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Table of Contents
Executive Summary ............................................................................................................................. 4
1. Introduction ................................................................................................................................... 5
2. Background on the Canadian Federal Clean Fuel Standard ................................................... 6
2.1 Canadian Federal Clean Fuel Standard ................................................................................. 6
2.2 Compliance Obligations .......................................................................................................... 6
2.3 Compliance Pathways ............................................................................................................ 8
3. Existing Biofuel Use & Regulations in Canada ......................................................................... 9
3.1 Existing Renewable Fuel Standards ....................................................................................... 9
3.2 Future Uncertainties ................................................................................................................ 9
3.3 Historical Canadian Demand for Low Carbon Fuels .............................................................. 9
3.4 Clean Fuel Standards for Transportation Fuels.................................................................... 14
3.5 Provincial Policies to Enable Low Carbon Intensity Natural Gas ......................................... 15
4. Other CFS Considerations ........................................................................................................ 16
5. Overview of Approach to Considering Future CFS Supply and Demand ............................ 19
6. Future Supply and Demand Scenarios .................................................................................... 23
6.1 Gasoline Substitutes (Ethanol) ............................................................................................. 29
6.2 Diesel Substitutes (Biodiesel & Renewable Diesel) ............................................................. 31
6.3 Natural Gas Substitutes (Renewable Natural Gas) .............................................................. 34
6.4 Jet Fuel (Renewable Jet Fuel) .............................................................................................. 39
6.5 Propane (Renewable Propane) ............................................................................................ 40
6.6 Heating Oil (Renewable Fuel Oil) ......................................................................................... 41
Appendix A: Detailed Methodology & Assumptions ..................................................................... 42
Scoping of Fuels ........................................................................................................................... 42
Emission Reduction Targets ........................................................................................................ 43
GHG Intensities of Low Carbon Liquid Fuels ............................................................................... 44
Energy Density ............................................................................................................................. 45
Co-Product Splits .......................................................................................................................... 45
Appendix B: References ................................................................................................................... 46
4
Executive Summary
The Clean Fuel Standard (CFS) currently under development by Environment and Climate Change
Canada (ECCC) aims to reduce Canada’s greenhouse gas emissions (GHG) through the increased
use of lower carbon fuels, energy sources, and technologies. Informed by similar initiatives in other
jurisdictions the CFS is designed to incent the use of low-carbon fuels throughout the economy. The
CFS additional to the Pan-Canadian Approach to Pricing Carbon Pollution and will be applied as a
performance-based approach with the expectation to achieve annual reductions of 30 million tonnes
of GHG emissions by 2030.[1]
The CFS is a significant regulation, both in terms of scope and impact on the environment and the
economy. Globally there is no precedent for a combined low carbon fuel standard for liquid,
gaseous, and solid fuels. The CFS aims to build on learnings from other jurisdictions and experience
in Canada for introducing low carbon fuels into the market, such as the existing policies regulating
the use of ethanol in the transportation fuel system, but the scope, scale, and timeline of the planned
changes mean that there is significant uncertainty in terms of how effectively the market will be able
to respond. The CFS must be designed and deployed with an appreciation of the impacts on GHG
emissions and the economy to ensure that emission reductions are maximized at minimal impact to
the Canadian economy.
The Canadian Association of Petroleum Producers (CAPP) commissioned ICF to assess the
potential supply and demand for low carbon fuels associated with the design and implementation of
the CFS for liquid and gaseous fuels. The analysis in this study evaluated the demand for low
carbon fuels as a result of the proposed CFS and provided supply estimates. ICF outlined three
(high, mid, low) demand scenarios which result in a range of values.
Fuels covered under the CFS make up about 70% of Canada’s end use energy consumption. Given
the GHG abatement expectations of the CFS, very significant quantities of low carbon fuel will be
required to fulfill the carbon intensity reduction requirements. Between the low and high case, ICF
estimates that between 81 to 456 PJ of liquid low carbon fuels will be required by 2030 to meet CFS
demand. This is compared to current domestic biofuel demand levels of 108 PJ. From 2010 to 2019,
Canada’s low carbon fuel demand more than doubled, with about half the demand met by imports
rather than domestic production. As of 2019, Canada supplies 60% of their ethanol demand
domestically and 55% of their biodiesel demand. Canada relies on imports to supply current
renewable diesel consumption. Canada would need to increase domestic capacity and/or increase
imports in order to meet the potential quadrupling of demand by 2030. Given that almost 70% of the
growth in Canadian ethanol demand since 2011 has been met through imports from the US, and that
the US continues to be over-supplied with ethanol, it would seem likely that much of the incremental
ethanol demand from CFS would be met by US imports. However, Canada’s access to US low
carbon fuel supplies may be limited if future US or international policies increase the demand for low
carbon fuels globally.
In addition, ICF estimates that up to 542 PJ of low carbon gaseous fuels will be required. At this
stage, no other country has adopted a national CFS for gaseous fuels. In Canada, domestic demand
for low carbon gaseous fuels is currently limited to renewable natural gas (RNG) in BC and Quebec.
Canada currently has about 5 PJ of domestic renewable natural gas production capacity through 11
different production facilities. Although there has been demand for liquid low carbon fuels for over a
decade in Canada, there is far less precedence for low carbon gaseous fuels. Unlike common low
carbon fuels policies that focus on the transportation sector, the proposed CFS will have impacts on
all fuel types and all sectors of the economy.
Executive Summary
5
1. Introduction
This report provides an analysis of the potential supply and demand implications for low carbon fuels in Canada resulting from the proposed CFS, to support discussion related to the development of these Federal regulations. It includes a review of the proposed regulations, current Canadian supply and demand for low carbon fuels, and a range of scenarios illustrating the low carbon fuel volumes that would be required to meet different GHG emission reduction targets. Context on potential supply sources and limitations on low carbon fuels are also discussed.
The report is split into the following sections:
• Section 2 summarizes the main and relevant elements of the CFS design as we understand
them today
• Section 3 illustrates the existing low carbon fuel use and regulatory context in Canada
• Section 4 discusses other considerations
• Section 5 provides an overview of the approach applied to assess future demand and
supply for low carbon fuels resulting from the CFS.
• Section 6 provides the CFS supply and demand results.
1. Introduction
6
2. Background on the Canadian Federal Clean Fuel Standard
2.1 Canadian Federal Clean Fuel Standard
In late 2016 the Government of Canada initiated consultations with provinces and territories,
Indigenous peoples, industries, and non-governmental organizations with a goal of developing a
Clean Fuel Standard (CFS) to reduce Canada’s greenhouse gas emissions (GHG) through the
increased use of lower carbon fuels, energy sources and technologies. Informed by similar initiatives
in other jurisdictions the CFS is designed to incent the use of low-carbon fuels throughout the
economy. The Canadian national CFS is additional to the Pan-Canadian Approach to Pricing Carbon
Pollution and will be applied as a performance-based approach with the expectation to achieve
annual reductions of 30 million tonnes of GHG emissions by 2030.[1]
Since the announcement of the CFS several policy papers have been developed by Environment
and Climate Change Canada (ECCC) detailing elements of the proposed regulation. The CFS
regulations will eventually cover all fossil fuels used in Canada, but will set separate targets for
liquid, gaseous and solid fossil fuels. It is being developed in a phased approach, with liquid fuel
class regulations developed first, followed by gaseous and solid fuels. Globally there is no precedent
for a combined clean fuel or low carbon standard (CFS) for liquid, gaseous and solid fuels. When
regulation moves forward, Canada will be the first jurisdiction to implement this compliance caliber
type of broad fuels policy.[2]
As a result of the COVID-19 pandemic, ECCC has delayed the publication of proposed regulations
for the liquid fuel class of the CFS to fall 2020. ECCC is continuing to engage with the CFS
Technical Working Group on key regulatory design elements with consultations occurring in June
2020. The CFS Regulations release is expected in 2021 with requirements for liquid fuels coming
into force in 2022 and requirements for gaseous and solid fuels coming into force in 2023.[1]
2.2 Compliance Obligations
The objective of a CFS is to drive a reduction in the GHG intensity of the energy consumed through
the substitution of fossil fuels with lower carbon fuels, energy sources and technologies. Below we
define the fuels covered under the proposed regulation and the targets for the low carbon fuel and
resulting carbon intensity reduction.
Covered Fuels
The Clean Fuel Standard will apply to liquid, gaseous and solid fuels combusted for the purpose of
creating energy. Covered liquid fuels include gasoline, diesel fuel, jet fuel, kerosene and light and
heavy fuel oils. Covered gaseous fuels include natural gas (including liquefied natural gas and
compressed natural gas) and propane. Covered solid fuels include coal, petroleum coke and coke. 0F
i
In the process of producing fossil fuels, those fossil fuels produced and used on-site are referred to
as “self-produced and used fuel”. While most self-produced and used fuels will be exempt, the Clean
Fuel Standard will establish a carbon intensity reduction requirement for some of these fuels,
including coal used at coal mines and petroleum coke produced at refineries and upgraders. All self-
produced and used transportation fuels produced at refineries and upgraders (diesel fuel and
i Coal combusted at facilities that are covered by the federal coal-fired electricity greenhouse gas emission regulation
will be exempted from the CFS regulation.
2. Background on the Canadian Clean Fuel Standard
7
gasoline) will be subject to the reduction requirements for gasoline and diesel under the Clean Fuel
Standard.
The CFS will not apply to fuels when they are primarily used as feedstocks in industrial processes or
when used for non-combustion purposes (e.g. solvents).
Certain fuels will be excluded from application of the carbon intensity requirements of the Clean Fuel
Standard, including fuels that are exported from Canada, fuels that are in transit through Canada,
and coal combusted at facilities that are covered by coal-fired electricity GHG regulations. Other
exclusions may be considered.
Carbon Intensities
The CFS will establish lifecycle carbon intensity values and requirements separately for liquid,
gaseous and solid fuels accounting for the amount of greenhouse gases emitted to produce a unit of
energy. This lifecycle approach will cover raw material extraction through materials processing,
manufacture, distribution, use, repair and maintenance, and disposal or recycling, where applicable.
The table below provides baseline carbon intensities and carbon intensity credit reference values for
covered fuels. Liquid fuel carbon intensity credit reference values have been updated per the revised
2030 target and trajectory provided in the June 2020 technical working group consultations.[3] 1F
ii
Exhibit 1 Proposed Carbon Intensities (g CO2e/MJ)
Fuel Baseline Carbon
Intensity
Carbon Intensity
Credit Reference 2022
Carbon Intensity
Credit Reference 2030
Liquid Fuels 84-100 89.1 79.5
Gasoline 92 89.6 80.0
Diesel 100 97.6 88.0
Kerosene 88 85.6 76.0
Light Oil 84 81.6 72.0
Heavy Oil 99 96.6 87.0
Jet Fuel 86 83.6 74.0
Solid Fuels 97-110 Not yet defined Not yet defined
Natural Gas 62 61.8 (Interim) 61.8 (Interim)
Compressed Natural Gas 65 Not yet defined Not yet defined
Liquified Natural Gas 73 Not yet defined Not yet defined
Propane 75 74.8 (Interim) 74.8 (Interim)
Under the CFS, the carbon intensity of liquid fuels will have to be reduced by 12 grams (g) of carbon
dioxide equivalent (CO2e) per megajoule (MJ) below their reference carbon intensity by 2030. This
corresponds to a carbon intensity reduction of approximately 13% and is expected to result in up to
23 megatonnes (Mt) of incremental emissions reductions in 2030. Carbon intensity reduction
requirements for liquid fuels will start in 2022, requiring a 2.4 g CO2e/MJ reduction for all liquid fossil
ii Liquid fuels include gasoline, diesel, kerosene, light and heavy fuel oil. Solid fuels include coal and petroleum coke.
8
fuels, increasing by 1.2 g CO2e/MJ annually to achieve a 12 g CO2e/MJ carbon intensity reduction
requirement in 2030.
2.3 Compliance Pathways
The main objective of the CFS is de-carbonization through the reduction of the GHG emissions
intensity of fossil fuels consumed in the economy. The main outcome is the substitution of higher
GHG emitting fuels with lower GHG emitting fuels and the creation of demand for and supply of low-
carbon fuels.
The proposed CFS regulation provides an array of compliance options beyond direct fuel
substitution. ECCC identified three compliance categories and has provided detailed criteria on how
credits are developed within the liquid fuel stream. More substantial guidance, specific to the
gaseous and solid stream is expected with the release of the gaseous and solid fuels regulatory
approach document. Three compliance categories are afforded under the regulation published to
date; Category 1, actions throughout the lifecycle of a fossil fuel that reduce its carbon intensity,
Category 2, the supply of low-carbon-intensity fuels and Category 3, end-use fuel switching. The
focus of the analysis in this report is compliance category 2.
The supply of low-carbon intensity fuels (Compliance Category 2) allows for the creation of credits
through the reduction of lifecycle carbon intensity of fossil fuels by blending low-carbon intensity
fuels with fossil fuels or using low-carbon intensity fuels on their own (known as “drop-in” fuels).
Historically this has been the main pathway to compliance in similar regulations and is expected to
serve as the central compliance pathway for the CFS.
For liquid fuels a low-carbon intensity fuel content requirement has been established ensuring a
distinct demand for a minimum of 5% low-carbon intensity fuel content in gasoline and 2% in diesel
and distillate heating oil.
To date, ECCC has indicated they will not set a minimum renewable fuel content requirement for the
gaseous stream. This is distinct from approaches in other jurisdictions such as British Columbia and
Quebec, which do not regulate gaseous fuels.
Low-carbon intensity fuels are defined as fuels other than the fossil fuels subject to the carbon
intensity reduction requirements, which have a carbon intensity that is equal to or less than 90% of
the credit reference carbon intensity value for the fuel.[1] Low-carbon intensity fuels in the gaseous
class, defined as part of the liquid class regulations, are currently limited to hydrogen, biogas,
renewable natural gas, and renewable propane. ECCC is developing a new Fuel Lifecycle
Assessment Modelling Tool which will be used to quantify the lifecycle carbon intensity of low-carbon
intensity fuels. As a result, low-carbon carbon intensity values directly applicable to the CFS are not
yet available.
In addition to the three compliance categories, several market mechanisms have been defined to
support market flexibility.[1] These mechanisms include Renewable Fuel Regulation (RFR)
compliance unit bank roll-over, banking, cross-class trading, early credit creation, credit clearance
mechanism, compliance fund mechanism and deficit carry forward. These mechanisms still need to
be developed and defined but they are intended to add further optionality to meeting compliance
obligations and support the liquidity of the credit and trading system but have not been considered
within this analysis, which focuses on quantifying the potential demand for low-carbon fuels through
CFS.
9
3. Existing Biofuel Use & Regulations in Canada
3.1 Existing Renewable Fuel Standards
The Federal Renewable Fuels Regulation has reduced GHG emissions from fuels in Canada,
requiring an average renewable content of at least 5% for gasoline and 2% for diesel. Five provinces
also have renewable fuel mandates equal to or higher than the current federal mandate.2F
iii Currently
there is approximately 7% renewable fuels in the gasoline pool and 2% in the diesel pool, resulting in
reductions of approximately 4 Mt CO2e per year.[4] The proposed CFS is meant to modernize and
replace the existing Renewable Fuels Regulation in Canada.
Exhibit 2 Current Provincial Renewable Blend Requirements[5]
Province Ethanol Blend Mandate
for Gasoline Renewable Fuel Blend
Mandate for Diesel
British Columbia 5% 4%
Alberta 5% 2%
Saskatchewan 7.5% 2%
Manitoba 8.5% 2%
Ontario 10% 3F
iv 4%
3.2 Future Uncertainties
As demand for transportation fuels has dropped during the COVID-19 Pandemic, the dropping price
of petroleum-derived fuels has made low carbon fuels less competitive. The demand for low carbon
fuels is also down, as lower volumes are required to meet total blending requirements. While these
dynamics may reverse themselves, they highlight how disruptions or policy changes can greatly
influence international fuel market dynamics. For example, if broader low carbon fuel policies are
adopted in the US, this could decrease the US supply available to Canada and other countries. If low
carbon fuel polices are adopted outside of the US, this could increase competition for US supply,
making it more difficult and expensive for Canada to rely on US fuels. It is important to consider that
changes to low carbon fuel policies in other jurisdictions could limit Canada’s ability to import low
carbon fuels.
3.3 Historical Canadian Demand for Low Carbon Fuels
Canada’s net demand for low carbon fuels more than doubled from 2010 to 2019, as shown in
Exhibit 3.[6] In 2010, the share of low carbon fuels was 89% ethanol, 5% biodiesel, and 6%
renewable diesel, while in 2019, the share was 76%:15%:9%, respectively. Growth in ethanol
consumption has slowed since 2015, but demand has remained steady. While demand for low
carbon diesel alternatives have grown at a faster rate, they have also seen greater up and down
fluctuations from year to year.
iii Provinces include British Columbia, Alberta, Saskatchewan, Manitoba and Ontario
iv Beginning in 2020
3. Existing Biofuel Use and Regulation in Canada
10
Exhibit 3 Net Canadian Demand for Low Carbon fuels, 2010 – 2019 [million L]
The specific dynamics of Canada’s supply and demand for low carbon fuel are unique to each fuel
type, in terms of production versus imports, and consumption versus exports. The following exhibits
show the supply (imports and production) and demand (exports and consumption) breakdown for
each year.
As Canada’s demand for ethanol has grown over the past decade, most of this incremental demand
has been met by importing more ethanol, rather than building more domestic production capacity.
Exhibit 4 shows that imports supplied 66% of the increased consumption from 2010 to 2019, and
given that more than half of the increase in domestic ethanol production over that same period
occurred in 2011 alone, imports have represented an even larger share of the growth since 2011.
Over this timeframe the share of incoming fuel from production and imports has shifted from about
77% and 23% in 2010 to 58% and 42% in 2019.[7] To put some context on Canadian demand it is
also important to consider US supply and demand for ethanol, where 98% of Canada’s ethanol
imports (and essentially 100% of its fuel ethanol imports) originate. In 2019 the US had ethanol
production capacity of 16.9 billion gallons (63,970 million Litres), while US biofuels regulations
include a 15 billion gallon (56,780 million Litres) on corn-based ethanol [8], resulting in a surplus in
capacity that is more than triple total Canadian ethanol demand. Canada consumes most of the
ethanol that they produce and import, and only exports a very small amount (less than 5%).
11
Exhibit 4 Ethanol in Canada, 2010 – 2019 [million L]
To meet Canada’s demand for biodiesel, supply has swung between production and imports. The
share of incoming fuel from production and imports has shifted from 53% and 47% in 2010 to 39%
and 61% in 2019. Canada has also shifted towards consuming more biodiesel than they export. The
share of outgoing fuel from consumption and exports has shifted from 47% and 53% in 2010 to 71%
and 29%. The United States is by far the largest supplier of biodiesel to Canada, but some biodiesel
is also imported from Europe, primarily Germany, and also from Argentina.[7]
Exhibit 5 Biodiesel in Canada, 2010 – 2019 [million L]
12
From 2010 to 2019, Canada has had no renewable diesel production capacity, and everything
consumed has had to be imported. The US exports less renewable diesel than Canada’s demand.
Canada has imported renewable diesel from Singapore, the Netherlands, Finland, and the United
States.[6]
Exhibit 6 Renewable Diesel in Canada, 2010 – 2019 [million L]
The breakdown of ethanol production capacity by province is shown for ethanol in Exhibit 7 for 16
operational and 4 demonstration facilities. In 2015, Ontario had the most ethanol production capacity
in Canada, followed by Saskatchewan, Quebec, Manitoba, and Alberta.[6] There is also a
demonstration facility of unknown size in PEI.
Exhibit 7 Ethanol Production Capacity by Province, 2010 [million L per year]
13
The breakdown of biodiesel production capacity by province is shown for biodiesel in Exhibit 8 for
10 operational facilities. In 2015, Ontario had the most biodiesel production capacity in Canada,
followed by Alberta, Quebec, Saskatchewan and BC.
Exhibit 8 Biodiesel Production Capacity by Province, 2015 [million L per year]
Historically, the price of ethanol has followed the price of petroleum-derived gasoline in the US, as
shown in Exhibit 9. There is an over-supply of ethanol in North America, so margins are low for
ethanol producers serving the transportation markets, and ethanol prices are a few cents per gallon
cheaper than gasoline.
Exhibit 9 Historic US Gasoline and Ethanol Prices
14
Historically, the price of biodiesel has stayed close to the price of petroleum-derived diesel in the US.
Publicly available information about renewable diesel wholesale prices is very limited.[9] Some
studies estimate that renewable diesel may cost about 20% to 30% more to produce than petroleum-
derived diesel.[10] For comparison, the biodiesel wholesale price was about 15% higher than the
petroleum-derived diesel price in Exhibit 10.
Exhibit 10 Historic US Diesel and Biodiesel Prices
3.4 Clean Fuel Standards for Transportation Fuels
There are several jurisdictions that have implemented low carbon fuel standards for the
transportation sector which provide valuable insights into how this type of policy can be
implemented. California, Oregon, British Columbia and the European Union have all implemented
low carbon fuel standards for transportation.
Both California and Oregon currently require a 10% reduction in transportation fuel carbon intensity
by 2020 and 2025 respectively.[11] Fuel providers must meet reduction targets by selling more low-
carbon fuels, reducing carbon intensity of fossil fuels, or purchasing credits from producers who
supply low carbon fuels.
British Columbia has implemented the renewable and low carbon fuel requirements regulation.
Under the BC regulation fuel suppliers must meet a renewable fuel requirement of 5% for gasoline
and diesel and must reduce fuel carbon intensity by 10% by 2020. In order to meet the low carbon
requirement fuel suppliers may supply more low carbon fuels or acquire credits through the
regulation or trade credits with other suppliers.[4]
The European Union added Article 7a to the EU Fuel Quality Directive in 2009. The directive
requires suppliers to reduce carbon intensity by 6% for transportation fuels supplied to the EU. The
directive is integrated with the EU’s renewable energy directive.
15
3.5 Provincial Policies to Enable Low Carbon Intensity Natural Gas
Both Quebec and British Columbia have recently implemented policies aimed to increase pipeline-
injected RNG consumption within the province.
Quebec enacted regulations in 2019 setting the minimum quantity of RNG produced in Québec and
to be injected by a natural gas distributor at 1% of the total quantity of natural gas the distributor
distributes as of 2020, and progressively increases that quantity to 5% of the total quantity of natural
gas distributed by 2025.[12]
British Columbia’s CleanBC climate strategy released in 2018 includes a policy mandate to increase
RNG consumption to 15% of natural gas consumed in the province by 2030.[13] The policy is
applicable to both residential and industrial natural gas users and is projected to result in an
estimated total annual demand of 30 PJ in 2030.
16
4. Other CFS Considerations
ICF has calculated the estimated volumes of low carbon fuels that would be required to meet the
emission reduction targets in the CFS. This demand does not take potential blending limitations into
account. This excludes other compliance mechanisms, such as reducing the carbon intensity of
petroleum-derived fuels or end-use fuel switching and other flexibility mechanisms proposed in the
policy. ICF has compared these demand estimates to current low carbon fuel supply levels, as well
as projections for future supply levels. This comparison helps to illustrate whether supply capacity
as-is would be sufficient to meet low carbon fuel demand, and if not, to what extent supply capacity
or imports would need to grow to fill the gap. However, there are other important factors to consider
beyond this when understanding future low carbon fuel markets.
Heterogeneity of Low Carbon Fuels
In this study, low carbon fuels were treated homogenously by fuel type. In reality, the costs and
physical properties of low carbon fuels vary depending on the feedstocks utilized and the conversion
process technology. Two important physical properties are the carbon intensity and the energy
density of the low carbon fuels relative to their petroleum-derived counterparts. The lower the carbon
intensity of the fuel, the lower the volume fuel is required to meet the emission reduction
requirements. Conversely, the lower the energy density of the low carbon fuel, the higher the volume
of low carbon fuel would be required to meet the overall energy demand. As ECCC has not yet
related their carbon intensity calculator for CFS, ICF selected the most appropriate carbon intensity
data that was available for Canada in context of the CFS. Future research exploring the supply by
low carbon fuel type and the demand for low carbon fuels with respect to cost and carbon intensity is
needed to fully understand how this heterogeneity would impact market dynamics.
Carbon Intensity and Time
Beyond the static carbon intensity, one must consider how the carbon intensity may change over
time. In this study, ICF assumed that the GHG intensity for low carbon fuels would remain constant
from 2020 to 2030. However, it is possible that the average carbon intensity for different low carbon
fuel types could change over time. The CFS could incentivize producing low carbon fuels with the
lowest carbon intensity – or improving production processes to achieve this end – which would result
in the carbon intensity of low carbon fuels decreasing over time. Conversely, if low carbon
feedstocks are utilized to their full extent, production may need to utilize less-optimal feedstocks
which have a higher carbon intensity, resulting in the carbon intensity of low carbon fuels increasing
over time.
Competition for and Availability of Feedstocks
Globally there is no precedent for a combined low carbon fuel standard for liquid, gaseous, and solid
fuels. Another important consideration is the dependence of supply on feedstock availability. Both
virgin and waste feedstocks can be used to produce different types of fuels. For example, used
cooking oil (a waste feedstock) and canola oil (a virgin feedstock) can both be used to produce
biodiesel, renewable diesel, and renewable jet fuel. Thus, there will be competition around how to
use these different feedstocks and which low carbon fuel to produce from them. Furthermore, if
supply estimates for different fuel types are done in isolation, one must be cautious that they are not
double counting the feedstock available. This competition will be heightened if regions outside of
Canada introduce similar policies that incentivize the use of low carbon fuels. International
competition and increased demand would likely drive up the prices for low carbon fuels, and thus
increase the cost for CFS compliance.
4. Other CFS Considerations
17
Exhibit 11 (inspired by the Marine Industry Decarbonization Council’s graphic[14] with additional
data from NREL[15], ARC[16], and AGF[17]) is a non-exhaustive list that shows how different
feedstock groups can be used to produce different low carbon fuels. This highlights the issue of
competition regarding which fuel type a feedstock is chosen to produce.
Exhibit 11 Overview of Different Feedstock Conversion Pathways
Feedstock Fuel Precursor Low Carbon Fuel
Virgin Oil Crops
Vegetable Oil
Biodiesel
Renewable Diesel
Renewable Jet Fuel
Agricultural Residues RNG
Waste Materials
Waste Oil
Biodiesel
Renewable Diesel
Renewable Jet Fuel
Waste Solids, Gases, Liquids RNG
Sugar / Starch Crops
Sugar Ethanol
Alcohol Renewable Jet Fuel
Lignocellulosic Biomass Syngas
Ethanol
Renewable Diesel
Biodiesel
Renewable Jet Fuel
RNG
Wood extractives
Tall Oil
Renewable Diesel
Renewable Jet Fuel
Forestry Residues RNG
Algae Green Crude
Renewable Diesel
Renewable Jet Fuel
18
The previous paragraph describes the complexities of feedstock competition with respect to what
type of fuel the feedstock is used to produce. This can be an issue experienced by Canadian low
carbon fuel producers, as well as international producers. If demand for low carbon fuels rises
globally, demand for feedstocks will increase as well. It is possible that domestic feedstock
producers may sell to non-Canadian fuel producers, or Canadian fuel producers will see greater
value in supplying international markets, in all cases driving up compliance costs in Canada.
Treatment of Indirect Land Use Change
Indirect land use change (ILUC) quantifies the emissions associated with changing soil carbon stock
when land is changed to grow feedstocks for biofuels. Currently, the CFS does not include ILUC in
their quantification of low carbon fuel carbon intensity. This is a different approach than the California
Low Carbon Fuel Standard, which explicitly includes ILUC as an emissions source. The proposed
Canadian CFS may include land-use and biodiversity criteria in order to exclude certain feedstocks
that induce significant land use change, which would be similar to the European approach. The
result of excluding certain feedstock by either means would be a more limited supply of low carbon
fuels.
If the CFS were to take ILUC into account in in the carbon intensity quantification, there would be
two potential impacts. Firstly, including the ILUC would increase the carbon intensity of the fuels,
thus requiring a greater volume of low carbon fuel to be needed to meet the same emission
reduction target. The corollary of this is that if including ILUC increased the carbon intensity so much
that it no longer met the minimum 10% reduction rule in the CFS, then the fuel type would not be
eligible under CFS.
Renewable Natural Gas Infrastructure Challenges
Complexities related to natural gas transmission and distribution infrastructure will challenge the
introduction of low carbon fuels. Low carbon gaseous fuel production will be more disparate and
require processing and compression / liquefaction as well as transport and injection into systems not
designed for new receipt points.
19
5. Overview of Approach to Considering Future CFS Supply and
Demand
The main study results, presented in Section 6, first calculate the potential demand for different low
carbon fuels under the CFS. Then these potential low carbon fuel requirements are presented in the
context of current and future available supply, where possible. While the information available and
sources for supply varies significantly by fuel type (some biofuels have well established industries,
production of others is still limited), a consistent approach was used to calculate different low carbon
fuel demand scenarios under CFS.
Exhibit 12 outlines the approach taken to quantify potential biofuels demand. These steps are
explained below, while more details on the assumptions are provided in Appendix A.
Exhibit 12 Overview of Approach to Establishing Potential CFS Biofuels Demand
The Forecast of Demand for Fuels is based on the Canadian Energy Regulator (CER) Energy
Futures 2019 study. This forecast sees transportation fuel consumption declining gradually out to
2030, based on expected efficiency improvements, changes in Vehicle Kilometers Travelled, and a
low level of electric vehicle adoption. Some adjustments are made to align the CER forecast and fuel
categories to the biofuels to be considered in this study. For example, only domestic aviation fuel
consumption is considered under the CFS, so the amount included in this study is lower than the
CER total. Also, the CER forecast includes a separate biofuels demand forecast, and this has been
split up and added back into the diesel and gasoline pools, to reflect the total demand for those
products (some of which is already met by biofuels). After the adjustments are made, the resulting
reference case for fuels demand is shown in Exhibit 13.
Forecast of Demand
for Fuels
CFS GHG Intensity
Reduction Targets
High / Mid / Low
Biofuels Compliance
Scenarios
Emissions
Reductions Required
from Biofuels
GHG Intensities of
Biofuels
Biofuels Demand
5. Overview of Approach to Considering Future CFS Supply and Demand
20
Exhibit 13 Reference Case Fuels Demand [PJ]
The CFS GHG Intensity Reduction Targets were presented earlier in Exhibit 1, and correspond to
a carbon intensity reduction of approximately 13% by 2030.4F
v
However, the CFS includes multiple compliance categories, not all of which require the adoption of
biofuels. While this study only looks at the adoption of biofuels as low carbon fuels, the demand for
these fuels is shown for three ‘Low Carbon Fuels Compliance Scenarios’, to give context on the
relative level of demand that would exist.
▪ ‘High’ Scenario: All of the CFS GHG emission reductions (12 g CO2e/MJ) are met through
the adoption of low carbon fuels.5F
vi
▪ ‘Mid’ Scenario: Half of the CFS GHG emission reductions (5 g CO2e/MJ) are met through
the adoption of low carbon fuels.
▪ ‘Low’ Scenario: Only the CFS minimum blending requirements (5% gasoline, 2% diesel) are
met through low carbon fuels. This is actually below current low carbon fuel demand and
seems to be more of a ‘backstop’ within the regulations to avoid a drop-in biofuel use during
the transition to new regulations. For example, this could occur if global demand for low
carbon fuels drove up costs for these fuels, and other CFS mechanisms become more
affordable than low carbon fuel blending.
v Requires a 2.4 g CO2e/MJ reduction for all liquid fossil fuels in 2022, increasing by 1.2 g CO2e/MJ
annually to achieve a 10 CO2e/MJ carbon intensity reduction requirement in 2030.
vi See caveat about limitations explained in callout box above.
21
The previously described steps quantify the Emissions Reductions Required from Low Carbon
Fuels under different scenarios. However, most of the alternative fuels under consideration are ‘low
carbon’ fuels, but not ‘zero-carbon’ fuels. In order to calculate the corresponding Low Carbon Fuels
Demand, the GHG Intensities for each of the alternative fuel type are used. The green numbers
shown in Exhibit 14 are the GHG intensities used for the key low carbon fuels, and are primarily
based on research conducted by Navius.[18] The corresponding pink numbers show the emissions
intensity of the petroleum-derived fuels displaced by the low carbon options. The black band
highlights the range of GHG intensities from low carbon fuels.6F
vii Different conversion processes and
feedstocks will result in significantly different GHG intensities, which will have a significant impact on
the calculated requirements for low carbon fuels.
Exhibit 14 GHG Intensities of Key Low Carbon Fuels and the Petroleum-Derived Fuels they Replace
vii Very low carbon intensities are often associated with low carbon fuels which use wastes as a feedstock.
For example, municipal solid waste as a feedstock can include negative emission sources in the
emissions quantification due to avoided emissions from landfilling.
It should be noted that the demand scenarios consider the demand for low carbon fuels needed
to satisfy the emission reduction requirements from the CFS. The demand for these scenarios
does not consider potential limitations on blending requirements, seasonality, fuel station
limitations, automobile specifications, or other potential constraints. The demand shows the
amount of fuel needed to meet the compliance obligations. If practical constraints were to place
limitations on the amount of low carbon fuels used, the demand may be lower than what is
shown in this study.
These scenarios are illustrative of potential futures and are not predictions of what is most likely
to occur. ICF does not assign a likelihood of occurrence to any of the scenarios.
22
Overall, this represents a 52% reduction in emissions intensity for ethanol (the low carbon
alternative) compared to gasoline (the petroleum-derived baseline), 92% for biodiesel, 83% for
renewable diesel, 64% for renewable jet fuel, 25% for renewable propane, and 73% for renewable
fuel oil.
Renewable Natural Gas (RNG), which is not shown in the figure above, is assumed in this analysis
to have a lifecycle carbon intensity of zero. Individual RNG projects can range from as low as -410 g
CO2e/MJ to as high as 55 g CO2e/MJ (versus conventional natural gas around 62 g CO2e/MJ) based
on different processes and feedstocks. If the average carbon intensity of RNG deployed is above
zero, this would increase the volumes of RNG required to meet CFS requirements.
ICF notes that ECCC has interim carbon intensities for some fuels in the CFS.7F
viii Unlike the values
used by ICF from the Navius study, these interim ECCC values are not weighted by Canadian
consumption levels. Additionally, since the ECCC carbon intensities follow the California Air
Resources Board (CARB) methodology, it is likely that they include indirect land use change (ILUC),
which the CFS is explicitly excluding from the emissions quantification. ICF has elected not to use
the ECCC interim values, and instead use the values found to be specifically relevant to Canadian
consumption levels and the Canadian CFS methodology. ICF finds this approach to be most
appropriate course of action. Furthermore, this approach is conservative; if higher carbon intensities
are used, a greater volume of low carbon fuels would be needed.
The calculated Low Carbon Fuels Demand is presented for different fuel types in the next section
of this report. Along with demand, context is provided on existing levels fuel production capacity in
Canada, current levels of imports to Canada, as well as different estimates of potential future supply
levels.
viii These values include a carbon intensity of 49 for ethanol, 26 for biodiesel, and 29 for renewable diesel
(g/CO2e/MJ).
The carbon intensity of low carbon fuels varies depending on the feedstock and conversion
process. The representative values for low carbon fuel intensities that ICF used in this study are
conservative, as higher carbon intensities would result in a higher demand for low carbon fuels
than what is shown in this study. ICF tried to select values that best represent the mix of low
carbon fuels available in the Canadian market currently; however, this may change in the future
as supplies change. ICF used values that follow the ECCC methodology, such as excluding
indirect land use change from the emissions quantification.
23
6. Future Supply and Demand Scenarios
The demand for low carbon fuels was calculated under three CFS scenarios, as described in
Section 5.
The total demand for low carbon liquid fuels is visualized through bars in Exhibit 15 in petajoules
and in Exhibit 16 in billion L, along with the baseline biofuels demand from the CER Energy Futures
forecast, in the dotted orange line.
Exhibit 15 Demand for Low Carbon Liquid Fuels [PJ]
The demand scenarios in this study were created so that only low carbon intensity fuels
(Category 2) would be utilized to satisfy the total emission reductions required by the CFS.
Other compliance mechanisms (Category 1: reducing the carbon intensity of petroleum-derived
fuels, Category 3: end-use fuel switching) were not considered in this study. Introducing other
compliance mechanisms may result in a lower demand for low carbon fuels than shown in this
study.
6. Future Supply and Demand Scenarios
24
Exhibit 16 Demand for Low Carbon Liquid Fuels [Billion L]
This shows that the CFS has the potential to significantly increase the demand for biofuels – with the
High Demand scenario for 2030 requiring nearly 5 times the amount in the reference case for that
year. However, to truly understand the results, the supply and demand must be considered on a
fuel-by-fuel basis. Exhibit 17 illustrates the different low carbon fuels studied here and the
petroleum-derived fuels for which they would serve as an alternative. Exhibit 18 and Exhibit 19
then summarize the demand for different low carbon fuels, followed by sub-sections discussing each
of the key fuel types studied here.
Exhibit 17 Petroleum-Derived and Low Carbon Fuel Types
Gasoline• Ethanol
Diesel• Biodiesel
• Renewable Diesel
Natural Gas• Renewable Natural
Gas
Jet Fuel• Renewable Jet
Fuel
Propane
• Renewable Propane
Fuel Oil• Renewable Fuel Oil
25
Exhibit 18 Summary of Low Carbon Fuel Demand Results [PJ]
Fuel Scenario 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
Eth
an
ol
High 72 71 70 103 136 167 198 229 258 287 316
Mid 72 71 70 69 68 84 99 114 129 144 158
Low 72 71 70 69 68 67 66 65 64 64 63
Bio
die
se
l*
High 7 7 9 14 19 23 27 32 36 40 45
Mid 7 7 7 7 9 12 14 16 18 20 22
Low 7 7 7 7 7 7 7 7 7 7 7
Ren
ew
ab
le
Die
se
l*
High 7 7 10 16 21 26 30 35 40 45 49
Mid 7 7 7 8 10 13 15 18 20 22 25
Low 7 7 7 7 7 7 7 7 7 7 7
Ren
ew
ab
le
Na
tura
l
Ga
s
High - - - 55 110 166 224 281 337 393 453
Mid - - - 27 55 83 112 140 169 197 227
Low - - - 14 14 14 14 14 14 15 15
Ren
ew
ab
le
Je
t F
ue
l
High - - 4 6 8 10 12 14 16 18 21
Mid - - 2 3 4 5 6 7 8 9 10
Low - - 2 2 2 2 2 2 2 2 2
Ren
ew
ab
le
Pro
pan
e High - - 17 26 34 43 52 61 70 79 88
Mid - - 9 14 19 24 29 34 39 44 49
Low - - 3 3 3 3 3 3 3 3 3
Ren
ew
ab
le
Fu
el O
il High - - 5 8 10 13 15 18 20 23 25
Mid - - 3 4 5 6 8 9 10 11 13
Low - - 3 3 3 3 3 3 3 3 3
*Assumes 50/50 split between Biodiesel and Renewable Diesel in terms of emissions reductions
achieved, while Section 6.2 below presents a range for this split.
26
Exhibit 19 Summary of Low Carbon Fuel Demand Results [Billion L, except RNG in Billion m3]
Fuel Scenario 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
Eth
an
ol
High 3.0 2.9 2.9 4.3 5.7 7.0 8.3 9.5 10.8 12.0 13.2
Mid 3.0 2.9 2.9 2.9 2.8 3.5 4.1 4.8 5.4 6.0 6.6
Low 3.0 2.9 2.9 2.9 2.8 2.8 2.7 2.7 2.7 2.7 2.6
Bio
die
se
l*
High 0.2 0.2 0.3 0.4 0.6 0.7 0.8 1.0 1.1 1.2 1.4
Mid 0.2 0.2 0.2 0.2 0.3 0.4 0.4 0.5 0.5 0.6 0.7
Low 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2
Ren
ew
ab
le
Die
se
l*
High 0.2 0.2 0.3 0.5 0.6 0.7 0.9 1.0 1.2 1.3 1.4
Mid 0.2 0.2 0.2 0.2 0.3 0.4 0.4 0.5 0.6 0.6 0.7
Low 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2
Ren
ew
ab
le
Na
tura
l
Ga
s
High - - - 1.5 2.9 4.4 6.0 7.5 9.1 10.6 12.2
Mid - - - 0.7 1.5 2.2 3.0 3.8 4.5 5.3 6.1
Low - - - 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4
Ren
ew
ab
le
Je
t F
ue
l
High - - 0.1 0.2 0.2 0.3 0.3 0.4 0.4 0.5 0.6
Mid - - 0.1 0.1 0.1 0.1 0.2 0.2 0.2 0.3 0.3
Low - - 0.0 0.0 0.0 0.0 0.0 0.1 0.1 0.1 0.1
Ren
ew
ab
le
Pro
pan
e High - - 0.7 1.0 1.4 1.7 2.1 2.4 2.8 3.1 3.5
Mid - - 0.4 0.6 0.8 0.9 1.1 1.3 1.5 1.7 1.9
Low - - 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1
Ren
ew
ab
le
Fu
el O
il High - - 0.3 0.4 0.5 0.6 0.8 0.9 1.0 1.2 1.3
Mid - - 0.1 0.2 0.3 0.3 0.4 0.5 0.5 0.6 0.6
Low - - 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1
*Assumes 50/50 split between Biodiesel and Renewable Diesel in terms of emissions reductions
achieved, while Section 6.2 below presents a range for this split.
27
Exhibit 20 Summary of Low Carbon Fuel Demand Results [Volumetric Bending Rate, %]
Fuel Scenario 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
Eth
an
ol
High 7% 7% 7% 10% 14% 17% 20% 23% 26% 29% 32%
Mid 7% 7% 7% 7% 7% 9% 10% 12% 14% 15% 17%
Low 7% 7% 7% 7% 7% 7% 7% 7% 7% 7% 7%
Die
se
l P
oo
l T
ota
l*
High 2% 2% 3% 5% 6% 8% 9% 11% 12% 14% 15%
Mid 2% 2% 2% 2% 3% 4% 5% 5% 6% 7% 8%
Low 2% 2% 2% 2% 2% 2% 2% 2% 2% 2% 2%
Bio
die
se
l**
High 1% 1% 2% 2% 3% 4% 5% 5% 6% 7% 7%
Mid 1% 1% 1% 1% 2% 2% 2% 3% 3% 3% 4%
Low 1% 1% 1% 1% 1% 1% 1% 1% 1% 1% 1%
Ren
ew
ab
le
Die
se
l**
High 1% 1% 2% 2% 3% 4% 5% 6% 6% 7% 8%
Mid 1% 1% 1% 1% 2% 2% 2% 3% 3% 4% 4%
Low 1% 1% 1% 1% 1% 1% 1% 1% 1% 1% 1%
Ren
ew
ab
le
Na
tura
l
Ga
s
High 0% 0% 0% 1% 2% 4% 5% 6% 7% 9% 10%
Mid 0% 0% 0% 1% 1% 2% 3% 3% 4% 4% 5%
Low 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%
Ren
ew
ab
le
Je
t F
ue
l
High 0% 0% 6% 9% 12% 14% 17% 20% 22% 25% 28%
Mid 0% 0% 3% 4% 6% 7% 9% 10% 12% 13% 14%
Low 0% 0% 3% 3% 3% 3% 3% 3% 3% 3% 3%
Ren
ew
ab
le
Pro
pan
e High 0% 0% 12% 18% 24% 30% 36% 42% 48% 54% 60%
Mid 0% 0% 7% 10% 13% 17% 20% 23% 27% 30% 33%
Low 0% 0% 2% 2% 2% 2% 2% 2% 2% 2% 2%
Ren
ew
ab
le
Fu
el O
il High 0% 0% 3% 4% 6% 7% 8% 10% 11% 13% 14%
Mid 0% 0% 1% 2% 3% 3% 4% 5% 6% 6% 7%
Low 0% 0% 1% 1% 1% 1% 1% 1% 1% 1% 1%
* Sum of Biodiesel and Renewable Diesel volumes relative to total diesel requirements.
**Assumes 50/50 split between Biodiesel and Renewable Diesel in terms of emissions reductions
achieved, and this percentage compares the volume of each alternative diesel fuel to the total diesel pool
volume (Section 6.2 below presents a range for this split).
28
Exhibit 21 Summary of Low Carbon Fuel Demand Results [GHG Emission Reductions, kilotonnes CO2e]
Fuel Scenario 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 G
aso
lin
e High 3,434 3,387 3,340 3,294 6,511 8,021 9,497 10,946 12,370 13,770 15,151
Mid 3,434 3,387 3,340 3,294 3,256 4,011 4,748 5,473 6,185 6,885 7,575
Low 3,434 3,387 3,340 3,294 3,249 3,202 3,159 3,121 3,086 3,054 3,024
Die
se
l
High 1,298 1,288 1,745 2,594 3,430 4,251 5,060 5,861 6,639 7,425 8,209
Mid 1,298 1,288 1,273 1,262 1,715 2,126 2,530 2,930 3,319 3,712 4,105
Low 1,298 1,288 1,273 1,262 1,251 1,241 1,230 1,222 1,211 1,204 1,198
Jet
Fu
el High - - 213 322 432 545 659 775 892 1,011 1,131
Mid - - 107 161 216 272 329 387 446 505 566
Low - - 98 98 99 100 100 101 102 103 103
Fu
el O
il High - - 339 505 670 834 998 1,160 1,323 1,485 1,649
Mid - - 169 253 335 417 499 580 661 743 824
Low - - 211 209 208 207 207 206 205 205 205
Pro
pan
e High - - 342 513 687 861 1,038 1,216 1,397 1,581 1,767
Mid - - 171 257 343 431 519 608 699 790 884
Low - - 51 51 52 52 52 52 52 53 53
Na
tura
l
Ga
s
High - - - 3,378 6,779 10,238 13,838 17,361 20,830 24,315 28,016
Mid - - - 1,689 3,390 5,119 6,919 8,680 10,415 12,158 14,008
Low - - - 872 875 881 893 896 896 896 904
*Assumes 50/50 split between Biodiesel and Renewable Diesel in terms of emissions reductions
achieved, while Section 6.2 below presents a range for this split.
As noted in Section 5, ICF has used carbon intensities for some fuels that are lower than
interim values that ECCC has listed, producing a more conservative forecast of required
volumes of low carbon fuels. For example, if the higher ECCC factors were used, total liquid fuel
demand would be 512 PJ in the High Scenario in 2030 rather than 456 PJ, equivalent to 19.9
billion L versus 17.8 billion L. For ethanol in the high case, this would increase the blending rate
by volume by about 4% (from 32% to 36%), increasing the ethanol demand from 316 PJ to 352
PJ in 2030 (from 13.2 to 14.7 billion L). In the high case for 2030, this would increase biodiesel
demand from 45 PJ to 55 PJ (from 1.4 to 1.7 billion L), while renewable diesel demand would
increase from 49 PJ to 58 PJ (from 1.4 to 1.7 billion L). Overall in the high case, this would
increase the total required biodiesel and renewable diesel blending rate by about 3%, from 15%
to 18%, on a volumetric basis.
29
6.1 Gasoline Substitutes (Ethanol)
Ethanol has been blended with petroleum-derived gasoline as an automotive fuel for many years. In
Canada and the US, ethanol blending rates from 5% to 10% are found. Common ethanol feedstocks
in Canada include corn, wheat, barley, and sorghum.[18], [19]
Exhibit 20 shows in solid lines the potential Canadian demand for ethanol under three demand
scenarios from 2020 to 2030. These different demand scenarios are ‘non-cumulative’, and the
scenarios and calculation approach are discussed in Section 5. The dotted lines are cumulative and
aim to provide some context on current and potential future supply levels available to Canada, both
produced domestically and supply available from the US.
Exhibit 22 Ethanol Supply and Demands
30
In terms of the ethanol demand shown in Exhibit 20, the High Demand scenario (navy solid line)
represents 100% of the gasoline pool GHG emissions required through the CFS being met through
ethanol blending, and not from other compliance mechanisms. In contrast, the Mid Demand scenario
(blue solid line) represents ethanol demand if half the GHG emission reductions required are met
through ethanol blending, and half through other compliance mechanisms. In both those scenarios,
this is based on a static assumption for the GHG intensity of ethanol. On one hand, the CFS would
provide incentive for ethanol producers to lower the GHG intensity of their products, which could
reduce these requirements. But on the other hand, a significant expansion in ethanol demand
through the CFS might also require tapping into higher emission sources to meet demand.
In terms of the ethanol supply shown in Exhibit 20, based on data form the USDA, Canada
produced about 2 billion liters of ethanol in 2018 (dotted green line) and the US produced about 60
billion liters in 2018.[6], [7] In 2019, Canada produced about 60% of current ethanol domestically and
imported the remainder (dotted orange line). The US ethanol production capacity is greater than
their domestic demand. In 2018, US ethanol production was running at 97% capacity, meaning that
there is 3% of spare capacity available if their plants were run at full capacity (dotted pink line).8F
ix
Depending on how ethanol markets may change in Canada and abroad, for example the CFS
driving up ethanol demand and prices in Canada, the ethanol capacity that the US is currently using
to supply exports to other countries could potentially be diverted to Canada. This quantity, the US’
current non-Canadian exports (dotted blue line) is uncertain as it depends on future Canadian
policies, future US policies, and future international policies. These will all have an impact on
whether it is possible for Canada to import supply from the US, and for what price.
Overall, the US has a significant amount of spare ethanol capacity. It would appear that the excess
US spare capacity would be able to provide ethanol through imports to Canada to meet the new
CFS demand. However, this is contingent upon whether Canada will be able to afford to import from
the US, especially if US or international demand for US supply increases.
It appears that if ethanol demand were to significantly increase in Canada through the CFS, that
there would be adequate existing capacity based in the US to meet the new Canadian requirements
through ethanol imports. Thus, Canada may import the US’s readily available supply rather than
growing Canadian production capacity. Given that it is existing (already built) infrastructure, the US
capacity would likely have advantages in terms of cost-competitiveness and ability to match a quick
ramp- up in demand. Canada’s access to the US spare supply is dependent on US policies not
changing how domestic ethanol production is consumed in the US, as well as international policies
impacting ethanol demand.
Recall that current ethanol blending rates in Canada are between 5% to 10%. In the High Demand
scenario, blending ethanol with gasoline would result in a 25% blending rate on an energy basis and
a 32% blending rate on a volumetric basis by 2030. In the Mid Demand scenario, blending levels
would be at 13% on an energy basis and 17% on a volumetric basis by 2030. This difference
between energy and volumetric blending rates is due to differences in energy densities between the
two fuels.
ix Not included here, but worth mentioning that from 2014 to 2017 US ethanol production was above the
rates capacity of facilities (102%-105%), as some facilities have the ability to produce beyond their official
rating. This means that if demand for ethanol was high, there may be more than 3% spare capacity that
could be leveraged from US plants.
31
Studies have conflicting results regarding the feasibility of ethanol blending above 15%[20], thus
making blending limits a contentious issue.[21] The US Environmental Protection Agency (EPA) has
certified that vehicles in the US fleet made in 2001 or later are E15 compatible, allowing (but not
requiring) up to 15% of ethanol blended with gasoline being sold for cars and light-duty pickup trucks
made after that that year. However, vehicle manufacturers have not started including the usage of
E15 under warranty coverage until models for more recent years.
6.2 Diesel Substitutes (Biodiesel & Renewable Diesel)
Low carbon fuel alternatives to diesel include renewable diesel and biodiesel. Biodiesel is a more
established biofuel, while renewable diesel is a new option with much more limited production
capacity. Renewable diesel is more chemically and physically similar to petroleum-derived diesel
than biodiesel. The production of biodiesel introduces oxygen, which makes it chemically distinct
from petroleum-derived diesel. Although renewable diesel is considered a “drop-in” fuel alternative to
diesel (avoids concerns about blending levels), it is more expensive and more emissions intensive to
produce than biodiesel.[10] Common renewable diesel feedstocks include virgin oils (canola, corn,
soy) as well as waste oils (tallow, yellow grease) [18], [19]. Some petroleum refiners are also
beginning to explore producing ‘co-processed’ renewable diesel at existing refineries.
Fuel markets will decide the proportion of adoption of biodiesel and renewable diesel as alternatives
to petroleum-derived diesel under the CFS. Exhibit 21 shows four figures, in order to demonstrate
the requirements from CFS with different levels of compliance through biodiesel vs. renewable
diesel. The top two figures show biodiesel supply and demand in two cases – on the left biodiesel
makes up all of the low carbon diesel alternative fuel, and on the right it makes up halves. The two
bottom figures show renewable diesel supply and demand for the same two demand cases. The
solid non-cumulative lines show the Canadian demand for low carbon diesel under three scenarios
from 2020 to 2030 (discussed Section 5). The dotted lines are cumulative and show current and
future supply available to Canada, both produced domestically and supply available from the US.
Ultimately, given that biodiesel is lower cost, has a lower GHG intensity, and is a more established
fuel, it is likely to make up a greater portion of the CFS demand – up to the vehicle and temperature
imposed blending limits for biodiesel. These limitations are discussed later in this section.
32
Exhibit 23 Supply and Demand for Low Carbon Diesel at Different Split Levels
Biodiesel 100% (Renewable Diesel 0%) Biodiesel 50% (Renewable Diesel 50%)
Renewable Diesel 100% (Biodiesel 0%) Renewable Diesel 50% (Biodiesel 50%)
33
Based on data from the USDA, Canada produced about 300 million liters of biodiesel in 2018 and
the US produced about 7 billion liters.[6], [7] In 2019, Canada produced about 55% of the biodiesel
domestically and imported the remainder (green and orange dotted lines). In 2018, the US produced
more biodiesel than it consumed, with a spare capacity of about 3% (pink dotted line). The US has
exported between 6% to 14% of their biodiesel production since 2010.[7] Canada’s portion of US
biodiesel exports was about 20%. Depending on how biodiesel markets may change in Canada and
abroad, a greater portion of the biodiesel that the US is exporting could be diverted to Canada. The
United States is by far the largest supplier of biodiesel to Canada, but some biodiesel is also
imported from Europe, primarily Germany, and also from Argentina.[6]
Canada did not produce renewable diesel in 2018 (dotted green line) while the US produced about
750 million liters.[6], [7] In 2019, Canada was importing 100% of their renewable diesel demand
(dotted orange line). In addition to their domestic production, the has had to US to import renewable
diesel to meet their demand. Thus, ICF does not consider the US to have spare capacity available.
The US exports less renewable diesel than Canada’s demand. Canada has imported renewable
diesel from Singapore, the Netherlands, Finland, and the United States.[6]
Recall that the current low carbon diesel blending rates in Canada are between 2% to 4%. Note that
for this study, ICF has assumed that biodiesel and diesel each make up half of the low carbon fuel
energy required to meet the diesel pool emission reduction targets. Together, blending low carbon
diesel would result in a 14% blending rate on an energy basis and a 15% blending rate on a
volumetric basis by 2030 in the High Demand scenario. In the Mid Demand scenario, blending levels
would be at 7% on an energy basis and 8% on a volumetric basis by 2030. If biodiesel were to make
up half of the low carbon diesel pool, blending would result in a 6.5% blending rate on an energy
basis and a 7.5% blending rate on a volume basis by 2030 in the High Demand scenario, and a
3.8% blending rate on an energy basis and a 3.3% blending rate on a volume basis by 2030 in the
Mid Demand scenario. If renewable diesel were to make up half of the low carbon diesel pool,
blending would result in a 7.2% blending rate on an energy basis and a 7.9% blending rate on a
volume basis by 2030 in the High Demand scenario, and a 3.6% blending rate on an energy basis
and a 4.0% blending rate on a volume basis by 2030 in the Mid Demand scenario. This difference
between energy and volumetric blending rates is due to differences in energy densities between the
two fuels.
The cloud point – a common measure for a fuel’s cold weather performance – of all diesel fuels vary
depending on their composition. The lower the cloud point, the lower the operating temperature
under which a fuel can perform successfully. Petroleum-derived diesel fuels are blended with
kerosene to ensure minimum temperature requirements are met during different seasons and in
different regions. Similarly, the cloud point of biodiesel or renewable diesel must be considered when
blending with petroleum-derived diesel to ensure that the cloud point of the overall product is
suitable.[10] The type of feedstock used influences the cloud point of biodiesel while the production
process plays a bigger role in the cloud point of renewable diesel. Generally, biodiesel has a higher
cloud point than renewable diesel. This can be mitigated through blending plans for the winter
season, but the requirement for a seasonal drop in blending levels would limit the overall annual
average blending level. Blending rates between 5% to 20% have been used in Ontario. The
University of Toronto recommends that blending rates of 5% could be used in the winter, 10% in the
spring and fall, and 20% in the summer in Toronto.
34
Another technical consideration about the operability of low carbon diesel alternatives is their
compatibility with existing engines. According to the US DOE in 2020, most engines are warrantied
up to around 20%.[22] However, this is a contentious issue and warrants further investigation,
potentially through consultations with the automobile manufacturing industry.
Overall, the US has some spare ethanol capacity of biodiesel, but not of renewable diesel. If low
carbon diesel demand were to increase in Canada, it is possible that costs for Canada to import from
the US’s extra supply may be lower than growing Canadian production capacity. Even if some of
Canada’s need for low carbon diesel is met through imports form the US, additional production
capacity will be needed to meet the entire demand. Depending on US and international policies,
Canada’s access to US low carbon fuels may be limited.
In the following sections, renewable fuels that can be produced as co-products of the biodiesel and
renewable diesel production processes are discussed. Renewable fuel oil can be collected from the
biodiesel production process as longer hydrocarbon chains from the distillation process, estimated to
be about 5% of the biodiesel yields. Typical renewable diesel product slates are optimized to
produce about 15% renewable jet fuel and 10% renewable propane, but these splits can vary
significantly with different production technologies.
6.3 Natural Gas Substitutes (Renewable Natural Gas)
Low-carbon-intensity fuels in the gaseous stream announced to date include hydrogen, biogas,
renewable natural gas (RNG), and renewable propane. It is expected that the RNG will be a primary
source of low carbon fuels to meet requirements under the gaseous stream in the 2023-2030
timeframe.[1]
The Alberta Research Council (ARC) published a study in 2010 that identified the primary
feedstocks identified for RNG in Canada as agricultural, forestry and municipal waste streams. The
largest feedstock source is forestry biproducts from wood harvesting and milling, this makes up 51%
of potential feedstock. Municipal waste including both solid waste from landfill and biosolids from
wastewater treatment plants and contribute 36% of the potential feedstock. Agricultural waste makes
up the remaining 13%.[16]
The 2010 ARC study considered RNG production using two technologies, anerobic digestion and
gasification. The use of gasification provided
84% of the total potential estimated with the
remaining 16% coming from anerobic digestion
processes.[16]
The most common way to produce RNG today
is through anerobic digestion where
microorganism breakdown organic material in
an environment without oxygen to produce CH4
and CO2. Gasification includes a broad range
of processes whereby a carbon containing
feedstock is converted into a mixture of gases
referred to as synthetic gas or syngas.
A third technology available is Power to Gas
(P2G). This technology includes a broad range
of processes whereby a carbon containing
feedstock is converted into a mixture of gases
referred to as synthetic gas or syngas.
Exhibit 24 RNG Technical Potential by Technology
35
Although this technology is proven, it is not yet commercialized. The first utility-scale facility in North
America was built in Ontario and became operational in 2018. ICF has not identified any
quantification of technical potential for this technology in Canada.
Throughout the analysis we have applied a carbon intensity of zero for RNG. We note that there is
some variability in carbon intensity for RNG, with some carbon intensities above and below zero or
equal to zero. RNG sources published within CARB range from 46 to -276 gCO2e/MJ.[23] These
values will vary by region and Exhibit 24 includes an even wider range, illustrating how the carbon
intensity of RNG can vary based on different production technologies and feedstocks. An average of
zero carbon intensity is generally accepted for RNG and both Enbridge Gas and FortisBC consider
RNG to be carbon neutral.[24], [25] If the average carbon intensity of RNG deployed is above zero,
this would increase the volumes of RNG required to meet CFS requirements.
Exhibit 25 Lifecycle GHG Emission Factor Ranges for RNG Feedstocks[26]
36
The CFS targets for liquid fuels are more certain than those for gaseous fuels. Currently, the interim
(placeholder) reduction target for natural gas in the CFS is 0.3%. Exhibit 23 visualizes how this
target, as well as more aggressive targets, would impact the petroleum-derived natural gas demand.
Exhibit 26 Potential Gaseous Stream Targets
37
Exhibit 24 shows in solid non-cumulative lines the Canadian demand for RNG under three
scenarios from 2020 to 2030. The dotted lines are cumulative and show the future supply potential in
Canada and 2018 Canadian Capacity for RNG. To date only a small number of pipeline-injected pilot
projects have been developed in Canada, with total RNG production identified representing about 5
PJ (dotted green line).[27] Canada’s future technical potential for RNG from anerobic digestion is
about 245 PJ (not shown on graph). Evaluating the potential supply relative to the demand, future
technical potential of anaerobic digestion technology may be sufficient to meet the medium target of
5% reduction if all available anaerobic digestion resources were deployed. Any additional reductions
would have to come from gasification or P2G technologies which are not yet commercialized in
Canada.
Exhibit 27 Renewable Natural Gas Supply and Demand
38
Exhibit 25 shows that the future supply of RNG in North America is uncertain, highlighting low and
high resource scenarios for resource potential in the US. These supply lines are not cumulative. A
recent study from the US RNG supply between 2025 and 2040 indicates that between 680 to 2,200
PJ of RNG could be available in 2030.[17] There is less publicly available research on Canada’s
future RNG supply. The 2010 ARC study indicates that at an unknown future year, it is technically
feasible that about 250 PJ of RNG could be produced through anaerobic digestion and about 1,300
could be produced through gasification.[16] However, anaerobic digestion is a more mature
technology than gasification. Thus, there is uncertainty regarding these future projections. Additional
study is underway at Natural Resources Canada, but the results are not yet public.
Exhibit 28 Future Supply Projections for RNG in North America
RNG costs vary significantly depending on the project type, scale and location. Costs range from
$8/GJ to $15-20/GJ.[27] Compared to fossil fuel based natural gas, costs of RNG even at the low
end of the estimates are significantly higher. The Average AECO-C price for 2018 was $1.48/GJ.[28]
For illustrative purposes $8/GJ RNG would be over $6/GJ more expensive or more than 5 times the
cost. Using the carbon intensities evaluated in the analysis the blended cost increases the cost by
up to 30%. The Canadian Energy Research Institute released a study in 2019 which evaluated the
impact of decarbonization of the Canadian fuel supply. The CERI modeling indicated a price
increase of 58% relative to the baseline costs for natural gas.[5]
When compared to other renewable energy sources the cost of RNG is relatively low. Other low
carbon fuels such as hydrogen which can be blended directly into the gas supply or P2G which can
be sourced from renewable electricity are not commercially available in Canada and therefore our
appreciation of cost in Canada is limited. As part of study completed by ICF for the American Gas
Association, ICF quantified the cost of gasification at 18 - 46 $USD per GJ. Other traditional
renewable energy sources such as solar and wind electricity are generally more expensive on a per
GJ basis. Canada’s Energy Futures quantified costs of $36 for solar generation and $15 for wind
generation per GJ in 2016 levelized Canadian dollars, although costs for the commodities are
expected to continue to decrease.[29]
39
6.4 Jet Fuel (Renewable Jet Fuel)
Renewable jet fuels (RJF) are made to a suitable quality so that they can be blended or entirely
substituted with petroleum-derived jet fuel. RJF can be produced form a variety of feedstocks and
production methods.[30] Successful demonstration flights were first conducted in 2008, with
commercial flights starting in 2011.[31] Despite the technical feasibility, uptake has been small (less
than 1% of global aviation fuels) due to high prices, limited production capacity, and a lack of policy
support.[32]
Exhibit 26 shows in solid non-cumulative lines the Canadian demand for RJF under three scenarios
from 2020 to 2030 given the adoption of CFS for domestic aviation. The dotted lines are cumulative
and show current and future supply available to Canada, both produced domestically and supply
available in the US.
Exhibit 29 Renewable Jet Fuel Supply and Demand
ICF could not find documentation of any RJF production capacity in Canada (dotted green line).
Recent literature indicates that the US makes up about 25% of the world’s RJF production capacity
at about 10 million liters.[33] Based on typical export levels of US biofuels to Canada, ICF estimates
that about 5% of the 2019 US production capacity may be available to supply Canada (dotted
orange line).
Blending renewable jet fuel would result in a 22% blending rate on an energy basis by 2030 in the
High Demand scenario, and a 11% blending rate in the Mid Demand scenario.
Depending on how the product slate is designed, RJF could make up between 15% to 75% of co-
products from renewable diesel facilities.[32] Production processes may come online which solely
produce RJF, thus cutting the supply dependence on renewable diesel.
Due to RJF’s low market penetration rate, there is significant uncertainty regarding future supply.
Canada’s CFS and ICAO’s CORSIA policy are set to come into effect in the early 2020s, which
could change the market dynamics for RJF. Thus, although ICF could not find documentation of
plans for future RJF production capacity in Canada, this may change between now and 2030.
40
6.5 Propane (Renewable Propane)
Renewable propane (also known as bio propane or bio LPG) is chemically identical to petroleum-
derived propane, except that it is derived from a biogenic source.[33] Renewable propane currently
makes up less than 1% of the propane (LPG) market.
Technically, propane is classified as a gas under the CFS, and is thus tied to the gaseous emission
reduction targets. Since renewable propane can be produced as a by-product of liquid low-carbon
fuel processes, ICF conducted our demand analysis of propane with liquid emission reduction target
levels as an upper bound.
Exhibit 27 shows in solid non-cumulative lines the Canadian demand for renewable propane under
three scenarios from 2020 to 2030 given the adoption of CFS. This includes propane demand from
the transportation, residential, and commercial sectors. The dotted lines are cumulative and show
current and future supply available to Canada, both produced domestically and supply available from
the US.
Exhibit 30 Renewable Propane Supply and Demand
ICF could not find documentation of any renewable propane production capacity in Canada (dotted
green line). Recent literature indicates that the US makes up about 5% of the world’s renewable
propane production capacity at about 20 thousand tons.[33] Based on typical export levels of US
biofuels to Canada, ICF estimates that about 5% of the 2019 US production capacity may be
available to supply Canada (dotted pink line).
To meet emission reduction targets for propane, renewable propane would have to replace liquid
propane entirely in the High Demand scenario. This is due to the relatively high carbon intensity of
renewable propane – and thus the low emission reduction relative to the petroleum-derived
counterpart – which means that a greater amount of the fuel must be used in order to meet blending
the emission reduction targets. In the Mid Demand scenario, the blending rate would be 50% on an
energy basis by 2030. Since renewable propane is still a more nascent fuel, the carbon intensity
could decrease as commercialization continues.
41
6.6 Heating Oil (Renewable Fuel Oil)
Renewable fuel oil (RFO) has similar combustion properties to current petroleum-derived distillate
fuel oils.[34] Petroleum-derived fuel oils have also been blended with biodiesel and renewable diesel
successfully in stationary heating applications. Since renewable fuel oil is still in the early stages of
development, ICF assumed that renewable fuel oil could be used as an alternative for both heavy
and light petroleum-derived fuel oil.
Exhibit 28 shows in solid non-cumulative lines the Canadian demand for RFO under three scenarios
from 2020 to 2030 given the adoption of CFS. This includes light and heavy fuel oil demand from the
transportation, residential, and commercial sectors. The dotted lines are cumulative and show
current and future supply available to Canada, both produced domestically and supply available from
the US.
Exhibit 31 Renewable Fuel Oil Supply and Demand
The USDA estimates that there is about 13 million gallons of RFO produced in Canada (dotted
green line). ICF could not find documentation of any RFO production capacity in the US.
Blending renewable fuel oil would result in an 23% blending rate on an energy basis by 2030 in the
High Demand scenario, and an 10% blending rate in the Mid Demand scenario.
42
Appendix A: Detailed Methodology & Assumptions
Section 5 provided an overview of the methodology, while this appendix provides additional details
on assumptions that were made as part of the study in order to model the potential impacts of CFS
rollout across Canada.
Scoping of Fuels
The CFS applies differently to different fuel types. ICF used reference case fuel demands from the
Canadian Energy Regulator (CER) Energy Futures 2019 study. This provides historic and future fuel
consumption by sector and fuel type.
In the transportation sector, road fuels (diesel, gasoline, and propane) are all covered under the
CFS. In addition to these petroleum-derived transportation fuels, the CER also tracks biofuels. ICF
disaggregated the biofuels into gasoline (75%) and diesel (25%) demand based on current
consumption data from the USDA[6], in order to more accurately capture the full demand for
gasoline and diesel transportation fuels (this biofuel consumption results from blending with gasoline
and diesel, and is not purchased on its own).
For aviation fuels, only domestic travel is covered under the CFS. ICF utilized data from Annual
Reports on Canada’s Action Plan to Reduce Greenhouse Gas Emissions from Aviation to estimate
the share of international versus domestic aviation. On a fuel basis, about 30% of Canada’s air travel
in 2018 was domestic.[35]
Similarly, only domestic marine travel (heavy fuel oil) is covered under the CFS. Using data from
Transport Canada’s Annual Reports, ICF estimated that about 15% of Canada’s marine travel is
domestic.[36]
The CER tracks lubricants as a transportation fuel as well. This was excluded from the liquid fuel
analysis as it is not covered under CFS. Industrial sector refined petroleum products were also
excluded, given that a large portion of this demand was expected to include on-site consumption of
by-products (eg. at refineries), or used for non-combustion purposes or feedstocks, all of which
would not be covered by CFS.
For the liquid fuels in the commercial and residential sectors, the CER tracks refined petroleum
products, but not by type. ICF disaggregated these into fuel types based on data from Natural
Resource’s Canada’s Comprehensive Energy Use Database.[37] ICF estimated that 75% of the
residential liquid fuels are light fuel oil, with the remainder propane. ICF estimated that 40% of the
commercial liquid fuels are light fuel oil, with the remainder propane.
The natural gas considered in this study include natural gas consumed by the residential,
commercial, industrial, and transportation sector.
Appendix A: Detailed Methodology & Assumptions
43
Based on the above assumptions which slightly alter the CER projections, the reference case fuel
demand in this study tabulated below (visualized earlier in Exhibit 13).
Fuel [PJ] 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
Heating Oil
137 136 135 135 134 133 133 133 132 132 132
Aviation Fuel
88 88 89 89 90 91 91 92 93 94 94
Diesel 741 709 701 695 689 683 678 673 667 663 660
Heavy Fuel Oil
6 6 6 6 6 6 6 5 5 5 5
Gasoline 1,434 1,414 1,395 1,375 1,356 1,337 1,319 1,303 1,289 1,275 1,263
Propane 143 143 142 143 143 144 144 145 146 146 147
Natural Gas
4,310 4,336 4,344 4,373 4,388 4,418 4,478 4,495 4,494 4,497 4,533
ICF’s demand estimates in the table above are based on a reference case transportation fuel
consumption forecast from the Canadian Energy Regulator Energy Futures study, which sees
gasoline and diesel demand dropping. The CER’s forecasted decline is expected to mostly be the
result of efficiency improvements, but the forecast does also include a low level of transportation
electrification. It should be noted that this analysis has not attempted to back-calculate what
reference case gasoline or diesel demand would be in the absence of that low level of vehicle
electrification. If that had been done, these demand scenarios would then be based on higher levels
of gasoline demand and would show higher ethanol requirements. It should also be noted that this
low level of reference case transportation electrification from the CER also has not been used by ICF
to lower the ethanol requirement in the High Demand scenario to account for some level of CFS
emission reductions being met by credits given for EV adoption. Instead, this analysis focuses on
giving context to potential low carbon fuel demand, drawing the boundary conditions for where
demand could fall, and avoids getting into a separate analysis on the relative merits of low carbon
fuel adoption versus other CFS compliance options (fuel switching, reducing petroleum-derived
carbon intensity).
Emission Reduction Targets
Per the CFS, there is a mandated emission reduction target of 12 g CO2e/MJ for each liquid fuel type
by 2030. This reduction is displayed annually and cumulatively, plus applied to key liquid fuels.
Fuel 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
Liquid Fuel Mandated Reduction Targets
Annual 0 2.4 1.2 1.2 1.2 1.2 1.2 1.2 1.2 1.2
Cumulative 0 2.4 3.6 4.8 6 7.2 8.4 9.6 10.8 12
Liquid Fuels
Gasoline 92.0 89.6 88.4 87.2 86.0 84.8 83.6 82.4 81.2 80.0
Diesel 100.0 97.6 96.4 95.2 94.0 92.8 91.6 90.4 89.2 88.0
Heavy Fuel Oil
99.0 96.6 95.4 94.2 93.0 91.8 90.6 89.4 88.2 87.0
44
Fuel 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
Light Fuel Oil
84.0 81.6 80.4 79.2 78.0 76.8 75.6 74.4 73.2 72.0
Jet fuel 86.0 83.6 82.4 81.2 80.0 78.8 77.6 76.4 75.2 74.0
Gaseous Fuel Mandated Reduction Targets
Annual 0 0.2 0 0 0 0 0 0 0 0
Cumulative 0 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2
Gaseous Fuels
Natural Gas 62.0 61.8 61.8 61.8 61.8 61.8 61.8 61.8 61.8 61.8
Propane 75.0 74.8 74.8 74.8 74.8 74.8 74.8 74.8 74.8 74.8
For gaseous fuels, the placeholder target for natural gas is blending 0.3% of with renewable natural
gas, with more stringent targets expected to be announced as the regulations are developed.
GHG Intensities of Low Carbon Liquid Fuels
The GHG intensities (g CO2e/MJ) of low carbon fuels vary depending on the feedstock and
conversion process utilized, as visualized earlier in Exhibit 14. The data behind this figure is shown
in the table below. The first value for each fuel is used in the analysis, and the values in parentheses
provide context on the range that exists for different processes and feedstocks.
Fuel Low Carbon Fuel Intensities
Sources
Ethanol 44.1 (0.9 – 81.6) BC Low Carbon Fuel Standard[38]
GHGenius v 5.0f[19]
Navius[18] Biodiesel 8.0 (0.2 – 99.0)
Renewable diesel 16.9 (3.6 – 94.6)
Renewable jet fuel 31.1 (6.0 – 72.0) Literature[30]
Renewable propane 55.0 (45.0 – 65.0) 9F
x California Low Carbon Fuel Standard[39]
GREET[40] Renewable fuel oil 24.4 (21.2 – 27.3) viii
Renewable Natural Gas
0 (-410 to 55) Zero is generally accepted average. Individual feedstock ranges are from GREET model, CARB’s modified California GREET model, and ICF analysis[26]
Recall that the ECCC interim values include a carbon intensity of 49 for ethanol, 26 for biodiesel,
and 29 for renewable diesel (g CO2e/MJ) using CARB values which include indirect land use change
(which the CFS would exclude).
x Carbon intensities specific to these low carbon fuels could not be found via the Canadian methodology
so US values which include ILUC were used instead.
45
Energy Density
In order to convert between the energy demand for fuel types and the volumetric low carbon fuel
supply, the following energy densities (MJ/L) were used based on multiple sources.[41]–[43]
Low Carbon Fuel Energy Density Petroleum-Derived Fuel Energy Density
Ethanol 24 Gasoline 25
Biodiesel 33 Diesel 39
Renewable diesel 35
Renewable jet fuel10F
xi 37 Jet Fuel 37
Renewable propane xi 25 Propane 25
Renewable fuel oil xi 37 Fuel Oil 37
Co-Product Splits
Like petroleum-refining, multiple fuels are often produced simultaneously. The product slate can vary
depending on the configuration of the plant. In this study, three fuel groups were considered.
Ethanol plants were considered in isolation. Biodiesel plants were considered to produce renewable
fuel oil as well, with a 95% and 5% split of the product slate respectively, based on expert
consultation. Renewable diesel plants were considered to produce renewable propane and
renewable jet fuel. For this study, the product slate was considered to produce 75% renewable
diesel, 15% renewable jet fuel, and 10% renewable propane.[32]
xi Energy densities specific to these low carbon fuels could not be found so petroleum-derived values
were used instead.
46
Appendix B: References
[1] Environment and Climate Change Canada, “Clean Fuel Standard Proposed Regulatory Approach,” 2019. [Online]. Available: https://www.canada.ca/content/dam/eccc/documents/pdf/climate-change/pricing-pollution/Clean-fuel-standard-proposed-regulatory-approach.pdf.
[2] Canada West Foundation, “WHAT NOW? | Lessons Learned?: Canada’s new Clean Fuel Standard,” 2019.
[3] Environment and Climate Change Canada, “CFS Technical Working Group Consultations.” 2020.
[4] Environment and Climate Change Canada, “Clean Fuel Standards Information Webinar, January 30, 2017.” 2017.
[5] C. for C. and E. Solutions, “Canadian Provincial Renewable Fuel Standard,” 2020. https://www.c2es.org/document/canadian-provincial-renewable-fuel-standard/.
[6] U. S. D. of Agriculture, “Annual Report on Biofuels in Canada,” 2019. [Online]. Available: https://apps.fas.usda.gov/newgainapi/api/report/downloadreportbyfilename?filename=Biofuels Annual_Ottawa_Canada_8-9-2019.pdf.
[7] U. S. D. of Agriculture, “Annual Report on Biofuels in USA,” 2020.
[8] E. P. Agency, “Overview for Renewable Fuel Standards,” 2017. https://www.epa.gov/renewable-fuel-standard-program/overview-renewable-fuel-standard.
[9] C. R. F. Association, “Canadian Ethanol Facilities,” 2015. http://ricanada.org/wp-content/uploads/2015/03/Canadian-Ethanol-and-Biodiesel-Facilities-Producer-Tables-for-Website.pdf.
[10] U. of Toronto, “Evaluation of the impact of using biodiesel and renewable diesel to reduce greenhouse gas emissions in the city of Toronto’s fleet vehicles,” 2019. [Online]. Available: https://www.toronto.ca/legdocs/mmis/2019/ie/bgrd/backgroundfile-130965.pdf.
[11] J. Leonard, “Renewable Diesel as a Major Heavy-Duty Transportation Fuel in California: opportunities, benefits and challenges,” 2017. [Online]. Available: http://learn.gladstein.org/whitepaper-renewablediesel.
[12] P. Quebec, “-6.01, r. 4.3 - Regulation respecting the quantity of renewable natural gas to be delivered by a distributor,” 2019. http://legisquebec.gouv.qc.ca/en/ShowDoc/cr/R-6.01, r. 4.3/ .
[13] G. of B. Columbia, “cleanBC Climate Strategy,” 2018. https://www2.gov.bc.ca/assets/gov/environment/climate-change/action/cleanbc/cleanbc_2018-bc-climate-strategy.pdf .
[14] M. I. D. Council, “Alternative Marine Fuels.” [Online]. Available: https://midc.be/alternative-marine-fuels/.
[15] N. R. E. Laboratory, “Review of Biojet Fuel Conversion Technologies,” 2016. [Online]. Available: https://www.nrel.gov/docs/fy16osti/66291.pdf.
[16] A. R. Council, “Potential Production of Methane from Canadian Waste,” 2010.
[17] I. American Gas Association, “Renewable Sources of Natural Gas,” 2019. [Online]. Available: https://www.aga.org/natural-gas/renewable/.
[18] Navius Research, “Biofuels in Canada 2019: tracking biofuel consumption, feedstocks and avoided greenhouse gas emissions,” 2019. [Online]. Available: https://www.naviusresearch.com/publications/2019-biofuels-in-canada/ .
[19] Squared Consultants Inc, “GHGenius model 5.0f.” 2020, [Online]. Available: https://www.ghgenius.ca/index.php/all-news.
References
47
[20] N. R. E. Laboratory, “Issues Associated with the Use of Higher Ethanol Blends (E17-E24),” 2002. [Online]. Available: http://www.nmma.org/lib/docs/nmma/gr/environmental/32206.pdf .
[21] T. I. C. on C. Transportation, “Technical Barriers to the Consumption of Higher Ethanol Blends,” 2014. [Online]. Available: https://theicct.org/sites/default/files/publications/ICCT_ethanol_revised_02_03_format.pdf.
[22] U. D. of E. – A. F. D. Center, “Biodiesel Blends,” 2020. [Online]. Available: https://afdc.energy.gov/fuels/biodiesel_blends.html.
[23] M. Bradley, “Renewable Natural Gas Report,” 2017. [Online]. Available: https://www.mjbradley.com/sites/default/files/MJB%26A_RNG_Final.pdf.
[24] Enbridge Gas, “Renewable Natural Gas,” 2020. .
[25] FortisBC, “Renewable Natural Gas,” 2020. .
[26] ICF, “Study on the Use of Biofuels (Renewable Natural Gas) in the Greater Washington, D.C. Metropolitan Area,” 2020. [Online]. Available: https://washingtongasdcclimatebusinessplan.com/wp-content/uploads/2020/04/200316-WGL-RNG-Report-FINAL.pdf.
[27] C. G. Association, “The Renewable Natural Gas Roadmap,” 2014. [Online]. Available: http://www.cga.ca/wp-content/uploads/2015/04/The-Renewable-Natural-Gas-Technology-Roadmap.pdf.
[28] Alberta Energy Regulator, “AECO-C Price,” 2019. https://www.aer.ca/providing-information/data-and-reports/statistical-reports/st98/prices-and-capital-expenditure/natural-gas-prices/aeco-c-price .
[29] C. E. Regulator, “Canada’s Energy Future 2018,” 2018. [Online]. Available: https://www.cer-rec.gc.ca/nrg/ntgrtd/ftr/2018/chptr4-eng.html.
[30] Biotechnology for Biofuels, “Life-cycle analysis of greenhouse gas emissions from renewable jet fuel production,” 2017. [Online]. Available: https://biotechnologyforbiofuels.biomedcentral.com/articles/10.1186/s13068-017-0739-7.
[31] International Energy Agency, “Biofuels Ready for Take-off,” 2019. [Online]. Available: https://www.iea.org/newsroom/news/2019/march/are-aviation-biofuels-ready-for-take-off.html.
[32] The International Council on Clean Transportation, “The cost of supporting alternative jet fuels in the European Union.” [Online]. Available: https://theicct.org/sites/default/files/publications/Alternative_jet_fuels_cost_EU_20190320.pdf.
[33] Atlantic Consulting, “Process Technologies and Projects for Bio-LPG,” 2019. [Online]. Available: https://www.mdpi.com/1996-1073/12/2/250/pdf.
[34] Brookhaven National Laboratory, “Evaluation of Biomass-Derived Distillate Fuel as Renewable Heating Oil,” 2015. [Online]. Available: https://www.bnl.gov/isd/documents/95113.pdf.
[35] T. Canada, “Canada’s Action Plan to Reduce Greenhouse Gas Emissions from Aviation,” 2019. [Online]. Available: https://www.tc.gc.ca/documents/2019-2020-AH-03_REPORT_E-Accessible.pdf.
[36] Transport Canada, “Annual Reports,” 2020. [Online]. Available: https://www.tc.gc.ca/eng/policy/anre-menu.htm.
[37] N. R. Canada, “Comprehensive Energy Use Database,” 2020. https://oee.nrcan.gc.ca/corporate/statistics/neud/dpa/menus/trends/comprehensive_tables/list.cfm.
[38] G. of B. Columbia, “Renewable & Low Carbon Fuel Requirements Regulation,” 2020. https://www2.gov.bc.ca/gov/content/industry/electricity-alternative-energy/transportation-energies/renewable-low-carbon-fuels .
[39] California Air Resources Board, “Low Carbon Fuel Standard Pathway Certified Carbon Intensities,” 2020. [Online]. Available: https://ww2.arb.ca.gov/resources/documents/lcfs-pathway-certified-carbon-intensities.
48
[40] Argonne National Laboratory, “GREET Model.” 2019, [Online]. Available: https://greet.es.anl.gov/.
[41] Berkley, “Fuel Energy Density,” 2020. [Online]. Available: http://w.astro.berkeley.edu/~wright/fuel_energy.html .
[42] Envergent, “Renewable Fuel Oil - A Commercial Perspective,” 2012, [Online]. Available: https://www.energy.gov/sites/prod/files/2014/03/f14/pyrolysis_lupton_0.pdf.
[43] Wikipedia, “Energy Content of Biofuel,” 2020. https://en.wikipedia.org/wiki/Energy_content_of_biofuel .
![3.Liquid Fuels[1]](https://img.pdfslide.us/doc/110x75/577cc79f1a28aba711a17e01/3liquid-fuels1.jpg)
