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C&B Farms Biomass Heating Project

Greenhouse Gas Emissions Reduction

Report

For the Period: 1 January, 2016 – 31 December, 2016

FINAL REPORT

1 May 2017

Prepared by: Blue Source Canada ULC (Authorized Project Contact) Suite 700, 717-7th Avenue SW Calgary, Alberta T2P 3R5 T: (403) 262-3026 F: (403) 269-3024 www.bluesourceCAN.com

Prepared for: C&B Farms Inc.

327 Essex Road 18 Leamington, ON, N8H 3V5

Phone: (519) 322-2772 Fax: (519) 322-2576

http://www.bluesourcecan.com/

Page ii

Prepared by: Blue Source Canada ULC 700, 717 7th Ave. SW, Calgary, AB, T2P 0Z3 Tel:(403) 262-3026 Fax:(403) 269-3024

Contents Contents ........................................................................................................................................................ ii

List of Figures ............................................................................................................................................... iii

List of Tables ................................................................................................................................................ iv

List of Abbreviations .................................................................................................................................... iv

1 PROJECT SCOPE AND PROJECT DESCRIPTION ....................................................................................... 1

1.1 Introduction .................................................................................................................................. 2

1.2 Conditions prior to project initiation ............................................................................................ 4

1.3 Description of how the project will achieve GHG emission reductions/ removals ...................... 5

1.4 Project eligibility ........................................................................................................................... 5

1.4.1 Flexibility mechanisms .......................................................................................................... 6

1.4.2 Other Methodology Changes ................................................................................................ 6

1.5 Project technologies, products, services and the expected level of activity ................................ 9

1.6 Identification of risks................................................................................................................... 10

1.7 Roles and responsibilities............................................................................................................ 10

1.8 Reporting Period ......................................................................................................................... 11

1.9 Summary Environmental Impact Assessment ............................................................................ 11

1.10 Stakeholder Consultations .......................................................................................................... 11

1.11 Project History ............................................................................................................................ 11

2 REVIEW OF PROJECT CONSISTENCY WITH ISO14064-2 PRINCIPLES ................................................... 11

2.1 Relevance .................................................................................................................................... 11

2.2 Completeness .............................................................................................................................. 12

2.3 Consistency ................................................................................................................................. 12

2.4 Accuracy ...................................................................................................................................... 13

2.5 Transparency ............................................................................................................................... 13

2.6 Conservativeness ........................................................................................................................ 13

3 INVENTORY OF SOURCES AND SINKS .................................................................................................. 13

3.1 Quantification of estimated GHG emissions/removals .............................................................. 14

3.1.1 Justification for excluding sources and sinks ...................................................................... 14

3.1.2 Quantification of source and sinks ...................................................................................... 16

3.1.3 List of Assumptions ............................................................................................................. 25

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3.2 Estimate of total GHG emission reductions/removals enhancements attributable for the

project 29

4 IDENTIFICATION OF BASELINE ............................................................................................................ 30

5 QUANTIFICATION PLAN ...................................................................................................................... 31

5.1 Baseline Emissions Quantification Methodology ....................................................................... 31

5.2 Project Emissions Quantification Methodology ......................................................................... 34

6 MONITORING PLAN............................................................................................................................. 35

7 DATA INFORMATION MANAGEMENT SYSTEM AND RECORDS .......................................................... 37

7.1 Data Management and QA/QC at C&B Farms ............................................................................ 37

7.2 Data Management and QA/QC at Blue Source ........................................................................... 38

7.2.1 Back-up Procedures at Blue Source .................................................................................... 39

7.2.2 Document Retention Policy at Blue Source ........................................................................ 39

8 GREENHOUSE GAS ASSERTION ........................................................................................................... 39

9 PROJECT PERFORMANCE .................................................................................................................... 41

10 REPORTING AND VERIFICATION DETAILS ....................................................................................... 42

11 STATEMENT OF SENIOR REVIEW .................................................................................................... 43

12 WORKS CITED .................................................................................................................................. 44

Appendix A – IT Backup Procedure for Blue Source ................................................................................... 45

Appendix B – Data Retention Policy at Blue Source ................................................................................... 46

List of Figures FIGURE 1: AERIAL PHOTOGRAPH OF C&B FARMS LTD. ................................................................................................. 3

FIGURE 2: UNIQUE SITE IDENTIFICATION OF C&B FARMS LTD., AND PROXIMITY TO THE TOWN OF LEAMINGTON ... 4

FIGURE 3: PRE-PROJECT AND PROJECT CONDITION BIOMASS USE CONFIGURATION ................................................. 5

FIGURE 4: 4.5 MW VYNCKE BOILER ............................................................................................................................. 10

FIGURE 5: SIMPLIFIED PFD OF SOURCES AND SINKS, POST-PROJECT, (ALBERTA ENVIRONMENT, SEPTEMBER 2007)

............................................................................................................................................................................ 14

FIGURE 6: DATA FLOW FROM SUPPLIERS TO C&B FARMS AND TO BLUE SOURCE ..................................................... 38

FIGURE 7: HISTORIC OFFSET PROJECT PERFORMANCE ............................................................................................... 39

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List of Tables TABLE 1: JUSTIFICATION OF SSRS EXCLUDED FROM QUANTIFICATION ...................................................................... 15

TABLE 2: INCLUSION AND EXCLUSION OF SOURCES, SINKS AND REMOVALS OF GHG EMISSIONS, EXTRACTED FROM

THE PROTOCOL ................................................................................................................................................... 16

TABLE 3: EMISSION FACTORS USED FOR THE PROJECT ............................................................................................... 20

TABLE 4: 100YR GLOBAL WARMING POTENTIAL, 2007 IPCC 4TH ASSESSMENT REPORT ............................................. 21

TABLE 5: LANDFILL DESIGN PROPERTIES ..................................................................................................................... 21

TABLE 6: GREENHOUSE OPERATING PARAMETERS AND FUEL ENERGY CONTENT ..................................................... 23

TABLE 7: ENERGY CONTENT OF NATURAL GAS CONSUMED BY C & B FARMS IN 2016 .............................................. 25

TABLE 8: BIOMASS HEATING VALUES FROM ECOSTRAT ............................................................................................. 25

TABLE 9: LIST OF ASSUMPTIONS.................................................................................................................................. 25

TABLE 10: OFFSET TONNES ACHIEVED TO CURRENT REPORTING PERIOD (2006 – 2016) AND ANTICIPATED PER YEAR

THEREAFTER (ITALICIZED) ................................................................................................................................... 29

TABLE 11: BARRIERS ASSESSMENT OF ALTERNATIVE BASELINE SCENARIOS .............................................................. 30

TABLE 12: DATA MONITORING AND COLLECTION ...................................................................................................... 34

TABLE 13: METER MAINTENANCE AND CALIBRATION ................................................................................................ 35

TABLE 14: 2016 VERR SUMMARY ................................................................................................................................ 40

List of Abbreviations Blue Source Blue Source Canada ULC

CH4 Methane

CO2 Carbon Dioxide

CO2e Carbon Dioxide-equivalent

GHG Greenhouse gas

GWP Global Warming Potential

HFC Hydrofluorocarbon(s)

hp horsepower

MW Megawatt

NIR National Inventory Report

N2O Nitrous Oxide

PFC Perfluorocarbon(s)

SF6 Sulphur Hexafluoride

SGER Specified Gas Emitters Regulation

SS Sources and Sinks

VERRs Verified Emission Reductions/Removals


1 PROJECT SCOPE AND PROJECT DESCRIPTION The project title is: C&B Farms Biomass Heating Project

The project’s purpose(s) and objective(s) are:

The Biomass Heating Project’s purpose is to reduce both GHG emissions and energy costs associated with the purchase and combustion of natural gas used to provide the heat load for the C&B greenhouse. This objective is achieved by supplementing the natural gas with woodchip biomass diverted from landfill. Primary reductions are achieved through the substitution of the equivalent volume of fossil fuels that would have otherwise been combusted and secondary avoidance of methane generated through the landfill gas that would have been produced through the anaerobic degradation of the wood waste.

Date when the project began:

The project began October 11, 2006.

Expected lifetime of the project:

The biomass boiler is anticipated to operate for a minimum period of 15 years.

Credit start date: October 20, 2006

Credit duration period:

October 20, 2006 - October 20, 2021

Estimated emissions reductions:

The current reporting period generated 4,320 tonnes CO2e. The total project emission reductions from this project are estimated to be approximately 77,265 tonnes of CO2e as follows (current reporting period in bold text) 1:

Year Emission Reduction (t CO2e)

10/20/2006 – 12/31/2006 3,326

2007 4,578

2008 4,918

2009 4,542

2010 4,444

2011 4,690

2012 4,452

2013 5,452

2014 7,111

2015 5,585

2016 4,320

2017 4,969

2018 4,969

2019 4,969

2020 4,969

01/01/2021 – 10/20/2021 3,970

TOTAL 77,265

Applicable Quantification Protocol(s):

The quantification protocol used is the Alberta Environment Specified Gas Emitters Regulation: “Quantification Protocol for Diversion of Biomass to Energy from Biomass Combustion Facilities”, version 1, September 2007.

1 Annual emission reductions presented in italics are projected reductions based upon historic performance.


Protocol(s) Justification:

For transparency, note that version 2.0 of this Protocol was approved by Alberta Environment and Sustainable Resource Development in April 2014. However, this project will continue to use version 1.0 of the Protocol.

Other Environmental Attributes:

The project is not generating any other environmental attributes, credits or benefits such as Renewable Energy Certificates.

Unique latitude and longitude:

The Project is located in Leamington, Ontario Canada at 327 Essex Road 18, N8H 3V5. Latitude, Longitude: 42°04'22.5"N, 82°37'27.6"W

Ownership: This Project is wholly owned and operated by C&B Farms Ltd.

Reporting details:

The first reporting period covered October 20, 2006 to December 31, 2011. The second project reporting period covered 2012 and 2013. Going forward it is anticipated that the Project Reporting periods will occur annually. This report includes the tonnes of CO2e reductions from January 1, 2016, to December 31, 2016.

Verification details:

The verifier, Brightspot Climate, is an independent third-party that meets the requirements outlined in accordance with ISO 14064-3. An acceptable verification standard (e.g. ISO 14064-3) was used and the verifier vetted to ensure technical competence with this project type.

1.1 Introduction The C & B Farms Biomass Heating Project (‘the Project’) is a biomass energy generation project located

near the town of Leamington, Ontario. The Project is owned and operated by C & B farms: a large

commercial greenhouse operation that consists of 14.2 acres of covered greenhouse area (see Figure 1

and Figure 2).

The opportunity for generating carbon offsets with this protocol arises mainly from:

1) indirect GHG emission reductions through the use of biomass to offset non-renewable thermal

energy production; and

2) from direct GHG emission reductions due to the avoidance of methane emissions from the

decomposition of organic wood wastes in landfills.

Methane is a powerful GHG with a 100-year global warming potential 25 times that of carbon dioxide

and is passively emitted from the disposal of waste biomass in landfills or other oxygen-free conditions

where the biomass undergoes anaerobic decomposition. The diversion of biomass away from an

anaerobic storage site, such as a landfill, to a combustion facility avoids the formation of methane

gas. As a result, the activity reduces anthropogenic GHG emissions from the use of biomass for

thermal energy generation in place of fossil fuels used in previous years.


C&B Farms grows miniature bell pepper and sweet point pepper varieties. Planting operations began in

December (2015) and harvesting started in April and continued through to November. Since the farm

operates year-round in a cold climate, there is a high heating demand that was initially met with oil-fired

boilers that burned Bunker C fuel (fuel oil #6), that were also equipped to burn natural gas.

Due to the high costs associated with burning fossil fuels for heating, C&B Farms investigated the use of

biomass for heat. They found local suppliers of woodchips from various industrial sources that would have

otherwise been destined for disposal at a municipal landfill. C&B Farms thus installed a new biomass boiler

to provide an alternate heat source to the greenhouse operations. However, as CO2 is still required for

optimum plant growth, the natural gas fired boilers remain in operation. Often during winter when

heating demands are high, the biomass will provide the primary heat supply to the greenhouses. In the

summertime months, when heating is required only during cooler summer days and nights, the natural

gas boilers provide 95%-100% of the energy demand to ensure the ideal CO2 concentration is maintained

for optimum vegetative growth and yields.

Serialized Verified Emission Reductions/Removals (VERRs) are generated by this project by the

displacement of fossil fuels with biomass that would have otherwise been burned to supply the

greenhouse heat load.

Figure 1: Aerial photograph of C&B Farms Ltd.


Figure 2: Unique site identification of C&B Farms Ltd., and proximity to the Town of Leamington

1.2 Conditions prior to project initiation Prior to the start-up of the biomass combustion boiler at the C&B Farms site, all of the heat requirements

for the greenhouses were produced by natural gas and fuel oil combustion in one or more of four existing

boilers at the site. The boilers are rated at 2 x 200hp, 800hp and 700hp. One 200hp boiler and the 700hp

boiler have the capability of burning fuel oil as a means of flexibility when natural gas prices are high. The

greenhouse operation requires a source of CO2 to enhance plant growth, which means that fuel oil could

not be used as the sole source of heating unless a separate liquid CO2 system were put in place. An existing

hot water distribution system was in place to distribute hot water from each boiler to different parts of

the greenhouses through pipes along the ground near the pepper plants to keep the plants warm

throughout the year. An above ground steam distribution system is connected to three of the boilers as a

back-up heating source that is only used during the coldest months of the year or for melting snow off the

greenhouses.

The biomass used by the project would have previously been sent for disposal to landfill without the

creation of a market for biomass as a fuel, which is in part due to the third-party biomass supplier and end

users such as C&B Farms. The creation of a market for biomass has led operators of waste sorting facilities

and wood waste processing facilities to separate clean biomass materials for sale to third party suppliers

who then distribute the biomass fuel to end users.

As such, had the Project not been initiated by C&B Farms, the biomass would have decomposed

anaerobically in a landfill to form methane emissions. Additionally, the thermal energy produced by

biomass combustion in this project would have been produced by natural gas and fuel oil combustion.


Therefore, the baseline condition is the anaerobic decomposition of that portion of biomass which has

been diverted from landfill and transported to C&B Farms, and the generation of an equivalent quantity

of thermal energy from fossil fuel combustion.

Figure 3 below illustrates the biomass waste uses before and after the implementation of the Project.

Figure 3: Pre-project and Project condition biomass use configuration

1.3 Description of how the project will achieve GHG emission reductions/

removals The Project results in a reduction in greenhouse gas emissions through:

a. The use of a less carbon intensive fuel (biomass) than would have been used in the baseline to

generate an equivalent quantity of thermal energy;

b. The avoidance of methane generated from anaerobic decomposition of the wood waste at a

landfill.

Currently, the biomass is supplied mainly by Ecostrat, in the form of small diameter woodchips. These

were produced from construction and demolition wood waste that was originally diverted from landfill.

Had C&B Farms not provided a market value for this biomass it would not have been diverted from landfill

and would have undergone anaerobic decomposition. Additional woodchips were obtained from Essex

County Feedlots (7 loads) when the farm needed a quick delivery of biomass on top of their usual order

from Ecostrat. Credit for this portion is therefore gained as a result of the direct avoidance of anaerobic

decomposition of biomass to form methane.

1.4 Project eligibility The project is eligible to create emission reductions as follows:

✓ The GHG emission reduction assertion was quantified using a quantification methodology

considered to be industry best practice guidance (Alberta Environment, September 2007);

Municipal

Wood Waste

Landfill

Anaerobic Decomposition

Pre-Project Condition

Municipal

Wood Waste

Sorting and

diversion of

wood

Project Condition

Third Party

delivery of

wood for fuel

Wood burned

in C&B boilers

for heating

Combustion


✓ The quantification protocol referenced was developed in accordance with the ISO 14064-2

standard, as required by the GHG CleanProjects® Registry;

✓ The GHG assertion has been verified by an independent third-party;

✓ The facility is not subject to any regulations requiring the use of biomass or prohibiting the

combustion of natural gas, fuel oil, or coal for thermal energy generation in Ontario;

✓ The project is not currently subject to any climate change or emissions management legislation in

the province of Ontario or Federally in Canada;

✓ Potential GHG emission reductions generated by this project are not listed on any other GHG

reduction registry in Canada or internationally;

✓ The project has not received any public funds in exchange for GHG emission reductions (e.g.

offsets) resulting from this project; and

✓ All environmental attributes generated by the project, including any GHG emission reduction

benefits, are owned solely by C&B Farms Ltd.

While Ontario has passed legislation requiring the collection and use of landfill gas for all new landfills

and landfills exceeding the size of 1.5 million cubic meters, this does not impact the eligibility of

project to generate offset credits, as the activity of combustion of diverted landfill waste still remains

unregulated2. However, this regulation does apply to the baseline emission source as the landfill gas

could be required to be captured and collected. The landfill parameters for the waste sourced in

Ontario have been modified to reflect the possibility of the waste diversion sourcing from one of these

regulated landfills.

1.4.1 Flexibility mechanisms

No flexibility mechanisms were used in the quantification methodology.

1.4.2 Other Methodology Changes

Highlighted below are the variances and, or modifications made during the previous reporting period:

i) Updated Global Warming Potentials:

In 2014 the 100-year global warming potentials were updated to reflect the latest published

values used in the National Inventory Report. This impacted the GHG assertion significantly

due to the increase in the 100-year methane GWP and the sensitivity of the avoided methane

from landfilling.

ii) Greenhouse Operation Expansion

For the 2012 reporting year and onward, C&B Farms underwent an expansion of an addition

5 acres of glass greenhouse space used for growing additional pepper varieties. However, the

frequency and duration of use of the biomass boiler remains unaffected by this addition, as it

was already at its maximum intended operation prior to the expansion. Combining this factor

2 Ministry of the Environment and Climate Change, Ontario Regulation 232/98 and Revised Regulations of Ontario 1990, Regulation 347 (General Waste Management) under the Environmental Protection Act.


with the direct substitution of greenhouse gas savings between project biomass combustion

and baseline fossil fuel combustion, no methodology changes were required.

iii) Scholl-Canyon Model Adoption

For the 2015 greenhouse quantification, the landfill avoidance methodology was updated to

align with current best practices in greenhouse gas accounting and the latest calculation

methodology accepted by the Alberta Emission Offset Registry. This method employs the

first order decay Scholl-Canyon Model.

iv) SS P9 – Emissions from Biomass Transfer

Also in 2015, the electricity usage used on site to convey the biomass from the receiving

area to the boiler was included in the GHG quantification.

The following variances, or modifications, were made during the 2016 vintage year reporting period:

v) Updated Emission Factors

Emission factors and sources were updated from the Carbon Emission Offsets Handbook to

Part 2 of the National Inventory Report (NIR) 1990-2014: Greenhouse Gas Sources and Sinks

in Canada published by Environment Canada (2016) 3 to obtain factors and data more

applicable to Ontario, where available.

vi) Adjusted Baseline Scenario to 100% Natural Gas Displacement

In previous reporting periods, the baseline scenario included burning fossil fuels to heat the

greenhouse using both fuel oil (64% of the time) and natural gas (the remaining 36% of the

time). However, as the greenhouse entered a non-interruptible natural gas contract, they

cannot be forced to switch to fuel oil. In addition, due to the significantly higher cost of fuel

oil compared to natural gas and the need to generate CO2 from the natural gas to support

plant growth, the proportion of fuel use in the absence of the project would be very minimal.

Finally, the project proponent confirmed that fuel oil would only be used if necessary as back-

up to natural gas. For these reasons, the baseline has been adjusted to included only natural

gas displacement, rather than a proportion of each fuel. This selection is consistent with ISO

14064-2 principle of conservativeness.

vii) SS B9&10 – Baseline Emissions from Decomposition of Biomass and Methane Collection and

Destruction

In the past, only one ash content lab analysis value was available – 1.13% for waste identifier

“G.” As a result, the value was applied to all biomass types and assumed to be representative

for the other waste IDs. As the majority of samples for this reporting period have distinct ash

3 Environment and Climate Change Canada (2016). National Inventory Report 1990-2014: Greenhouse Gas Sources and Sinks in Canada. Canada’s Submission the United Nations Framework Convention on Climate Change – Part 2.


content, the values were applied to their respective waste ID for a more accurate calculation

of the methane that would have been generated from the biomass (less ash) sent to landfill.

Waste types “K” and “S” did not have ash content within the lab results; however, as the two

have the same description and similar btu values to “G” (see Table 8), the ash content was

assumed to be representative of all three wastes.

viii) SS B9&10 – Baseline Emissions from Decomposition of Biomass and Methane Collection and

Destruction

The fraction of degradable organic carbon (DOCf) was changed from 0.5 listed in the

Handbook and used in previous years to 0.6. The 2016 NIR report selected the higher value

from the IPCC (2006) range 0.5-0.6 as it better represented Canadian wood waste diversion

practices regarding woods that contain high proportions of lignite4. This change can be noted

under MSW Landfills (pg. 156) in Annex 3 of the NIR part 2.

ix) SSB9&10 - Baseline Emissions from Decomposition of Biomass and Methane Collection and

Destruction

The rate of decay – ‘k’ – formula was updated from the one listed in the Protocol, as: k=

0.00003 x PCPN +0.01, to the relationship used in the 2016 NIR Part 2 report by Environment

Canada. The new formula, k = 0.00007 x PCPN - 0.0172, uses a relationship prepared by the

Research Triangle Institute (RTI) for the U.S Environmental Protection Agency, and was

applied to annual average precipitation data for each of the provinces. Therefore, this

relationship and the subsequent information provided by the NIR more accurately portrays

the k values present in Ontario, as compared to the Protocol developed for Alberta users.

The formula was also applied to the Michigan annual average precipitation due to the fact

that the RTI relationship was developed in the U.S for the EPA based on U.S waste

composition.

x) SS B12 – Baseline Emissions from Thermal Energy Produced

The value associated with the natural gas energy content (high heating value, HHV) was

derived from Union Online to obtain monthly heat values for the “South” delivery area –

containing C & B Farms. In previous reporting periods, a standard high heating value (HHV)

provided by Union Gas for a standard gas composition was used. Using the monthly values

provided for 2016 natural gas consumption adheres to the ISO 14064-2 principle of accuracy.

xi) SS B13 – Baseline Emissions from Fuel Extraction and Processing

In previous reporting periods, the baseline emissions for fuel oil extraction and processing

were calculated using an emission factor in tonnes of CO2e, rather than for each greenhouse

gas separately – CO2, CH4, and N2O. As emissions are calculated individually for natural gas

4 Ibid. Annex 3, Pages 156-157.


extraction and processing, the same methodology was applied to fuel oil, to maintain both

quantification consistency and accuracy in the emission volume generated.

xii) SS P9 – Emissions from Biomass Transfer

In the past, biomass boiler runtime was estimated based on the planting schedule of crops in

the greenhouse. However, this assumption is not always indicative of the biomass boiler

running to meet heating demands. For this reporting period, the boiler runtime was estimated

based on conversation with the greenhouse owner and biomass delivery dates. Most

greenhouses turn off the biomass boiler in the summer time (June through September), due

to low heating demand, and use the fossil fuel boiler to supply plants with CO2 and the small

heat load. This method is directly related to the ISO 14064-2 principle of accuracy.

Lastly, it should be noted that C & B Farms experienced an abnormal growing season due to a foreign pest

infestation that targeted pepper crops. As a result, the crop was lost in early October. The biomass boilers

did not run in October or November due to this occurrence.

1.5 Project technologies, products, services and the expected level of activity The Project consists of the generation of thermal energy through a 4.5 MW Vyncke biomass boiler. The

thermal energy generation system consists of one biomass combustion boiler with a rated capacity of

4.5MW and associated piping for distribution of hot water throughout the greenhouses to provide heat

to the pepper plants throughout the year. The boiler is equipped with a multi-stage cyclone to capture

particulate matter (fly ash) from the combustion exhaust.

Biomass is delivered to C&B Farms from one primary biomass fuel supplier for just-in-time delivery of fuel

during the heating season - Ecostrat. Two additional biomass suppliers are utilized when required;

however, only Ecostrat supplied biomass for the 2016 reporting period. Biomass is unloaded directly into

the covered storage hopper that feeds the boiler via a conveyor belt so additional transportation of

biomass in not required. The biomass is burned as received and no additional drying, grinding or

processing of the biomass takes place at the C&B Farms site. The covered storage silo can hold

approximately one week’s worth of biomass.

Figure 4 shows the 4.5 MW Vyncke biomass boiler installed at C&B Farms.


Figure 4: 4.5 MW Vyncke Boiler

1.6 Identification of risks The identification and analysis of risks associated with the quantification of GHG emission reductions from

this project has been completed by the third-party verifier. The generation of thermal energy using

biomass in place of fossil fuels results in a permanent GHG emission reduction since the fossil fuel

displacement cannot be reversed. This project type does not involve biological or geological

sequestration-related risks.

1.7 Roles and responsibilities

Project Developer Contact Information

C&B Farms Ltd. Contact: Brady Tiessen Phone: (519) 322-2772 Fax: (519) 322-2576 Email: [email protected]

327 Essex Road 18, Leamington, ON, N8H 3V5, Canada

Authorized Project Contact

Blue Source Canada ULC Kelsey Lank, AIT. Carbon Solutions Analyst Phone: 403-262-3026 x228 Fax: 403-269-3024 Email: [email protected]

Suite 700 717 - 7th Avenue SW Calgary, AB, T2P 0Z3 Canada Web: www.bluesourcecan.com

Verifier

BrightSpot Climate Aaron Schroeder, P.ENG Principal Phone: 604-353-0264

225 West 8th Avenue, Vancouver BC V5Y 1N3 Web: www.brightspot.co

mailto:[email protected]


http://www.bluesourcecan.com/

http://www.brightspot.co/


Email: [email protected]

1.8 Reporting Period For the purposes of this project report, the carbon dioxide equivalent VERRs are claimed for activities

from January 1, 2016 to December 31, 2016.

1.9 Summary Environmental Impact Assessment An environmental impact assessment was not required for this Project.

1.10 Stakeholder Consultations Stakeholder consultations were not required for this Project. The Alberta Offset System Biomass

Quantification Protocol used to quantify VERRs from the Project was developed following a transparent

consultation process with industry stakeholders to ensure the relevance, accuracy, conservativeness,

consistency, and transparency of the protocol.

1.11 Project History The following provides a chronological history of the project to date:

• Prior to the project (Pre-October 2006): Prior to the implementation of the project, all of the

heating requirements for the greenhouses at C&B Farms were met with fossil fuels. There were

two 200-hp, one 800-hp and one 700-hp natural-gas-fired boilers. One of the 200-hp boilers

and the 700-hp boiler had the capability of burning fuel oil.

• October 2006: Onsite construction of a 4.5 MW Vynke biomass boiler and all associated

equipment and feedstock is completed.

• October 11, 2006: The new 4.5 MW Vynke biomass boiler is fully commissioned.

• 2010: Additional 5-acre glass greenhouse under construction.

• January 20, 2011: Planting and heating of glass greenhouse begins.

• 2012: Additional 5-acre glass greenhouse is operational.

2 REVIEW OF PROJECT CONSISTENCY WITH ISO14064-2 PRINCIPLES

2.1 Relevance The methodology referenced in quantifying GHG emission reductions from the C&B Farms Biomass

Heating Project (herein in referred to as “the Project”) was developed and approved under the Alberta

Offset System, regulated under the Province’s “Climate Change and Emissions Management Act.” The

Alberta Offset System Quantification Protocol for Diversion of Biomass to Energy from Biomass

Combustion Facilities,5 (herein in referred to as “the Biomass Protocol”) was developed following the ISO

5 Alberta Quantification Protocol for Diversion of Biomass to Energy from Biomass Combustion Facilities (Version 1, September 2007), http://environment.gov.ab.ca/info/library/7908.pdf


http://environment.gov.ab.ca/info/library/7908.pdf


14064-2 standard as required under the Alberta Offset System protocol development process.

Additionally, the protocol development process included a multi-step stakeholder review process

consisting of a technical expert review, a broader stakeholder review process and a public posting period,

all of which were managed by the Government of Alberta.

This Protocol has since been superseded by the Quantification Protocol for Energy Generation from the

Combustion of Biomass Waste, version 2.0, April 2014. Changes to the Protocol included the following:

- Broadening of scope to include additional sources of biomass waste and baseline disposal

scenarios

- Changes to the quantification methodology for reduction from avoided landfilling

- Updates to the record keeping requirements

Blue Source has chosen to continue to use the Protocol version 1.0 in combination with the published

Handbook of Emission Factors, due to specific impracticalities surrounding the updates made to the

record keeping requirements. Due to the number of sources used by the biomass supplier, and the

likelihood of obtaining records from 2005 and earlier to demonstrate the baseline activity of landfilling

the biomass waste, Blue Source has selected to use the original version of the Protocol, in combination

with regulatory requirements and an affirmation by the biomass supplier to demonstrate landfilling as the

most likely baseline activity. Changes to the record keeping requirements do not impact the quantitative

methodology of the calculation, however, for the updates surrounding the quantification of emissions

from landfilling, Blue Source is updating the methodology to reflect the best practise.

Sources, Sinks and Reservoirs (SSRs) considered to be relevant and included for quantification under the

Biomass Protocol are defined in Section 3 of this document, including justification for the exclusion of

SSRs identified in the life cycle elements of the project and baseline conditions.

2.2 Completeness The specific scope of this project has been limited to GHG emission reductions achieved through the

displacement of fossil fuels through the generation of thermal energy from biomass. Indirect GHG

emission reductions from the diversion of biomass wastes from landfill and the avoidance of the methane

emissions that would have occurred from the anaerobic (oxygen-free) decomposition of these residues in

landfill or stockpile are also quantified under the protocol. The project does not include any electricity

generation and as such, the GHG emissions related to electricity generation have been excluded.

Data collection and monitoring approaches as they pertain to the quantification approaches used in

calculating GHG emission reductions are summarized in Table 12 in this report.

2.3 Consistency The Biomass Protocol used in the quantification of GHG reductions is consistent in its application of

functional equivalence between the baseline and project condition. The unit of functional equivalence is

defined as the GJ of natural gas and GJ of fuel oil displaced by the Vyncke biomass-fired boilers in the

project condition.


For consistency, this project will continue to use version 1.0 of the Protocol. This is in line with the

approach used by Alberta Environment and Sustainable Resource Development for projects registered on

the Alberta Emissions Offset Registry. Under that system, projects are allowed to continue using the

protocol version under which the project was first registered, until the end of their crediting period.

2.4 Accuracy Bias and uncertainties in quantification were limited through the use of utility meter readings (natural gas

consumption) and financially audited data (biomass, fuel oil and coal sales data) in combination with using

the most relevant natural gas higher heating values for the southern Ontario region and up to date

emission factors from Environment Canada.

2.5 Transparency Data collection, monitoring, and quantification approaches are summarized in Table 12 of this report. The

annual emission reduction claims are also summarized in this document to support the transparency of

the GHG emission reduction assertion.

2.6 Conservativeness As discussed in Section 5, calculations are considered conservative for a number of reasons. In order to

conservatively calculate the natural gas and fuel oil savings resulting from the implementation of the

biomass energy generation system, the relative consumption of each fuel was calculated for 2005 which

is the last full year of fossil-fuel consumption prior to the implementation of the biomass heating system.

This ensures that fuel-oil consumption is not overstated, which is important since the emissions from this

fuel are greater than those for natural gas.

3 INVENTORY OF SOURCES AND SINKS The Biomass Protocol contains a list of baseline and project sources and sinks (SSs) that were deemed

applicable for projects developed according to the protocol. The SSs for the project are those inside the

dashed box, as identified in Figure 5.


Figure 5: Simplified PFD of sources and sinks, post-project, (Alberta Environment, September 2007)

3.1 Quantification of estimated GHG emissions/removals The following equations serve as the basis for calculating the emission reductions from the comparison

of the baseline and project conditions as per the Project Protocol:

Emission Reduction = Emissions Baseline – Emissions Project

Emissions Baseline = sum of the emissions under the baseline condition.

Emissions Decomp Biomass = emissions under SSR B9 and B10 Decomposition of Biomass and Methane Collection/Destruction

EmissionsElectricity= emissions under SS B11 Electricity Production

Emissions Thermal Heat = emissions under SSR B12 Thermal Energy Produced.

Emissions Fuel Extraction / Processing = emissions under SSR B13 Fuel Extraction and Processing Emissions Project = sum of the emissions under the project condition.

Emissions Facility Operation = emissions under SSR P6, P8 to P11, P13, P14 and P16 Facility Operation.

Emissions combustion of biomass = emissions under P12 Combustion of Biomass Emissions Fuel Extraction / Processing = emissions under SS P22 Fuel Extraction and Processing

3.1.1 Justification for excluding sources and sinks

The following two SSRs (shown in Table 1) were not applicable to this project and as such were not quantified.


Table 1: Justification of SSRs Excluded from Quantification

Source/Sink Reason for Exclusion

Emissions Electricity = emissions under SSR B11 Electricity Production.

Electricity is not generated from biomass on-site and therefore no electricity displacement occurs in the baseline scenario and this SSR is not relevant to this project.

Emissions Fuel Extraction / Processing = emissions under SSR P22 Fuel Extraction and Processing

No fossil fuels are consumed on site for conducting facility operations. All natural gas consumption at the greenhouses (e.g. when the biomass units are not operating due to downtime) has been netted out in the baseline calculation for SSR B12 and therefore emissions related to fuel extraction and processing are not accounted for in the project condition.

SS P6 Biomass Transfer to Processing System

This emission source is outside of the project boundary as there is no on-site processing of the biomass. Transfer is performed by the biomass supplier.

SSP8 Biomass Processing This emission source is outside of the project boundary as there is no on-site processing of the biomass. Processing is completed off-site by the biomass supplier.

SSP10 Start up of Facility No fossil fuels are consumed to start up the biomass boiler. Biomass combustion is initiated manually by the operator.

SS P11 Facility Operation

Auxiliary systems such as lighting and space heating are deemed negligible for the standalone biomass power facility. As electricity or heating is not separately metered or tracked this source has been excluded.

SSR P13 Air Quality Control

The biomass boilers do come with a cyclone and blower on the boiler exhaust to remove ash and particulates prior to release to atmosphere. However, the fossil fuel boiler in the baseline condition was also equipped with a cyclone system on the exhaust piping due to he ability to combust coal. This source is functionally equivalent.

SS P14 Waste Transfer to Storage Area

The combustion residue (ash) is removed from the combustion box via conveyor system, is watered and placed in temporary collection area on a truck bed. Once full this is transferred to the storage/ ash stockpile area on site and used for miscellaneous landscaping projects on-site.

SS P16 Waste Transfer from Storage Area to Offsite

This emission source is not applicable as the ash is stockpiled on-site for use in miscellaneous projects such as landscaping infill etc.


3.1.2 Quantification of source and sinks

Table 2 below, provides a summary of the SSRs included and excluded from quantification as defined in the Biomass Protocol, (Alberta

Environment, September 2007). It should be noted, that the inclusion/exclusion of SSRs and related justifications are generic and were not

modified for this specific project as the exclusion of SSRs that are not relevant to the project configuration at C&B Farms is previously discussed.

Table 2: Inclusion and Exclusion of Sources, Sinks and Removals of GHG Emissions, extracted from the Protocol

1. Baseline Options 2. Baseline

(C, R, A)

2. Project

(C, R, A)

4. Include or Exclude

from Quantification 5. Justification for Exclusion

Upstream SS’s

P1 Collection of Biomass N/A Related Exclude

Under the majority of project and baseline configurations, the

collection of biomass will be functionally equivalent. These SS’s

may therefore be excluded. B1 Collection of Biomass Related N/A

P2 Storage of Biomass N/A Related

Exclude


storage of biomass will be functionally equivalent. In addition,

under the majority of project configurations, the storage of

biomass under conditions conducive to anaerobic digestion (i.e.

in piles, windrows or in landfill) under the project condition is for

less than six months. The generation of methane from typical

biomass materials over a period of less than 6 months is

considered to be negligible.

B2 Storage of Biomass Related N/A

P3 Processing of Biomass N/A Related

Exclude


processing of biomass will be functionally equivalent and

therefore these SS’s may be excluded. B3 Processing of Biomass Related N/A

P4 Transfer of Biomass N/A Related

Exclude


transfer of biomass will be functionally equivalent and therefore

these SS’s may be excluded. B4 Transfer of Biomass Related N/A

P5 Transport of Biomass N/A Related

Exclude


transport of biomass will be functionally equivalent and

therefore these SS’s may be excluded. B5 Transport of Biomass Related N/A

P22 Fuel Extraction / Processing N/A Related Include N/A



(C, R, A)

2. Project

(C, R, A)



B13 Fuel Extraction / Processing Related N/A Include

P23 Fuel Delivery N/A Related Exclude These SS’s are not relevant to the project as the emissions from

these practices are covered under proposed greenhouse gas

regulations. B14 Fuel Delivery Related N/A Exclude

Onsite SS’s

P7 Storage of Biomass N/A Controlled Exclude

As per the discussion on P2 and B2 Storage of Biomass, the

majority of project configurations limit the storage of biomass

under conditions conducive to anaerobic digestion (i.e. in piles,

windrows or in landfill) to less than six months. The emissions

from the storage under this SS will be similarly minimal and

therefore are excluded. However, this SS may be included as a

flexibility mechanism in cases where extended storage occurs,

i.e. greater than six months.

P6, P8 to P11, P13, P14 and P16

Facility Operation N/A Controlled Include N/A

P12 Combustion of Biomass N/A Controlled Include N/A

P15 Storage of Waste N/A Controlled Exclude

As per the discussion on P2 and B2 Storage of Biomass, the

project proponent can demonstrate that the storage of waste

under conditions conducive to anaerobic digestion (i.e. in piles,

windrows or in landfill) under the project condition was for less

than six months. The waste material is of much smaller volumes

compared to the biomass processed by the facility. Further, it is

rendered essentially inert and would therefore undergo

anaerobic digestion to a lesser extent than the non-combusted

biomass. Therefore, the emissions from the storage of waste

under this SS will be small and therefore may be excluded.

P21 Electricity Usage N/A Controlled Exclude

This SS is not relevant to the project as the emissions from the

electricity consumed at the facility are covered under proposed

greenhouse gas regulations.



(C, R, A)

2. Project

(C, R, A)



B11 Electricity Production Controlled N/A Include N/A

B12 Thermal Energy Production Controlled N/A Include N/A

B6 Transfer of Biomass Controlled N/A Exclude

The greenhouse gas emissions covered under this SS result from

the operation of equipment and machinery at the disposal site

for transferring waste from the transportation containers. The

incremental operation of this equipment to deal with the

biomass is the primary concern. Emissions under this SS

represent incremental emissions under the baseline condition.

Therefore, inclusion of this SS in the calculation increases the

emission reduction claim, so excluding this SS is reasonable.

B8 Disposal of Biomass Controlled N/A Exclude

Excluded as the volume of biomass being disposed of represents

less than 5% of the annual waste disposed of at the disposal

facility under the majority of configurations.

B9 and B10 Decomposition of

Biomass and Methane Collection

/ Destruction

Controlled N/A Include N/A

Downstream SS’s

P17 Transport of Waste N/A Related Exclude

Under the majority of project configurations, the volume of

waste generated is less than 2% of the total biomass processed

at the facility. Further, the distance to the disposal site is

typically less than 50 kilometres, one way. Therefore, for a

typical project the total emissions from transport of waste would

be less than 2 tonnes per year and therefore immaterial.

Therefore, this SS is excluded.

P18 Disposal of Waste N/A Related Exclude

The greenhouse gas emissions covered under this SS result from

the operation of equipment and machinery at the disposal site.

The incremental operation of this equipment to deal with the

biomass is the primary concern. Given the nominal volumes of



(C, R, A)

2. Project

(C, R, A)



material being disposed of as waste, as discussed in P17

Transport of Waste, this SS can be excluded.

P19 and P20 Decomposition of

Waste and Methane Collection /

Destruction

N/A Related Exclude

The waste from energy from biomass facilities is essentially inert

as the non-combustible component of the biomass material. As

such, the disposal of waste in the landfill would not contribute

to methane production, and would have no impact on methane

collection and destruction systems. Therefore, this SS is

excluded.

B7 Beneficial Biomass Use Related N/A Exclude

Excluded as greenhouse gas emissions under the baseline

condition serve only to increase the stated emission reduction.

The emissions under this SS may also be covered under

proposed greenhouse gas regulations.

Other

P24 Development of Site N/A Related Exclude

Energy from biomass facilities are similar in scope to other fossil

fuel power facilities that would be built to provide a similar

power source. Thus, the emissions from development of the site

would be similar.

P25 Building Equipment N/A Related Exclude



power source. Thus, the emissions from building the equipment

for the site would be similar.

P26 Transportation of

Equipment N/A Related Exclude



power source. Thus, the emissions from transportation of

equipment to the site would be similar.



(C, R, A)

2. Project

(C, R, A)



P27 Construction on Site N/A Related Exclude



power source. Thus, the emissions from construction on the site

would be similar.

P28 Testing of Equipment N/A Related Exclude



power source. Thus, the emissions from testing of equipment

would be similar, if not lower due to the biogenic source of the

predominant fuel source.

P29 Site Decommissioning N/A Related Exclude



power source. Thus, the emissions from site decommissioning

would be similar, if not lower due to the lower toxicity of the

facility fuel compared to fossil fuel power facilities.

B15 Development of Site Related N/A Exclude

Excluding emissions from the development of the site for the

baseline scenario represents a conservative approach of

accounting for these emissions.

B16 Building Equipment Related N/A Exclude

Excluding emissions from the building of equipment for the



B17 Transportation of

Equipment Related N/A Exclude

Excluding emissions from the transportation of equipment to

the site for the baseline scenario represents a conservative

approach of accounting for these emissions.

B18 Construction on Site Related N/A Exclude

Excluding emissions from the construction on the site for the



B19 Testing of Equipment Related N/A Exclude

Excluding emissions from the testing of equipment at the site for

the baseline scenario represents a conservative approach of




(C, R, A)

2. Project

(C, R, A)



B20 Site Decommissioning Related N/A Exclude

Excluding emissions from the decommissioning of the site for

the baseline scenario represents a conservative approach of


Table 3 summarizes the emission factors used in the Project.

Table 3: Emission factors used for the Project

Parameter Relevant SS

CO2 Emission Factor

CH4 Emission Factor

N2O Emission Factor

Emission Factor Source

Natural gas combustion

(EFNG) B12 1914.7 g/m3 0.037 g/m3 0.035 g/m3

Chemical engineering formula for CO2 factor, originally derived from CAPP 2003 GHG Report. Environment Canada (2016) NIR Part 2 – Table A6-1 and A6-2, Ontario, Agricultural

Natural Gas Extraction

(NGEX) B13

0.0427 t/e3m3

0.00234 t/e3m3

0.000004 t/e3m3

CAPP (2004) Table 4, Pg.30.

Natural Gas Processing

(NGP) B13

0.0904 t/e3m3

0.00029 t/e3m3

0. 0000032 t/e3m3

CAPP (2004) Table 4, Pg.30.

Biomass Combustion

(EFB,CH4)

(EFB,N2O)

P12 Biogenic, N/A 0.09 g/kg 0.06 g/kg Environment Canada (2016), NIR Part 2 - Table A6-32 Wood Fuel/ Wood Waste

Heavy Fuel Oil Combustion

(EFFO) B12 3156 g/L 0.120 g/L 0.064 g/L

Environment Canada (2016) NIR Part 2 – Table A6-4 HFO Industrial

Heavy Fuel Oil

Extraction/Processing

(EFFO,XP)

B13 0.1381 kg/L 0.0109 kg/L 4.208E-6 kg/L Carbon Offset Emission Factors Handbook (Government of Alberta, March 2015), Table 4


Ontario electricity grid consumption (EFGRID)

P9 50 g/kWh - - (Environment Canada, 2016) Part 3 - Table

A13-7

Table 4 highlights the global warming potentials used for this Project, updated to be consistent with Environment Canada’s 2014 National Inventory Report and the IPCC 4th Assessment Report: Climate Change 2007.

Table 5 and Table 6 summarize the landfill design parameters and greenhouse operating parameters and fossil fuel energy content used in the baseline calculations respectively.

Table 4: 100yr Global Warming Potential, 2007 IPCC 4th Assessment Report

Greenhouse Gas Species: Carbon Dioxide

(CO2) Methane

(CH4) Nitrous Oxide

(N2O)

Global Warming Potential VY 2016 1 25 298

Table 5: Landfill Design Properties

Parameter Methane

Correction Factor

Degradable Organic Carbon

Fraction of DOC Dissimilated

Methane Landfill Gas

Fraction

Fraction of Methane Recovery

Oxidation Factor

Methane Generation

Potential

Annual Precipitation

(mm/yr)

Landfill Decay Rate (yr-1)

Notation MCF DOC DOCf F R Ox Lo PCPN k

Ontario 1 0.21 0.60 0.50 0.663 0.10 0.0840 895.38 k= 7 x 10-5 x PCPN

-0.0172

Michigan 1 0.17 0.50 0.50 0.35 1.0 0.0567 850.14 k= 7 x 10-5 x PCPN

-0.01726

MCF – assigned value of 1.0 as all landfills would have been managed and anaerobic.

6 Environment Canada (2016) National Inventory Report: 1990-2014 Part 2.


DOC – as detailed information about the landfill waste composition is not available, default DOC values were used. The Ontario landfill DOC is

derived from the 2016 NIR report specifically for Ontario, and the Michigan value is the default listed in the Handbook since no specific landfill

data was available.

DOCf – The baseline scenario considers that without the activity of the Project, there would be no demand for the wood waste biomass and no

diversion activity would occur at the landfill. In previous years, the default DOCf value 0.5 listed in the Handbook and matching the NIR report was

used. The value was changed to 0.6 for this report, as the 2016 NIR Part 2 explains that the higher value better represents Canadian wood waste

diversion practices regarding woods that contain high proportions of lignite

F – the fraction of methane in landfill gas production was the default value in the Handbook

R – a value of 0.665 was used for the Ontario waste diversion sources. As Ontario has regulations surrounding landfill gas management for large

landfill, and it is uncertain which landfills the wood waste would have been sent to, the default landfill gas collection and destruction system

efficiency for active, temporary covered cells with a flare system in place was assumed. Ontario regulations include landfill cover design as part of

the new/expanding landfill specifications.7 As Michigan has no regulation regarding landfill gas destruction and does not include a daily landfill

cover as part of the solid waste management regulation, a default value of 0.35 was assumed to be the methane collection efficiency of operating

cells.8

Lo – the Lo value for Ontario was calculated using the given equation, and outlined further in this section. For Michigan, since no information was

available on landfill management the default value assuming no wood waste diversion was in place was employed.

PCPN – the average annual rainfall for the Ontario region was obtained from Environment Canada in the 2016 NIR report, for 1990-2007. Using a

200-km radius around Leamington, the average precipitation for southern Ontario was calculated to be 895.38. Ecostrat identified waste coming

from Michigan to be sourced from Taylor, Michigan. Therefore, the annual average rainfall for the closest community for Romulus was used:

850.14.

7 Environmental Protection Act, Regulation 232/98, section 6(c), xxiv. Source: Ministry of the Environment and Climate Change. (November 2016). Landfill Standards: A guideline on the regulatory and approval requirements for new/expanding land. 8 Michigan Department of Environmental Quality. Natural Resources and Environmental Protection Act, 451 of 1994: Part 115, Sold Waste Management.


k – the landfill decay rate was updated from the Handbook to the one used by Environment Canada in the 2016 NIR. This change is described

above in section 1.7.

Table 6: Greenhouse Operating Parameters and Fuel Energy Content

Emissions Factor

Proportion of Natural Gas*

Biomass Boiler Efficiency

Fossil Fuel Boiler Efficiency Residual Fuel Oil Energy

Content

Reference Site visit observations & project proponent

interview

Natural Resources Canada - Report -

"Combustion Testing at C&B Farms Inc"

Efficiency of Cleaver-Brooks boiler on natural gas = 81-82%, and on #6

oil = 82-83%

Environment Canada NIR 1990 - 2012 Part 2. Table

A4-2

Factor 100% 86% 83%9 42.50 MJ/l

* As mentioned previously, the baseline was adjusted to reflect more accurate and conservative fossil fuel consumption of natural gas in the

baseline condition, changing the proportion of natural gas and fuel oil use to 100% natural gas displacement.

Table 7 summarizes the energy content of natural gas – or the high heating value (HHV) consumed by C & B Farms, obtained from Union Gas for

the “south” delivery area.

Table 7: Energy content of natural gas consumed by C & B Farms in 2016

Parameter Jan Feb March April May June July Aug Sept Oct Nov Dec

HHV (MJ/m3)

39.06 38.98 38.66 38.69 39.17 38.76 38.75 38.62 38.96 39.04 39.11 39.12

Sample project calculations are included in Section 4.0.

Table 8 summarizes the biomass heating values based upon the most recent test results performed by Petro Labs, (April 2017 for E, May 2016 for

K and S, December 2015 for G, and November 2006 for KA).

9 Most conservative value from range.


Table 8: Biomass Heating Values & Description for Ecostrat & Essex County Feedlot/905Wood.com Waste

Material ID

Higher Heating Value,

as received (GJ/tonne)

Moisture Content

(%)

Ash Content

(%) Waste Type

Source Location

Description of Material

Ecostrat - G 18.29 8.10% 1.13% Post-Industrial Toronto, ON Transfer station where wood has been source segregated

Ecostrat - K* 18.24 7.62% 1.13% Post-Industrial Taylor, MI Transfer station where wood has been source segregated

Ecostrat - KA 13.54 29.46% 1.13% Post-Industrial Taylor, MI Pallet operation where scrap wood is processed rather than sent to landfill

Ecostrat - S* 17.45 12.25% 1.13% Post-Industrial Simcoe County, ON

Transfer station where wood has been source segregated

Ecostrat - E 15.66 22.15% 9.71% Post-Industrial Stoney Point, ON

Collection yard for source segregated scrap wood

Essex County Feedlot

“woodchips plus”

16.28 15.0% 3% Construction, demolition,

post-industrial Unknown

Scrap and recycled wood from: pallets, crates, engine blocks/saddles, construction debris, residential wood waste such as fencing etc.

Average 17.45 12.8% 2.85% - - -

Ecostrat does not submit woodchip samples for annual lab testing as they determined results are relatively consistent each year.

* Samples K and S did not include ash content amounts in the lab test results. Due to their btu values being close to that of G, and the

description of waste to be the same for all three, the ash content 1.13% was assumed to be representative of both K and S.

3.1.3 List of Assumptions

The following assumptions were made to complete the quantification:


Table 9: List of Assumptions

10 Email correspondence with Joe Macri with Ecostrat, on March 30th, 2017.

Assumption Description Source/Sink

Impact Justification

Representative

Ash Content for K

and S

Ash content was reported in the lab

tests for all waste types except for K

and S. 1.13% ash content was assumed

to be representative of both K and S

waste IDs.

SS B9&10

The effect of ash production on source B9&B10 is immaterial

due to the efficiency of the boilers and the small relative

portion of ash produced to biomass combusted. As G, K and S

are all described as coming from a “transfer station where

wood has been source segregated,” and have BTU values in the

range of 7500-7865 (Btu/lb) – higher than all other samples –

the ash content for G was assumed to be representative of K

and S as well.

All waste source

in Ontario &

Michigan would

have gone to a

large, regulated

landfill

As the biomass supplier did not

disclose the exact nature of the

landfills, it is difficult to determine

which specific landfill the waste was

sent prior to being diverted by the

supplier. However, Ecostrat did

provide a summary for each source

and confirmed that the waste would

have gone to a large (regulated) landfill

prior to diversion.10

SS B9&10

Without the market for biomass energy combustion, there

would have been no reason to divert wood waste from landfill.

Therefore, it is assumed that the waste would have gone to

regulated landfill in either Ontario or Michigan. This is a

conservative assumption, and also impacts the methane

recovery fraction used below.

Ontario landfill

methane recovery

fraction

The landfill gas recovery fraction was

assumed to be 0.665, for temporarily

covered landfills rather than open or

permanently clay covered landfills (end

of use), as regulated landfills are

SS B9&10

As regulations exist for large landfills, these MSW landfills are

assumed to be comprised of active cells with temporary covers

without wood waste diversion in the baseline and have flare

destruction systems in place for methane recovery. The

regulation does not require a minimum gas capture percent


11 Environmental Protection Act, Regulation 232/98, section 6(c), xxiv. Source: Ministry of the Environment and Climate Change. (November 2016). Landfill Standards: A guideline on the regulatory and approval requirements for new/expanding land. 12 Michigan Department of Environmental Quality. Natural Resources and Environmental Protection Act, 451 of 1994: Part 115, Sold Waste Management.

required to have include daily coverage

within the design specifications.

and is applied on a per landfill basis for sites greater than 1.5

million m3.

The regulation does require landfills greater than 40,000 m3 to

include a detailed plan regarding the source, nature, quality,

and application of daily cover used for the landfill as part of the

design specifications11.

A report issued by the OWMA in December 2015 (Kelleher,

Maria; Seidel, Christina; Torrie, Ralph, December 2015)

estimates that only 4 out of 12.4 Mt of gas is currently

captured. The selected landfill parameters remain conservative

to this estimation.

The fraction of methane recovery was derived from the Alberta

Handbook (Appendix C).

Michigan landfill

methane gas

recovery fraction

With no additional data from specific

landfills, and no particular requirement

within the regulations to have daily

landfill cover, the recovery percent for

active operating cells was used in the

landfill equation: 0.35.

SS B9&10

The federal Clean Air Act Regulations (NSPS/EG) require

landfills greater than 2.5 million m3 to collect and control

landfill gas; however, combustion of diverted landfill waste

remains unregulated.

The Michigan Department of Environmental Quality (MDEQ)

regulates landfill requirements under Part 115 – Solid Waste

Management – of the Act12. The landfill design requirements

only include specifications for: the liner, the waste cell including

leachate collection and treatment, and final cover. No daily

cover requirements are referenced.


Therefore, the ‘temporarily covered’ parameter within the

Handbook for methane recovery could not be used as it was for

Ontario. Instead, waste sourced from Michigan is assumed to

be diverted from Type II MSW landfills comprised of active cells

with no wood waste or landfill gas collection or destruction

systems in place.

905Wood.com Biomass Properties are consistent with Essex County Feedlot parameters

As 905Wood.com does not have data available for the HHV and ash content of biomass, the properties for Essex County Feedlots biomass were assumed to be consistent for with 905wood.com.

SS B9&10

Both Essex County Feedlots and 905wood.com are local woodchip suppliers to C & B Farms, therefore the biomass properties of 905wood.com are more likely to be consistent with Essex County Feedlot rather than with Ecostrat – who operate large scale biomass collection and delivery in North America. Selecting the lower HHV value from Essex County Feedlots and the higher ash content as compared to Ecostrat results in a lower volume of credits generated by the project and maintains conservativeness.


3.2 Estimate of total GHG emission reductions/removals enhancements

attributable for the project The greenhouse gas assertion is a statement of the number of offset tonnes achieved during the reporting

period. The assertion identifies emissions reductions per vintage year and includes a breakout of

individual greenhouse gas types (CO2, CH4, N2O, SF6, HFCs, and PFCs) applicable to the project and total

emissions reported as CO2e. The total in units of tonnes of carbon dioxide equivalent (CO2e) is calculated

using the global warming potentials (GWPs) referenced in Table 4. There are no sources or sinks of SF6,

HFCs or PFCs.

Table 10 identifies the greenhouse gas assertion, containing the calculated number of offset tonnes

achieved, separated by each unique vintage year and GHG released.

Table 10: Offset tonnes achieved to current reporting period (2006 – 2016) and anticipated per year thereafter (italicized)

Year CO2

(t CO2) CH4

(t CH4) N2O

(t N2O) SF6

(t SF6) HFCs

(t HFC) PFCs

(t PFCs) CO2e

(t CO2e) Total

(t CO2e)

200613 2,090.50 58.948 -0.0072 - - - - 3,326

2007 2,905.70 79.779 -0.0082 - - - - 4,578

2008 3,495.20 67.59 0.0139 - - - - 4,918

2009 3,212.40 63.143 0.0119 - - - - 4,542

2010 3,102.10 63.789 0.0092 - - - - 4,444

2011 3,303.20 65.876 0.0115 - - - - 4,690

2012 2,943.20 63.9 -0.1 - - - 204.9 4,452

2013 3,618.60 75.6 -0.1 - - - 289.5 5,452

2014 4,616.43 94.27 -0.16 - - -

187.2

7,111

2015 3621.9 80.4 -0.1 - - - -5 5,585

2016 2,619 69.5 -0.1 - - - -5.0 4,320

2017 3,254 70 -0.1 - - - -5 4,969

2018 3,254 70 -0.1 - - - -5 4,969

2019 3,254 70 -0.1 - - - -5 4,969

2020 3,254 70 -0.1 - - - -5 4,969

202114 2,603 56 -0.1 - - - -3 3,970

13 October 20, 2006 – December 31, 2006 14 January 1, 2021 – October 20, 2021


Year CO2

(t CO2) CH4

(t CH4) N2O

(t N2O) SF6

(t SF6) HFCs

(t HFC) PFCs

(t PFCs) CO2e

(t CO2e) Total

(t CO2e)

ALL

YEARS 51,147 1,119 -1 0 0 0 649 77,265

4 IDENTIFICATION OF BASELINE Two baseline scenarios were evaluated for the Project. These scenarios and the relevant barriers affecting each of these scenarios are summarized in Table 11 below: Table 11: Barriers Assessment of Alternative Baseline Scenarios

Alternative Baseline Scenario Relevant Barriers

Alternative 1: The generation of heat using a biomass heating system in the absence of commercializing GHG reductions.

Financial/Economic: The use of biomass rather than fossil fuels has the potential to be a cheaper fuel source for C&B Farms when comparing fuel costs, as biomass materials were locally available from a third-party supplier at the time the project was conceptualized. However, the high capital costs of implementing a new biomass fueled heating system would serve to be a significant impediment in the implementation of this project. The return on investment from implementing the biomass heating system may have appeared to be attractive relative to the continued operation of the pre-existing gas burners, but there were significant risks in investing a large amount of capital in a new technology. The implementation of the biomass system and related infrastructure was a significant capital expenditure, which could have been avoided by continuing to operate the existing infrastructure. Also, the implementation of a biomass energy generation system requires infrastructure to convey the wood residues, to control particulate matter and to handle ash from the boilers. Institutional: The biomass boiler system also requires trained personnel to operate and troubleshoot. The operation and maintenance of the biomass gasification system and fuel feeding equipment is much more challenging and costly than the continued operation of the natural gas burners. New Technology: The implementation of biomass boiler technology required a significant amount of training of staff to operate the system, and infrastructure development on-site to facilitate the commissioning and operation of the biomass system.

Alternative 2: The generation of heat using fossil fuels.

Financial/Economic: Greenhouse operations in Canada have very high heating loads and thus can be vulnerable to volatile fuel prices. The volatility of natural gas prices posed a risk to C&B Farm’s competitiveness in the commercial greenhouse business as fuel prices significantly impact operating costs. The use of biomass wastes for thermal energy generation would likely result in lower fuel costs than the continued use of fossil fuels. The continued operation of the natural gas-fired or fuel-oil fired heating systems would not require any incremental capital costs.


Based on the barriers test above, BASELINE SCENARIO ALTERNATIVE 2 is considered the most likely

baseline scenario.

The baseline scenario is defined as the use of the pre-existing fossil fuel combustion equipment at C&B

Farm’s facility to meet the thermal energy demands of the greenhouses. The continuation of previous

practices represents the most likely alternative as the implementation of a new biomass heating

technology posed a number of risks.

The baseline is classified as dynamic, as the baseline must be recalculated each project year to account

for annual changes in the biomass energy consumption. The baseline for the 2016 reporting period was

altered from existing quantifications that used a 2005 historical average baseline approach, and included

a proportion of both fuel oil and natural gas derived from purchasing records. However, this methodology

is no longer an accurate reflection of the existing baseline scenario; as the farm has a non-interruptible

natural gas line and uses predominantly natural gas. Fuel oil is used only as back up, largely due to the

high cost and need for CO2 from the natural gas boiler to support plant development. Therefore, the

previous allocation of 36% fuel oil and 64% natural gas usage in the baseline scenario was changed to

100% natural gas for the 2016 vintage year.

5 QUANTIFICATION PLAN

5.1 Baseline Emissions Quantification Methodology

SS B9 & 10 Quantification of the Baseline Emissions from Decomposition of Biomass and Methane

Collection/Destruction

The methane generation potential of waste streams disposed of in a landfill is determined from the

following calculation outlined in the Protocol.

1. Emissions Decomp Biomass = emissions under SS B9 and B10 Decomposition of Biomass and Methane

Collection / Destruction

𝑄CH4,𝑡 = ∑ [k × (M𝐵 − 𝑀𝐴𝑆𝐻)× 𝐿𝑜 × 𝑒−𝑘(𝑥−1) × (1 − 𝑂𝑥)]

𝑥=40

𝑥=1

× (1 − 𝑅)

And:

𝐿𝑂 = 𝑀𝐶𝐹 × 𝐷𝑂𝐶 × 𝐷𝑂𝐶𝐹 × 𝐹 ×16

12

𝑘 = 7× 10−5 × 𝑃𝐶𝑃𝑁 − 0.0172

Where:

Emissions Baseline = Emissions Decomp Biomass + Emissions Thermal Heat Generation +

Emissions Fuel Extraction / Processing


Q = amount of methane emitted in the current year by the waste MB – MASH, (t CH4/yr)

MB = Total mass of biomass, tonnes, where (MB – MASH) = Mass of landfill avoidance (MLA)

x = year of waste placement

k = landfill decay rate15

PCPN = annual average precipitation.

The annual precipitation for Ontario was calculated based on 30-year climate normal data

from Environment Canada for the Ontario region, with a 200-km radius applied around

Leamington for southern Ontario precipitation.

Because Ecostrat identified Michigan waste sources coming from Taylor, Michigan, the

annual average precipitation data for the nearest city – Romulus – was used to represent

the Taylor region.16

The remaining inputs to this equation are summarized in Table 5.

SS B12 Quantification of the Baseline Emissions from Thermal Energy Generation

In order to estimate the natural gas savings, the historical average fossil fuel consumption (natural gas

and fuel oil #6) was calculated for 2005 using purchasing records for each fuel type. 2005 was the last

year where the farm relied solely on fossil fuels for heating. The relative consumption of each fossil fuel

from the 2005 historical records was then compared to the biomass consumption in each project year

using the boiler efficiency of each type of boiler. The following two equations summarize the calculation

methods for determining the baseline quantity of fossil fuels that would have been combusted had the

biomass boilers not been commissioned.

𝑆𝑆𝐵12 𝐸𝑚𝑖𝑠𝑠𝑖𝑜𝑛𝑠 𝑑𝑢𝑒 𝑡𝑜 𝑇ℎ𝑒𝑟𝑚𝑎𝑙 𝐶𝑜𝑚𝑏𝑢𝑠𝑡𝑖𝑜𝑛 = ∑ ((𝑉𝑁𝐺,𝑖 + 𝐹𝑂𝑖)×𝐺𝑊𝑃𝑖)

𝑖=𝐶𝑂2,𝐶𝐻4,𝑁2𝑂

Where:

NGC,i = Emissions due to natural gas combustion, tonnes

FOC,i = Emissions due to fuel oil combustion, tonnes

i = greenhouse gas species, CO2, CH4, N2O

GWPi = global warming potential for GHG species

15 Environment and Climate Change Canada (2016). National Inventory Report 1990-2014: Greenhouse Gas Sources and Sinks in Canada – Part 2. Canada’s Submission to the United Nations Framework Convention on Climate Change. 16 U.S climate data, 2017, version 2.2, available at: http://www.usclimatedata.com/climate/michigan/united-states/3192

http://www.usclimatedata.com/climate/michigan/united-states/3192

http://www.usclimatedata.com/climate/michigan/united-states/3192


And:

𝑁𝐺𝐶,𝑖 = 𝑉𝑁𝐺×𝐸𝐹𝑁𝐺,𝐶,𝑖

𝐹𝑂𝐶,𝑖 = 𝑉𝐹𝑂×𝐸𝐹𝐹𝑂,𝐶,𝑖

Where:

VNG = Equivalent volume of natural gas combusted in the baseline, m3

VFO = Equivalent volume of fuel oil combusted in the baseline, m3

EFNG,C,i = Emission factor for natural gas combustion, g/m3

EFFO C,i = Emission factor for fuel oil combustion, g/L

and:

𝑉𝑁𝐺 = 𝑄𝐹𝑜𝑠𝑠𝑖𝑙 × %𝑁𝐺

𝐻𝐻𝑉𝑁𝐺

𝑉𝐹𝑂 = 𝑄𝐹𝑜𝑠𝑠𝑖𝑙 × %𝐹𝑂

𝐻𝐻𝑉𝐹𝑂

Where:

QFOSSIL = equivalent fossil fuel derived energy input to a fossil fuel boiler, GJ

%NG = 2005 baseline proportion of natural gas combustion, %

%FO = 2005 baseline proportion of fuel oil combustion, %

HHVNG = Higher heating value of natural gas, MJ/m3

HHVFO = Higher heating value of fuel oil, GJ/m3

and:

%𝐹𝑂 = 𝑄𝐹𝑂,2005

𝑄𝑇𝑜𝑡𝑎𝑙,2005= 0.0%

%𝑁𝐺 = 1 − %𝐹𝑂 = 100.0%

𝑄𝐹𝑜𝑠𝑠𝑖𝑙 =𝑄𝐵−𝑁𝐸𝑇

𝜂𝐹,𝐵𝑜𝑖𝑙𝑒𝑟

Where:

QTOTAL,2005 = total energy of fossil fuel used for combustion, GJ

QFO,2005 = volume of fuel oil used for combustion in the baseline year, GJ

QB-NET = total energy produced from project biomass combustion, GJ


ηF,Boiler = efficiency of fossil fuel fired boiler, %

SS B13 Quantification of the Baseline Emissions from Fuel Extraction and Processing

The baseline emissions from fuel extraction and processing of natural gas and fuel oil are calculated by

taking the volume of the respective fossil fuel displaced by thermal energy generated from biomass in the

project scenario and multiplying this volume by the respective CO2, methane and nitrous oxide emission

factors for the respective fossil fuel extraction and processing as found in Table 3.

𝐹𝐹𝐸𝑋𝑃 = 𝐹𝑂𝐸𝑋𝑃−𝐶𝑂2𝑒 + 𝑁𝐺𝐸𝑋𝑃−𝐶𝑂2𝑒

Where: FFEXP = total emissions due to fossil fuel extraction and processing, tonnes CO2e

FOEXP-CO2e = baseline emissions due to fuel oil extraction and processing, tonnes CO2e

NGEXP-CO2e = baseline emissions due to natural gas extraction and processing, tonnes CO2e

And:

𝑁𝐺𝐸𝑋𝑃−𝐶𝑂2𝑒 = 𝑉𝑁𝐺× (𝐸𝐹𝑁𝐺,𝐸𝑋 + 𝐸𝐹𝑁𝐺,𝑃)

𝐹𝑂𝐸𝑋𝑃−𝐶𝑂2𝑒 = 𝑉𝐹𝑂×𝐸𝐹𝐹𝑂,𝐸𝑋𝑃

Where:

VNG = Equivalent volume of natural gas combusted in the baseline, m3

VFO = Equivalent volume of fuel oil combusted in the baseline, m3

NGEX = Emission factor for natural gas extraction, t CO2e/e3m3

NGP = Emission factor for natural gas processing, t CO2e/e3m3

FOEXP = Emission factor for fuel oil extraction and processing, kg CO2e/L

5.2 Project Emissions Quantification Methodology SS P12 Quantification of the Project Emissions from Biomass Combustion

The following equations outline the methodology used to calculation emissions from woodchip

combustion.

EmissionsBiomass Transfer = emissions under SS P9 Biomass Transfer (receiving area to Combustion facility)

Emissions of CO2 = R x P x #U x 745.7 x EFGRID/10^9

Where

Emissions Project = Emissions Combustion of Biomass + EmissionsBiomass Transfer


R = unit runtime, hours, assumed to be equivalent to total active planting and growing dates P = power, hp #U = number of equipment EFGRID = Ontario Electricity Grid consumption factor, g/kWh 745.7 = GJ in 1 hp

Emissions combustion of biomass = emissions under P12 Combustion of Biomass

The following equations outline the methodology used to calculation emissions from woodchip

combustion, (sample for January, 2016).

Emissions of CO2 = 0, since CO2 from biogenic sources are not considered

𝐵𝐶𝐻4 = 𝑀𝐵 × 𝐸𝐹𝐵,𝐶𝐻4 ÷ 1000𝑘𝑔𝑔/

Emissions of CH4 = (Mass of Biomass, tonnes) x (0.09 g CH4/kg biomass) ÷ 1000 g/kg

= 434.5 tonnes x 0.09 g CH4/ kg_biomass ÷ 1000 g/kg

= 0.039 tonnes CH4

𝐵𝑁2𝑂 = 𝑀𝐵 × 𝐸𝐹𝐵,𝑁2𝑂 ÷ 1000𝑘𝑔𝑔/

Emissions of N2O = (Mass of Biomass, tonnes) x (0.00002 kg N2O/kg_biomass)

= 434.5 tonnes x 0.06 g N2O/kg_biomass ÷ 1000 g/kg

= 0.026 tonnes N2O

6 MONITORING PLAN In general, the data control processes employed for this Project consist of manual data capture and

reporting, and manual entry of monthly totals or averages into the project quantification calculator.

The primary methods of data collection are the reconciliation of monthly natural gas utility invoices, fuel

oil sales receipts, and weight tickets for biomass deliveries. The natural gas and fuel oil consumption data

was then used to develop the relative annual energy consumption of the two fossil fuels at the facility to

quantify the natural gas and fuel oil savings resulting from the implementation of the biomass boilers, as

described in section 5.1.

Table 12 on the following page summarizes the data sources and handling procedures for the key

parameters used in the quantification methodology. Table 13 outlines the metering used for

measurement of data sources, and the parties responsible for their maintenance and calibration.


Table 12: Data Monitoring and Collection

SSR identifier or name

Data parameter

Estimation, modeling,

measurement or calculation approaches

Data Recording Data unit Sources/

Origin Monitoring frequency

Description and justification of

monitoring method Uncertainty

Deviation from the Biomass Protocol

B12

Proportion of Natural Gas used in baseline versus fuel oil

Estimation based on metered natural gas consumption in the baseline condition

Continuous metering of natural gas volumes by the utility meter and monthly reconciliation of invoices.

Invoiced m3 of natural gas (later converted to GJ of natural gas using HHV)

Natural gas utility invoices

Continuous

Natural gas meter is maintained by the gas utility and is subject to Government of Canada measurement requirements.

Uncertainty is low for the volumes of natural gas as this data originates from reliable sources.

A historic benchmark intensity approach was used in place of a projection-based approach, as discussed in Section 4, since the transparency and consistency in approach are enhanced. Additionally, the gas and production data was more complete than the heat output data. QA/QC methods ensure accuracy using this approach.

Higher Heating Value of Natural Gas (HHV)

Factor obtained from Union Gas online monthly Heat Value History for the “south” delivery area

reconciliation values published online for Union Gas customers

GJ/m3 of natural gas

Heat Value History Report

Continuous

Natural gas composition analyses are performed using metering equipment maintained by the gas utility and this equipment is subject to Government of Canada measurement requirements.

Uncertainty is low for the HHV of natural gas as this data originates from reliable sources on a monthly basis.

There is no deviation from the Protocol.

Proportion of Fuel oil used in the baseline condition

Estimation based upon metered fuel oil consumption in the baseline

Per load delivery of fuel oil used by the greenhouse and monthly reconciliation of invoices

Invoiced litres of fuel oil

Fuel Oil delivery invoices

Per load as delivered

This represents the highest frequency of data collection available.

Uncertainty is low for the fuel oil volumes as this data originates from reliable sources.


B12, P12 Quantity of biomass combusted

Measured Biomass weight delivered

Per load weight as indicated on invoice ticket

Tonnes Biomass Suppliers: Ecostrat

Per load as delivered

This represents the highest frequency of data collection available.

Uncertainty surrounding this measurement is low, as the delivery of biomass by truck is DOT regulated



Table 13: Meter Maintenance and Calibration

Project Specific Data

Meter ID Meter

Make/Model Maintenance

Schedule Calibration Schedule Accuracy Rating

Natural Gas Consumption (m3)

Union Gas Meter for C&B Farms

N/A

Maintained by Union Gas as per

Measurement Canada

requirements

Calibrated by Union Gas or subcontractors as per Measurement Canada

requirements

Measurement Canada Standard of

+/-0.2%17

Higher Heating Value of Natural gas

(HHV)

N/A. Union Gas Heat Value

History Report N/A

Maintained by Union Gas as per

Measurement Canada

requirements

Calibrated by Union Gas or subcontractors as per Measurement Canada

requirements

As per Measurement Canada standard18 of

+/-0.1 MJ/m3

Mass of Biomass

Transported to C&B

Farms

N/A

(Truck Scale)

Fairbanks Scale As needed Annual third-party

calibration n/a

Biomass Energy

Content N/A N/A N/A

Currently measured upon

request of biomass

purchaser.

n/a

7 DATA INFORMATION MANAGEMENT SYSTEM AND RECORDS

7.1 Data Management and QA/QC at C&B Farms The quantification of the mass of biomass consumed is completely manual, and is based on monthly

reconciliation of invoices received from the biomass supplier. Monitoring and QA/QC for biomass masses

consists of manual checking of data entered into the Quantification Calculator against the original invoices

from the biomass supplier to ensure independent review of the data prior to verification. A summary of

deliveries is provided by Ecostrat, which is converted to an excel document with Adobe Acrobat XI. This

summary of deliveries is cross-checked against the monthly invoices.

The quantification of the thermal energy delivered to the greenhouses will be based on the calorific value

of the biomass combusted and the combustion efficiency of the boiler. Manual checking will be conducted

on an annual basis by a third-party and will consist of:

✓ Reconciliation of values in the calculator with hard-copy records of electronic data;

✓ Comparison with data from other time periods to identify any major discrepancies (“reality

checking”); and

✓ Recalculation of selected values to ensure that the Calculator remains accurate.

A Data Flow Chart has been included below as Figure 6 to illustrate the flow of information within C&B

Farms and to Blue Source.

17 http://www.ic.gc.ca/eic/site/mc-mc.nsf/eng/lm00590.html 18 http://www.ic.gc.ca/eic/site/mc-mc.nsf/eng/lm00590.html

http://www.ic.gc.ca/eic/site/mc-mc.nsf/eng/lm00590.html

http://www.ic.gc.ca/eic/site/mc-mc.nsf/eng/lm00590.html


Figure 6: Data flow from suppliers to C&B Farms and to Blue Source

7.2 Data Management and QA/QC at Blue Source Blue Source Canada holds itself to the highest professional and ethical standards. Staff all have experience

in working on GHG projects and/or training in the use of ISO14064-2. Junior staff members are mentored

closely until their level of competence is deemed sufficient for them to work more independently. This

experience and training helps to ensure that errors and omissions are minimised and that project

documentation is compiled in accordance with the principles of relevance, completeness, consistency,

accuracy, transparency and conservativeness.

Blue Source Canada operates a rigorous internal QA/QC process that is built around the principle of senior

review (i.e. calculations and reports are checked by experienced staff members prior to being released).

The quantification calculator, for example, is checked for:

• Transcription errors/omissions

• Correctly functioning links/formulas in spreadsheets

• Correct and transparent referencing of data sources

• Justification of assumptions

• Use of, and compliance with, most up-to-date versions of protocols, technical guidance, etc.

Natural Gas Invoices

Fuel Oil delivery invoices

Wood chip delivery invoicesC&B Farms

Natural Gas Suppliers:• Union Gas

Fuel Oil Suppliers:• Sterling Marine Fuels• Neste• Johnny’s Gas Bar

Biomass Suppliers:• Ecostrat• Bulkliner Transport

C&B FarmsOffset Calculator

Spreadsheet

C&B Farms2005 Baseline Fossil Fuel Consumption

Spreadsheet

C&B FarmsProject Year

Biomass Summary Spreadsheet

Fossil Fuel Boiler Consultant:Dino Lusetti

Industrial Boiler Specialties

Biomass Boiler Information:NRCan CANMET Energy

Technology Centre

Email indicating typical efficiencies of Cleaver-Brooks

Fossil Fuel Boilers

Report on Combustion Testing on biomass boiler at

C&B Farms

Documents Controlled by Third PartiesDocuments

Controlled by C&B Farms

Documents Controlled by Blue Source


In addition, the Offset Project Report is also senior-reviewed for errors, omissions, clarity, etc.

Issues are recorded in Blue Source’s QA/QC checklist for the project (and, as necessary, embedded into

the reviewed version of the documents and/or calculator) and these will be corrected before these are

sent to the third-party verifier. Staff sign an “Attestation of Quality Assurance and Quality Control” to

document that the QA/QC process was followed. This QA/QC process is kept under constant review.

7.2.1 Back-up Procedures at Blue Source

Electronic data is backed up by Blue Source’s IT service provider, Calitso. A copy of this back-up procedure

is provided as Appendix A.

7.2.2 Document Retention Policy at Blue Source

Blue Source operates a documentation retention policy, which all staff must abide by as a condition of

their employment. A copy of this document retention policy is provided as Appendix B.

8 GREENHOUSE GAS ASSERTION The greenhouse gas assertion is a statement of the number of VERRs achieved during the reporting period.

The assertion identifies emissions reductions per vintage year and includes a breakout of individual

greenhouse gas types (CO2, CH4, N2O, SF6, HFCs, and PFCs) applicable to the project and total emissions

reported as CO2e. The total in units of tonnes of carbon dioxide equivalent (CO2e) is calculated using the

global warming potentials (GWPs) listed in Table 4.

The total greenhouse gas emission reductions claimed for the crediting period of January 1, 2016 to

December 31, 2016 are:

4,320 tonnes CO2e

Table 14 identifies the greenhouse gas assertion, containing the calculated number of offset tonnes

achieved, separated by each unique vintage year and GHG released.


Table 14: 2016 VERR Summary

Baseline Emissions t CO2 t CH4 t N2O tCO2e TOTAL (CO2e)

SS B9&10 Decomposition of Biomass

and Methane Collection/Destruction

66.4 1,659

SS B12 Thermal Energy Produced 2,448.7 0.05 0.05 2,463.2

SS B13 Fuel Extraction &

Processing 170.2 3.4 0.009 257.0

ALL 2,618.9 69.8 0.1 4,379.2

Project Emissions t CO2 t CH4 t N2O tCO2e TOTAL (CO2e)

P9 Biomass Processing 5.0 5.0

SS P12 Biomass Combustion - 0.2 0.2 54.2

ALL 0.2 0.2 5.0 59.2

Emissions Offset Credits Created t CO2 t CH4 t N2O tCO2e TOTAL (CO2e)

ALL 2,618.9 69.5

-0.1 -5.0 4,320.0


9 PROJECT PERFORMANCE Figure 7 depicts the Project performance from 2006 to the current reporting period. 2012 and 2013 saw

higher VERRs created due to the increase in mass of biomass consumed. Since 2008, the amount of

VERRs produced per tonne of biomass combusted has consistently been in the range of 1.5 - 1.8

VERRs/tonne, as represented by the green line.

Figure 7. Historic Offset Project Performance.

The generation intensity increased from 2013 due to the update of the global warming potentials. In 2015

the intensity reduced slightly due to the addition of the project electricity source, the change to the landfill

quantification as well as using the median calorific values for biomass energy. There is a decline in VERRs

generated in 2016 due to a significantly lower volume of biomass supplied to the farms: nearly 25% less

than 2015. The volume of offsets also decreased due to the removal of fuel oil from the baseline

condition, which has larger combustion emission factors compared to natural gas. Thus, the emission

reductions associated with thermal energy production caused a decline of 18% in overall emissions. The

VER performance indicator did rise slightly in 2016, largely due to the higher VOCf of 0.6 implemented in

the quantification.

0.000

0.200

0.400

0.600

0.800

1.000

1.200

1.400

1.600

1.800

2.000

-

1,000.00

2,000.00

3,000.00

4,000.00

5,000.00

6,000.00

7,000.00

8,000.00

2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016

VER

Rs/

ton

ne

Bio

mas

s

VER

Rs/

Bio

mas

s, t

on

ne

s

Biomass VERRs Performance Indicator


10 REPORTING AND VERIFICATION DETAILS This report has been prepared in accordance with ISO 14064-2 and GHG CleanProjects® requirements.

The verifier, Brightspot Climate, is an independent third-party. Contact details for the verifier have been

included in Section 1.7 of this report.

An acceptable verification standard (e.g. ISO14064-3) has been be used and the verifier was vetted to

ensure technical competence with this project type. The verifier was engaged to provide a reasonable

level of assurance.


11 STATEMENT OF SENIOR REVIEW This offset project plan was prepared by Kelsey Lank, Carbon Solutions Analyst, Blue Source Canada and

senior reviewed by Kelly Parker, Engineer, Blue Source Canada. Although care has been taken in preparing

this document, it cannot be guaranteed to be free of errors or omissions.

Prepared by:

Senior reviewed by:

Kelsey Lank 05/01/2017

Kelly Parker 05/01/2017


12 WORKS CITED Alberta Environment. (September 2007). Quantification Protocol for Diversion of Biomass to Energy from

Biomass Combustion Facilities, version 1.0. Edmonton: Alberta Environment.

Canadian Association of Petroleum Producers, CAPP. (September 2004). Technical Report: A National

Inventory of (GHG), (CAC), and (H2S) Emissions by the Upstream Oil and Gas Industry - Volume

1, September 2004.

Clearstone Engineering Ltd. (September 2004). A National Inventory of Greenhouse Gas(GHG), Criteria

Air Contaminant (CAC) and Hydrogen Sulphide (H2S) Emissions by the Upstream Oil and Gas

Industry, Volume 1 Overview of the GHG emissions Inventory. Calgary: CAPP.

Environment Canada. (2016). National Inventory Report,1990-2014 Part 2. Environment Canada.

Environment Canada. (2016). National Inventory Report,1990-2014 Part 3. Environment Canada

Government of Alberta. (March 2015). Carbon Offset Emission Factors Handbook, version 1.0.

Edmonton: Government of Alberta.

Kelleher, Maria; Seidel, Christina; Torrie, Ralph. (December 2015). Greenhouse Gas Emissions and the

Ontario Waste Management Industry. Ontario Waste Management Association.

Ministry of the Environment and Climate Change. (January 2012). Landfill Standards: A guideline on the

regulatory and approval requirements for new or expanding landfilling sites.

Ministry of the Environment and Climate Change. (May 2016). Landfill gas capture: a guideline on the

regulatory and approval requirements for landfill gas. Ontario Regulation 232/98 and Revised

Regulations of Ontario 1990, Regulation 347 (General Waste Management) under the

Environmental Protection Act.

Queen's Printer for Ontario (2012-2017) e-Laws. Ontario Regulation 232/98: LANDFILLING SITES.

Environmental Protection Act, R.S.O 1990, c. E.19.

Appendix A – IT Backup Procedure for Blue Source

Backup Procedure

Prepared For: Blue Source

Objective

To minimize interruptions to business by insuring that operation can be restored in case of

• Loss of any amount of information due to accidental or malicious deletion;

• Failure of one or more computers or components such as a hard disk drive; or

• A disaster resulting in loss of the entire infrastructure, or loss of access to it.

Backup Procedure

1. Backup Rotation

• Rotation is continues and automatic in accordance with retention specifiedin item 2.

• All off-site data is stored in Canada at a SSAE 16, CSAE 3416 and ISA3402certified data center.

2. Retention

• 30 days of continuous data change, and nightly system state is off site in datacenter. Data is stored both on-site and off-site

• Data can be restored as far as 30 days back from on-site and off-site backups

3. Backup Schedule

• Data backup

� Full backup is scheduled to run nightly at 8:00PM

• Image Backup (Entire server backup) – Disaster Recovery Backup

� Scheduled to run nightly at 3am

Off site storage

• All off-site data is stored in Canada at a SSAE 16, CSAE 3416 andISA3402 certified data center.

Appendix B – Data Retention Policy at Blue Source

Last Revision: January 8, 2013

Document Retention Policy, version 1.3.

1. All documents relevant to Offset Projects will be kept, in at least

electronic format, and where possible, in hardcopy format, for

a. At least 10 years beyond the last year in which credits are created

(e.g. a project that creates credits between 2000-2008 will have

all records kept until at least 2018), or

b. As required by the Offset Project Program

whichever period is longer.

2. Hard copy documents will be kept in project folders in our Blue Source

head office location, which is currently Suite 700, 717 – 7th Av SW,

Calgary, AB, T2P 0Z3. All electronic documents will be saved to the

appropriate project folder on the Calgary Server (“S:\ drive”).

3. The S:\ drive will be backed up in accordance with Blue Source’s IT

Backup Procedure, which may change from time to time.

4. Blue Source’s preference is to keep all documents in electronic form,

wherever possible.

5. All employees will comply with this policy as a condition of their

employment.

Yvan Champagne

President, Blue Source Canada ULC

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