 $1,422,000 $833,000

Contingency $735,000 $1,303,000 $1,303,000 $1,415,000 $1,184,000 $1,131,000 $641,000

Plant Total $9,000,000 $16,000,000 $16,000,000 $17,400,000 $14,500,000 $13,800,000 $7,900,000

$346 /KW $615 /KW $615 /KW $669 /KW $558 /KW $531 /KW $304 /KW

Energy Sources:Geothermal "Field" Footprint Required 6,400 m2 1,000 m2

Geothermal "Field" Cost $5,700,000 $2,800,000Connecting Pipe System Cost $67,500 $950,000

Sewage Wetwell System $600,000Connecting Pipe System $100,000

BWI Interconnection Cost $1,700,000BWI Connecting Pipe Cost (200 mm) $7,200,000

Total Project $9,000,000 $21,800,000 $19,800,000 $18,100,000 $14,500,000 $13,800,000 $16,800,000

$346 /KW $838 /KW $762 /KW $696 /KW $558 /KW $531 /KW $646 /KW

Incremental Capital over Base $0 $12,800,000 $10,800,000 $9,100,000 $5,500,000 $4,800,000 $7,800,000

$2,560 /KW $2,160 /KW $1,820 /KW $1,100 /KW $960 /KW $1,560 /KW

FVB Energy Inc.

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9 APPENDIX 4: OPERATING COST ESTIMATES

Annual Operating and Maintenance Preliminary Cost Estimate

PROJECT NAME: Vancouver East Fraser Lands DevelopmentHeating Plant Options Summary

CLIENT: City of Vancouver

PROJECT No. 206281

PREPARED BY: Jim Manson, P.Eng.DATA SOURCE: Means Cost Works Data & FVB Data BaseREVISION No. AREVISION DATE: 13-Mar-07PRINTED DATE: 13-Mar-07SHEET: 1 of 1

Base Case - Gas Boilers Only Dev Case - GSHP Dev Case - GWHP Dev Case - Sewer HP Dev Case - Biomass Hog Dev Case - Biomass Pellets Dev Case - BWI Heat

Scenario 1 Ph 2: yrs 6-10 Ph 2: yrs 6-10 Ph 2: yrs 6-10 Ph 2: yrs 6-10 Ph 2: yrs 6-10 Ph 2: yrs 6-10 Ph 2: yrs 6-10

Diversified Load 20 MW 20 MW 20 MW 20 MW 20 MW 20 MW 20 MW

Hot Water ProductionHW Gas Boiler Capacity Installed 26 MW 21 MW 21 MW 21 MW 21 MW 21 MW 21 MWAlternate Heat Input Capacity 0 5 MW 5 MW 5 MW 5 MW 5 MW 5 MWSource of Alternate Heat Input Ground Source Ground Water Sewage Biomass (Hog) Biomass (Pellets) Burnaby Waste Incinerator

Total Plant Capacity 20 MW 20 MW 20 MW 20 MW 20 MW 20 MW 20 MW

Total Energy Delivered 50,800 MWh 50,800 MWh 50,800 MWh 50,800 MWh 50,800 MWh 50,800 MWh 50,800 MWh% Energy from Alternate Energy Capacity 75% 75% 75% 75% 75% 75%Alt Energy 0 MWh 38,100 MWh 38,100 MWh 38,100 MWh 38,100 MWh 38,100 MWh 38,100 MWhAlt Energy EFLH 7620 7620 7620 7620 7620 7620

Boiler SBE 80% 70% 75% 95%Staff Required 3 4 4 4 4 4 3HP delta T 70 deg C 70 deg C 60 deg CHP COP incl parasitics 2.6 2.6 3HP Electricity 14,654 MWh 14,654 MWh 12,700 MWhGas Volume 226,863 GJ 56,716 GJ 56,716 GJ 56,716 GJ 56,716 GJ 56,716 GJ 56,716 GJGas Price $8.00 /GJ $8.00 /GJ $8.00 /GJ $8.00 /GJ $8.00 /GJ $8.00 /GJ $8.00 /GJElectricity Price $0.080 /KWh $0.08 /KWh $0.08 /KWh $0.08 /KWh $0.08 /KWh $0.08 /KWh $0.08 /KWh

Base Plant Annual Operating Costs:Fuel Cost $1,815,000 $454,000 $454,000 $454,000 $454,000 $454,000 $454,000Labour Cost $80,000 $320,000 $320,000 $320,000 $320,000 $320,000 $240,000Consumables Cost $58,000 $58,000 $58,000 $58,000 $58,000 $58,000 $58,000Maintenance Cost $94,000 $94,000 $94,000 $94,000 $94,000 $94,000 $94,000Insurance, Admin and Mngmt $90,000 $90,000 $90,000 $90,000 $90,000 $90,000 $90,000

Plant Sub-Total $2,137,000 $1,016,000 $1,016,000 $1,016,000 $1,016,000 $1,016,000 $936,000

Alt Energy Annual Operating Costs:Fuel HHV 10.9 MJ/kg 18.0 MJ/kgFuel Volume 0 0 0 0 19,974 tonnes 11,289 tonnesFuel Price 0 0 0 0 $10.00 per tonne $126.00 per tonneFuel Cost $0 $0 $0 $0 $199,738 $1,422,400HP Electricity Cost $0 $1,172,308 $1,172,308 $1,016,000 $0 $0 $0Energy Cost $1,227,221% of Incr Capital for Incr Maintenance 1% 1% 1% 1.75% 1.5% 0.5%Incr. Staff Cost $80,000 $80,000 $80,000 $80,000 $80,000 $0Incr. Maintenance $128,000 $108,000 $91,000 $96,250 $72,000 $39,000

Plant Sub-Total $0 $1,380,000 $1,360,000 $1,187,000 $376,000 $1,574,000 $1,266,000

Total O&M $2,140,000 $2,400,000 $2,380,000 $2,200,000 $1,390,000 $2,590,000 $2,200,000

total $42 per MWh $47 per MWh $47 per MWh $43 per MWh $27 per MWh $51 per MWh $43 per MWh"fuel" $36 $32 $32 $29 $13 $37 $33

"alt fuel" $0 $23 $23 $20 $4 $28 $24Alt Energy Maintenance Issues:

none heat pump heat pump heat pump fuel delivery system fuel delivery system heat exchangersground source field production and injection wells sewage screening and pumps grates overheating grates overheating pumps

refractory repairs (periodic - ~6-8 years) refractory repairs (periodic - ~6-8 years)ash buildup in system ash buildup in system

O&M Savings -$260,000 -$240,000 -$60,000 $750,000 -$450,000 -$60,000Displaced Gas 0 GJ 170,147 GJ 170,147 GJ 170,147 GJ 170,147 GJ 170,147 GJ 170,147 GJIncr Electricity Used 0 MWh 14,654 MWh 14,654 MWh 12,700 MWh 0 MWh 0 MWh 0 MWh

Incremental Capital (from Capital Cost File) $12,800,000 $10,800,000 $9,100,000 $5,500,000 $4,800,000 $7,800,000



10 APPENDIX 5: COSTING ASSUMPTIONS The capital cost estimates are for the heat production sources only and do not include the customer distribution system that delivers the heat to the customers.

The capital estimates are based on high-level concepts for screening purposes. These estimates are based on 1st Quarter 2007 Means Costworks and FVB internal proprietary database.

Assumptions also listed on specific capital cost sheets.

10.1 GENERAL

All costs are Q1 2007 Canadian Dollars

PST at 7% is included

GST is not included

Land purchase costs are not included

Costs for Environmental investigation/remediation not included

Fees for Environmental permits and regulatory fees not included

Fees for permits, right-of-ways, and easements not included

Engineering is included

10% Owners Contingency is included

No allowance for Owners development costs

10.2 CENTRAL ENERGY CENTRE 10.2.1 General Costs based on Scenario 1 build-out to Phase 2.

Fees for Development/Building Permits not included

No allowance for expansion beyond noted capacity

Assumes building cost of $2,150 per m2 ($200 /ft2)

Assumes hot water production only at 100 C and 1100 knag

10.2.2 GSHP Option RETScreen used for GSHP “field” sizing and cost estimating

Assumes heating only

Assumes field size of approx 1-1.5 acres (~4,000-6,000 m2)

Assumes “light rock conditions as per RETScreen

Assumes partial well grouting only

HDPE pipe used for field connection to plant

Ph (780) 453-3410

Fax (780) 453-3682



10.2.3 GWHP Option RETScreen used for well cost estimating

Assumes heating only

Assumes flowrate per well of ~60 litres/second

Assumes partial well grouting only

HDPE pipe used for field connection to plant

10.2.4 Sewer HP Option Assumed 200 litres/second is available on steady-state basis – was not confirmed by the City or GVRD at time of issue.

Allocated $500,000 to access sewer from the proposed Kent-Boundary Pump Station.

10.2.5 Biomass Option Assumes

10.2.6 BWI Option Assumes 4,500 trench meter route along North Fraser Way

Assumes road reinstatement

Assumes two-pipe pre-insulated steel pipe buried at 1,200 mm to top of pipe

Assumes a small building (10m x 10m) is erected at BWI to house necessary equipment – no land costs have been included.

END

Ph (780) 453-3410

Fax (780) 453-3682

20 floor, four bentall centre 1055 dunsmuir street ... … · of river district in burnaby to a...

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