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Biomass Combined Heat & Power Options Report

Based on the operational experience of theBioenergy Research and Demonstration Facility

Located atThe University of British Columbia Point Grey – Vancouver

September 2014

French Translation: Pierre Turmel | Editor: Julie Sedger

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AcknowledgementsThe University of British Columbia (UBC) gratefully acknowledges the financial contribution made by Western Economic Diversification Canada to the construction of the Bioenergy Research and Demonstration Facility (BRDF).

UBC acknowledges, in addition, the financial contributions made to the BRDF by the following core funders:

• Natural Resources Canada

• Sustainable Development Technology Canada

• BC Bioenergy Network

• The Province of British Columbia

• FP Innovations

• Canadian Wood Council

• GE Canada

• Nexterra Systems Corp.

UBC also acknowledges the contribution to this Report provided by the Sauder School of Business Centre for Innovation and Impact Investing (formerly ISIS) – specifically, the Centre employees: Neil Thomson, Chris Kantowicz and James Tansey.

Report PurposeThis Options Report is intended to provide the information required to allow institutions, industry and communities to determine the feasibility of adopting a Combined Heat and Power (CHP) system in their particular circumstances with regard to issues such as current fuel costs, heat and power requirements, cost of installation and operation, efficiency of the technology, availability of suitable woody biomass, and the term of investment.

The Report’s publication and distribution fulfills one of the Conditions of Funding set out by Western Economic Diversification Canada.

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Table of Contents 1.0 OVERVIEW . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .1

PERFORMANCE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2

1.1 Proposed . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2

1.2 Actual. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3

1.2.1 Tonnes of CO2 equivalent displaced . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4

1.3 Curtailment of CHP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4

2.0 TECHNLOGY OPTIONS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4

2.1 CHP economic case . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4

2.2 CHP application examples . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5

2.2.1 Case 1: Natural gas displacement, British Columbia, Canada . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5

2.2.2 Case 2: Diesel displacement, Canada . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .6

2.2.3 Case 3: Fossil fuel displacement, North Carolina, USA . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .6

2.2.4 Case 4: Fossil fuel displacement, United Kingdom (UK) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .6

2.2.5 Location sensitivity factors and outcomes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7

3.0 RECOMMENDATIONS AND CONCLUSION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7

3.1 General considerations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7

3.2 Application-specific considerations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .8

3.3 Risk considerations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .8

3.4 Conclusion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .9

List of Figures Figure 1 The bioenergy research and demonstration facility is located on the south-western

edge of the university’s Point Grey, Vancouver Campus and within Metro Vancouver . . . . . . . . . . . . . . . . . . . .1

Figure 2 The BRDF can operate in one of two modes – thermal or CHP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2

List of Tables Table 1 In CHP the BRDF is designed to produce 10 GJ of thermal and 1.96 MWh of electricity . . . . . . . . . . . . . . . . .2

Table 2 BRDF uptime and syngas production has increased significantly since July, 2012. . . . . . . . . . . . . . . . . . . . . . .3

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ACRONYMS

BRDF Bioenergy Research & Demonstration Facility

CHP Combined Heat and Power

CO2 Carbon dioxide

GHG Greenhouse Gas

GJ gigajoule

IC Internal Combustion

kWh kilowatt hour

LDA Load Displacement Agreement

MMBtu Million British Thermal Units

MWh megawatt hour

NO Nitrogen Oxide

NPV Net Present Value

ODMT Oven Dry Metric Tonne

PM Particulate Matter

REC Renewable Energy Certificate

ROC Renewable Obligation Certificate

List of Acronyms

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1.0 OverviewThis Biomass Combined Heat & Power Options Report is based on the operational experience of the Bioenergy Research and Demonstration Facility (BRDF) located on the Point Grey Campus of The University of British Columbia (Figure 1). The BRDF commenced full operation in October 2012 after a two year design, construction and commissioning phase, and is North America’s first demonstration of a community-scale internal combustion engine based combined heat and power (CHP) system fuelled by woody biomass. The facility utilizes the proprietary woody biomass gasification technology developed by Nexterra Systems Corp. (Nexterra) (http://www.nexterra.ca/files/corporate-profile.php) to produce synthesis gas (syngas), which is then used to produce thermal or electrical energy. (For a further description of the technology and the facility, see http://sustain.ubc.ca/research/signature-research-projects/bioenergy-research-and-demonstration-facility).

Bioenergy Research

Demonstration Project

Figure 1. The Bioenergy Research and Demonstration Facility (BRDF) is located on the southwestern edge of UBC’s Point Grey, Vancouver Campus in Metro Vancouver.

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Performance1.1 PROPOSEDThe BRDF has two modes of operation: Thermal and CHP. In Thermal Mode, the facility produces thermal energy in the form of steam. In CHP Mode, the facility produces both electrical AND thermal energy (Figure 2).

Figure 2. The BRDF can operate in one of two modes – Thermal or CHP.

The “designed” energy-production capacity of the BRDF is summarized in Table 1.

DESIGNED ENERGY PRODUCTION CAPACITY

Operating Mode Thermal Energy Electrical Energy

Thermal1 20,000 lbs/hr = 21 GJ = 5.8 MWh 0

CHP 9,600 lbs/hr = 10 GJ = 2.8 MWh 1.96 MWh (Gross)

Table 1. In CHP, the BRDF is designed to produce 10 GJ of thermal and 1.96 MWh of electricity.

1 Three processes within the BRDF generate thermal energy: the boiler, engine exhaust, and the engine water jacket.

Demonstration (Combined Heat & Power) Mode

1. Biomass Dryer – dries “wet” (e.g. up to 55% moisture content) biomass to 20% moisture content.

2. Fuel Storage – wood residue delivered to storage facility conveyed to gasifier.

3. Gasification Technology – gasification process converts woody biomass into clean synthesis gas (syngas).

4. Syngas Conditioning Technology – syngas is conditioned and upgraded to meet fuel specification for engine.

5. Engine – high-efficiency internal combustion engine operates on syngas instead of natural gas to generate electricity & heat.

6. Heat & Power – system will produce 2 MWh electrical energy (4% of current peak use) and 9,600 lbs/hr steam (=12% of current campus use).

Thermal Mode

7. Oxidizer – the syngas is conveyed into an oxidizer where it is combusted, with the resulting flue gas directed through a boiler.

8. Boiler – hot flue gas enters the boiler to produce steam for campus heat distribution.

9. Electrostatic Precipitator (ESP) – the flue gas in cleaned in an ESP that filters out virtually all particulate matter.

10. Thermal Energy – system will produce 20,000 lbs/hr steam or 25% of campus use.

Combined Heat and Power (CHP) System Operating Modes

1. Biomass Dryer 2. Fuel Storage 3. Gasifier

4. Syngas Conditioning 5. Engine 6. Heat & Power

7. Oxidizer 8. Boiler 9. ESP 10. Thermal Energy

Thermal Mode

Tar Cracker Filter

Conditioned SyngasSyngas

Syngas

Electricity (1.96 MWh gross)

Heat (9,600 lbs/hr steam)

20,000 lbs/hr steam

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1.2 ACTUALThe recorded performance of the BRDF is summarized in Table 2.

BRDF PERFORMANCE (July 2012 – September 2014)

Biomass (ODMT)

Plant Uptime (%)

Thermal Mode

(Hours)

Steam Production

(GJ)

CHP Mode (Hours)

Engine Runtime (Hours)

Electricity Generated

(MWh)

FY2012/13

Q2 Jul-Sep 1,671 55% 1,067 10,044 151 89 88

Q3 Oct-Dec 2,024 69% 1,418 12,190 111 65 63

Q4 Jan-Mar 1,797 74% 1,627 18,632 0 0 0

FY2012/13 Total

5,491 66% 4,112 40,866 262 154 151

FY2013/14

Q1 Apr-Jun 2,032 77% 1,542 23,005 144 69 54

Q2 Jul-Sep 2,072 98% 2,166 23,511 0 0 0

Q3 Oct-Dec 2,698 83% 1,836 31,304 0 0 0

Q4 Jan-Mar 2,588 87% 1,867 29,988 0 0 0

FY2013/14 Total

9,390 86% 7,411 107,809 144 69 54

FY2014/15

Q1 Apr-Jun 1,579 71% 1,540 23,159 0 0 0

Q2 Jul-Sep 1,827 88% 1,954 30,123 0 0 0

FY2014/15 Total

3,406 80% 3,494 53,283 0 0 0

Grand Total 18,287 78% 15,017 201,957 406 223 205

Table 2. BRDF uptime and syngas production has increased significantly since July 2012.

For the April 1, 2014 - June 30, 2014 operating period, the facility delivered 18% of the total campus steam despite being shut down for a portion of May for semi-annual maintenance. In June of this same quarter, the facility generated 33% of the campus’s steam requirement – the highest contribution to UBC’s heating load to date. Throughout this operating period, the measured amounts for NOx and Particulate Matter (PM2.5) were compliant with Metro Vancouver permitted limits (http://www.metrovancouver.org/boards/bylaws/Amending%20Bylaws/GVRD_Bylaw_1087_Consolidated.pdf).

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1.2.1 TONNES OF CO2 EQUIVELANT DISPLACED

For UBC, Point Grey, the factor applied to determine the amount of equivalent CO2 displaced is .0625 tonnes of CO2 displaced per GJ of steam delivered to the heating grid by the BRDF2. Therefore approximately 12,600 tonnes of CO2 have been displaced during the July 1, 2012 -September 30, 2014 period.

1.3 CURTAILMENT OF CHPDuring the scheduled two week annual maintenance outage in June 2013, inspections of the clean-syngas conditioning system identified cracks in one of the system’s heat exchangers. CHP-Mode operation of the facility was suspended at that time and remains curtailed until these technical and financial issues are resolved. The major objective – to demonstrate the performance of CHP using woody biomass derived synthesis gas – remains unmet. The financial and performance assumptions used in this Report for CHP are therefore based on limited operating experience and the designed production capacity.

2.0 Technology OptionsCommunities or institutions contemplating local generation of thermal or electrical energy have a wide range of technology candidates to choose from. Ultimately, the technology choice decision is based on economic factors (What is the estimated cost of the energy produced and the value of the energy displaced?); social license (Will the local residents accept the siting and operation of the technology? Does the community/institution place a monetary value on sustainability/reduction of the generation of green-house gases (GHG), and if so, how much?); the technology’s operational risk (Will it operate effectively 24/7?); and the operational context (Does the location provide access to the required fuel supply and are operating labour and technical support readily available?).

2.1 CHP ECONOMIC CASEDetermining the financial merit of on-site CHP requires that the cost of electrical and thermal power produced be compared with the power generated by alternate fuels and their associated conversion technologies. For UBC, the alternate sources were:

• Purchased electrical power sourced from BC Hydro; and,

• On-site steam generated by the burning of natural gas, sourced from Fortis BC.

CHP cost factors considered were:

• Woody Biomass fuel

• Parasitic load

• Operating labour

• Maintenance

• Disposal of generated ash

• Financial capital

2 Factor takes into account the efficiency of the existing natural-gas fueled steam generation plant at UBC Point Grey

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CHP revenue credits considered were:

• Onsite electrical power generation3

• Cost avoidance of UBC-generated GHG4.

Assumptions, based on both actual and predicted data, were used in the business case supporting the construction and operation of the BRDF. A key factor was the availability of technologies and assets that complemented the CHP investment. These assets included the UBC district energy heating system that utilizes steam or hot water to distribute thermal energy to over 400 buildings on the campus. Likewise, UBC’s electrical energy distribution grid allowed on-campus consumption of the generated power and negated the need for integration with the more complex BC Hydro transmission system.

2.2 CHP APPLICATION EXAMPLESTo demonstrate the financial feasibility of the CHP technology in other jurisdictions, four different geographic locations were selected. The first two scenarios considered replicating the CHP system elsewhere in British Columbia - one as an alternative to using natural gas, and the other as an alternative to using diesel fuel. North Carolina, USA was chosen for the third scenario due to the ready availability of woody biomass in that state. Finally, the United Kingdom was chosen as the fourth scenario, due to the existence of financial support programs for renewable fuel technologies and the opportunity for cost avoidance.

Assuming a fully operational facility across the four scenarios, the key variables considered were:

1. Electricity cost and cost savings via a power purchase/load displacement agreement

2. Availability of renewable power incentives

3. The cost of natural gas

4. The cost of woody biomass fuel

5. Local operator costs

6. Carbon finance availability via CO2 offsets

2.2.1 CASE 1: NATURAL GAS DISPLACEMENT, BRITISH COLUMBIA, CANADA

BC Hydro meets over 90% of British Columbia’s power needs, with independent producers and out-of-province purchases supplying the remainder. The supply of power is plentiful in the province and energy costs, when compared globally, are low. Further, hydroelectric power is considered renewable, and there is little incentive for a utility to offer preferential rates in order to meet a renewable portfolio standard. For the BRDF, BC Hydro provides a credit, through a load displacement agreement (LDA) of $.045/kWh for any electrical power generated. It is assumed that other facilities located in BC would enjoy a similar arrangement with BC Hydro. Another unique aspect of renewable energy applications occurring in British Columbia is the existence of the carbon-neutral government mandate. This provides any government entity, or Crown Corporation, the financial incentive for operating a CHP facility by avoiding the cost for purchasing carbon offsets ($30 per tonne in 2013) to realize carbon neutrality for their operation. A non-government owner/operator, who is not encumbered by the BC carbon-neutral mandate, may still benefit from the sale of carbon offsets – with values ranging between $2 and $13 per tonne of carbon displaced. Finally, substitution of woody biomass provides a cost avoidance of the Provincial Carbon Tax (http://www.fin.gov.bc.ca/tbs/tp/climate/carbon_tax.htm) ($25 per tonne of carbon displaced) applied to fossil fuels.

3 Realized via a UBC-BC Hydro executed Load Displacement Agreement 4 Realized via the cost avoidance of the $30 per tonne of CO2 emitted, charged to BC Public Institutions and the $25 per tonne Carbon Tax.

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2.2.2 CASE 2: DIESEL DISPLACEMENT, CANADA

For applications removed from the main grid, and with limited access to natural gas, the benefits of a woody biomass facility can be compared to a diesel-fueled alternative. Average diesel prices in Northern Canadian applications are estimated to be between $0.64 and $0.67 per kWh. While the probability of securing an LDA in other locations is uncertain, a general assumption of an LDA offering $0.40 per kWh has been made for these communities. This application would, like Case 1, also benefit from the cost avoidance associated with the non-payment of the Provincial Carbon Tax. The ready availability of biomass in these locations is countered, however, by the relative scarcity of skilled operators, a 1MWh, or less, electrical energy demand, and lack of access to district energy heating systems.

2.2.3 CASE 3: FOSSIL FUEL DISPLACEMENT, NORTH CAROLINA, USA

Average power and natural gas prices for industrial customers in North Carolina are similar or slightly higher than in BC. Woody biomass costs are generally expected to be less than $60 per ODMT compared to $72 per ODMT at the BRDF, and there is estimated to be more than 8.3 million green tonnes of woody biomass from logging operations in the 17.7 million acres of timberland in the state5. In North Carolina, there do exist woody biomass-based utilities of a larger scale – 16 to 48 MWh – which were built over two decades ago. In North Carolina, there is also no explicit price on carbon. However, CO2 equivalents are traded on the voluntary market at a price of approximately $4 per tonne, (a higher price could be charged if the facility qualifies for California’s Cap-and-Trade Program). North Carolina does have a Renewable Energy Portfolio Standard (REPS) requiring 12.5% of the state’s power to come from renewable sources by 20206. The renewable energy generated from “woody biomass resources” qualifies for Renewable Energy Certificates (RECs). These RECs are sold to non-renewable energy generators on commodity markets to help them meet their mandated renewable energy commitments.

2.2.4 CASE 4: FOSSIL FUEL DISPLACEMENT, UNITED KINGDOM (UK)

The UK power generation landscape is characterized by electrical and natural gas prices for industrial customers that, on average, are more than double those in North America. The UK also offers among the most aggressive renewable energy objectives and incentives in the world. For large capacity facilities utilizing imported white-wood pellets as fuel, the price of woody biomass may be as high as $150 per tonne7. Community-scale projects, such as those proposed by Nexterra, can use locally-sourced construction and demolition waste which is available at significantly lower costs ($0 - $40/tonne) than pellets, and are available in quantities ranging from 13,000 - 85,000 tonnes per annum. To utilize these feedstocks, however, systems need to be able to meet strict emission levels, similar to those implemented at the UBC facility.

In the UK, gasification technologies, such as the one implemented at UBC, qualify as Advanced Conversion Technology (ACT) under the UK Department of Energy and Climate Change regulations. ACT technologies qualify for the highest band of Renewable Obligation Certificates (ROCs) and the newly adopted Contract for Differences. This gives the technology a distinct advantage over conventional combustion technologies. Under the current ROC regime, a qualifying gasification system would receive incentives and PPAs equal to CDN $0.22 - $0.26/kWh. Systems incorporating CHP could also qualify for the Renewable Heat Incentive which would equate to £0.04/kWh, equal to approximately CDN $13/MMBtu, plus the value of the natural gas. (Note: under the regulations, any carbon offsets are owned by the utilities purchasing the renewable attributes.)

5 Jeuck, J. & Duncan, D. (2009). NCSU. Economics of harvesting woody biomass in North Carolina. 6 North Carolina Utilities Commission website, Renewable Energy and Energy Efficiency Portfolio Standard (REPS), accessed March 5, 2013, http://www.ncuc.commerce.state.nc.us/reps/reps.htm 7 Biomass Energy Centre. (2008-2011). Retreived from: http://www.biomassenergycentre.org.uk/portal/page?_pageid=75,59188&_dad=portal&_schema=PORTAL

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2.2.5 LOCATION SENSITIVITY FACTORS AND OUTCOMES

It is clear that the financial viability of locating a CHP facility in a jurisdiction is highly sensitive to fossil fuel and power and woody biomass prices associated with that jurisdiction. The optimal project economics are in communities that are currently operating on diesel or fuel oil (e.g. Case 2). The second best market opportunity appears to be in the United Kingdom (e.g. Case 4). When modelled, both of these markets generate positive Net Present Values (NPVs) over 20 years. For North Carolina (Case 3) and British Columbia (Case 1), the projects are more challenging due to the comparatively low cost of natural gas and low power prices in those locations.

The ultimate NPV of the project will also depend on capital costs. In the remote community scenario (Case 2), a project could bear a capital cost of up to $10 million per MWh and still generate a positive NPV. In the United Kingdom scenario, a system’s capital threshold is in the range of $6-7 million per MWh installed.

3.0 Recommendations and Conclusion3.1 GENERAL CONSIDERATIONSGiven the demonstration of the BRDF technology at UBC, a number of key considerations should be taken into account when considering replicating this type of CHP technology:

1. Sources of funding. Depending on the size of the installation, a project similar to the BRDF will be characterized by a significant capital investment up-front, while realization of savings will depend on the system’s annual performance. The initial capital investment will likely come from a number of public and private sources.

2. Fuel accessibility. Jurisdictions must have continuous access to an acceptable fuel source, (volume, quality, price, transportation plan, etc.)

3. Grid connectivity. Any application considering operating a woody biomass CHP system to its maximum efficiency in cogeneration mode will require access to both a thermal grid and the local power grid.

4. Facility space and building requirements. For a 2 MWh application, the BRDF carries a small footprint of approximately 1800 square metres. Additional space consideration should be allowed for non-core components, such as back-up energy facilities or air monitoring equipment.

5. Social license. Jurisdictions must realize the social license of the community prior to building and operating a woody biomass CHP. In industrial applications, this may be achieved by simply complying with relevant operating regulations. However, locating a woody biomass CHP system in a mixed-use or urban zoned community will also require the acceptance of the technology and its operation by the local community.

6. LDA. Commercial benefits can be achieved in locations where utilities are willing to offer an LDA in support of local generation of electrical power.

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3.2 APPLICATION-SPECIFIC CONSIDERATIONSHaving evaluated the general considerations for a viable bioenergy CHP system, a number of application-specific factors associated with the economic, environmental and social environment will further determine the feasibility of replication.

1. Power prices. A project using a similar system as the BRDF would be most beneficial in areas where there are medium to high power prices (often indexed to elevated natural gas prices). To maximize the commercial competitiveness of woody biomass, as compared to traditional fossil fuel, the project would be most viable in jurisdictions that are dependent on fossil fuels such as natural gas or diesel fuel.

2. Woody biomass fuel cost. Jurisdictions that control their own woody biomass may realize savings through lower fuel procurement and transportation costs.

3. Emissions standards. Local emissions standards will need to be met or bettered for any project to obtain the social license required to build and operate a CHP facility.

4. Emission targets. Emission reduction targets that are supported by policy, legislation or incentives like those created by British Columbia’s carbon neutral government mandate, further strengthen the economic benefits of woody biomass-based power generation. Explicit carbon prices and GHG reduction requirements will be an important component of the business case for any application.

5. Renewable Energy Portfolio Standard. The business case for this type of facility is further enhanced by the existence of REPS, which drive demand for the energy produced. The energy is either sold directly into the grid, or into a secondary market in the form of a REC. In both cases, the purchase price is most often offered at a premium compared to what would otherwise be paid for fossil fuel-generated power.

6. Beyond the Business Case. The replication of the woody biomass CHP system, as with the adoption of all new technology, requires the jurisdiction to take on additional risk and uncertainty, which are difficult to quantify. At UBC, these risks were balanced against the environmental and teaching and learning benefits represented by the project.

3.3 RISK CONSIDERATIONSIn addition to the application-specific conditions identified, a number of risks will be assumed by the owner of a similar facility, including:

1. Construction risk. A detailed site analysis must be undertaken to identify any costs that may result from underlying geotechnical or remedial requirements.

2. Financing risk. Due to the technology’s early stage of maturity, projects undertaken should have a reasonable, if not slightly higher, allowance made for contingencies. Due consideration should be exercised for the possibility that promised funds may not materialize. Also, CHP projects should consider the impact of potential construction and commissioning over-runs. Schedule or cost over-runs may place a burden on project cash flows or the funding partners’ payment schedules.

3. Technology risk. Unscheduled downtime, during the first year of operation, to allow work on improving and optimizing the technology, should be anticipated.

4. Operating risk. Consistency of the fuel supply is a necessary factor in the reliable operation of the technology. Incentive and penalty schemes must be in place with the woody biomass fuel supplier to ensure that fuel specifications are met.

5. Performance risk. Once operational, the BRDF has largely performed as expected. Future applications should be aware of the potential for a facility to perform at levels below which the specifications suggest.

6. Demand risk. This was not a consideration for the BRDF, but may be for applications that could take the form of a municipal utility.

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7. Price risk. Maturing of the technology, and the development of similar systems, should result in a reduction in the capital cost of these types of systems. Nexterra, for example, anticipates an internal 20% cost reduction depending on further system development over the next 5-10 years8.

8. Energy price risk. The economic viability of these projects is highly sensitive to the cost of the fossil fuel displaced. There is, therefore, a risk that the commodity price is meaningfully different (higher or lower) than the forecasted commodity price once the plant is operational – impacting the actual/realized economics of the project.

3.4 CONCLUSIONWhen four application scenarios are analyzed, the most compelling application for CHP is when it is can successfully substitute woody biomass for diesel as the fuel supply. The second most compelling application is where woody biomass fuel replaces fossil fuel AND there are significant financial incentives for the use of the technology. The UK represents a market with strong incentives and high energy costs. Nexterra is currently developing this market having sold their initial project in the UK in December 2013. For the partners in the UK, the UBC project was a useful proxy for using woody biomass to produce power.

The BRDF provides a tangible “reference site” for the CHP technology with the majority of the project’s objectives having been achieved. UBC and its technology partner, Nexterra, will continue to develop, test and evaluate this technology to broaden its applicability to global-market opportunities.

8 Nexterra. (2012 August). Draft. Nexterra Gasification - IC Engine Overview

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