Vol. 145, No. 9 — February 26, 2011

ARCHIVED — Regulations Amending the Renewable Fuels Regulations

Statutory authority

Canadian Environmental Protection Act, 1999

Sponsoring department

Department of the Environment

REGULATORY IMPACT ANALYSIS STATEMENT

(This statement is not part of the Regulations.)

Executive summary

Issue

Greenhouse gases (GHGs) are primary contributors to climate change. The most significant sources of GHG emissions are anthropogenic, mostly as a result of combustion of fossil fuels. The emissions of GHGs have been increasing significantly since the industrial revolution and this trend is likely to continue if no action is taken. Historical data indicates that emissions in 2008 were about 19% above the 1990 levels. The Government of Canada is committed to reducing Canada’s total GHG emissions by 17% from 2005 levels by 2020.

In 2008, GHG emissions from the transportation sector contributed around 27% to Canada’s inventory of emissions. Modelling results from Natural Resources Canada (NRCan) indicate that the use of renewable fuels in liquid petroleum fuel for transportation can contribute to GHG emission reductions on a lifecycle basis.

The Renewable Fuels Regulations (the Regulations), published in the Canada Gazette, Part II, on September 1, 2010, include provisions requiring an average 2% requirement for renewable content in diesel fuel and heating distillate oil but do not specify a start date for this requirement. This requirement was subject to the demonstration of technical feasibility under the range of Canadian conditions, which was assessed by NRCan through the National Renewable Diesel Demonstration Initiative (NRDDI). In consultation with Environment Canada, Agriculture and Agri-Food Canada and Transport Canada, seven demonstration projects were delivered by stakeholders with funding assistance from NRDDI. In addition to the demonstration projects, a study of the readiness of the Canadian petroleum distribution infrastructure was also conducted through the NRDDI. The technical information and experience gathered through the NRDDI projects lead to the conclusion that renewable diesel can meet the Canadian petroleum industry accepted standards, subject to timing considerations for infrastructure readiness. (see footnote 2)

Now that the technical feasibility has been demonstrated, Environment Canada is proposing to amend the Regulations to set a coming-into-force date of July 1, 2011, for the 2% requirement for diesel fuel and heating distillate oil.

Objectives

The proposed Regulations Amending the Renewable Fuels Regulations (the proposed Amendments) would set a date of coming into force of the 2% requirement for diesel fuel and heating distillate oil. The coming into force of this requirement would provide further reductions in greenhouse gas emissions, in addition to the reductions estimated from the 5% in gasoline requirement of the Regulations (see Figure 1 below). It would also establish a demand for renewable content in diesel fuel in Canada and provide the renewable fuels industry with the regulatory certainty needed to secure investments to build new production plants and ensure an adequate supply of renewable fuels for the Canadian market.

Figure 1: Estimated GHG Emissions Reductions from the Renewable Fuels Regulations

Description

The proposed Amendments

The Regulations already include full provisions to require fuel producers and importers of diesel fuel and heating distillate oil to have an average annual renewable fuel content equal to at least 2% of the volume of distillates that they produce and import. However, the Regulations do not specify a start date for this requirement. Section 10 of the proposed Amendments would amend subsection 40(3) of the Regulations to set a coming-into-force date of the 2% requirement for diesel fuel and heating distillate oil of July 1, 2011. This requirement leads to the following changes:

• Subsection 1(1) clarifies the definition of “pre-distillate compliance period” by explicitly including the exact dates, specifically from December 15, 2010, to June 30, 2011. This does not result in any change of the actual requirements; and
• Subsection 1(2) clarifies the definition of “distillate compliance period” by explicitly including the exact dates; specifically, the first compliance period is from July 1, 2011, to December 31, 2012. This does not result in any change of the actual requirements.

In addition, Environment Canada and industry stakeholders have identified some issues, minor inconsistencies and lack of clarity in parts of the regulatory text since the publication of the Regulations in the Canada Gazette, Part II. The proposed Amendments would also include the following revisions on that account:

• Subsection 2(1) corrects paragraph 4(7)(a) of the Regulations by removing the phrase “or report”. The various clauses referred to in paragraph 4(7)(a) do not cover reports;
• Subsection 2(2) adds a new subsection 4(9) to the Regulations which clarifies the rules on how the percentages of renewable fuel in petroleum fuel, determined for the purposes of the definition of “high-renewable-content fuel” or in subsection 17(1), are to be determined. Consistent with current industry standards, these percentages are to be rounded to the nearest whole number percentage or, if equidistant between two whole number percentages, to the nearest even whole number percentage;
• Section 3 revises the marginal note in the English version of subsection 8(2) of the Regulations from “Distillate” to “Distillate pool”, which aligns with the marginal notes for subsections 5(2) and 6(2) of the Regulations;
• Section 4 and subsection 5(1) remove the phrase “the description” from the English versions of definitions of RF_G and RF_D in subsections 21(2) and 22(2) of the Regulations. This phrase is superfluous;
• Subsection 5(2) adds a new subsection 22(4) to the Regulations which clarifies that excess distillate compliance units owned by a primary supplier at the end of the pre-distillate compliance period and that cannot be carried forward can only be used to meet the primary supplier’s gasoline requirement;
• Section 6 adds a new subsection 25(5) to the Regulations which clarifies that excess distillate compliance units owned by an elective participant at the end of the pre-distillate compliance period are cancelled. Subsection 7(3) and section 11 add recordkeeping and reporting requirements, respectively, for information regarding that cancellation to subsection 31(2) and Schedule 5 of the Regulations;
• Subsection 7(1) revises the wording of subsection 31(1) of the Regulations to clarify the requirement to make records in a compliance unit account book. As a consequence of those changes, subsection 7(2) changes “and” to “or” at the end of the English version of paragraph 31(1)(b) of the Regulations;
• Section 8 adds a new subparagraph 32(3)(a)(iii) to the Regulations providing for compliance units to be created for a two-step blending process that initially results in high-renewable-content fuel which is later re-blended into fuel that is no longer high-renewable-content fuel. Some companies are considering such two-step blending, particularly for biodiesel where B50 can be stored unheated and then re-blended to create B5; and
• Section 9 corrects the English spelling of “occurred” in paragraph 34(3)(e) of the Regulations.

Background

National context

Since 1980, the Government of Canada has supported the development of alternative fuels and has been active in the research and development of technologies and in the implementation of market-based programs (such as fiscal incentives and economic assistance) that encourage the production and use of renewable fuel.

A number of demonstration programs aimed at evaluating and promoting the production and use of renewable fuels have been implemented by the Government of Canada, such as the Biodiesel Targeted Measure and the Ethanol Expansion Program.

Through the implementation of programs such as these, the Government of Canada has demonstrated its commitment to expanding the production and use of cleaner, renewable biofuels such as ethanol and biodiesel. More recently, the Government of Canada adopted the four-pronged Renewable Fuels Strategy to

• reduce GHG emissions resulting from fuel use;
• encourage greater production of renewable fuels;
• provide new market opportunities for agricultural producers and rural communities; and
• accelerate the commercialization of new renewable fuel technologies.

In addition to the overall environmental benefits, one of the key drivers for supporting renewable fuels production and use is the benefit that it can bring to the agriculture sector and rural Canada. Increased renewable fuels production in Canada will result in increased local demand for feedstocks and new markets for Canadian agricultural producers’ crops. For example, biodiesel facilities can provide a market for off-grade canola, which is not suitable for the food market.

Providing agricultural producers with the opportunity to invest in and develop profitable renewable fuels projects that use agricultural products as inputs will help to create a positive stream of income that could be more independent of commodity price swings. This would also encourage an approach that goes beyond simple commodity production to focus on new ways to add value to biomass produced on farms. Renewable fuel plants would inject additional spending into the local rural economies, broadening their tax base and generating additional jobs at the local level.

In support of the Renewable Fuels Strategy, on December 30, 2006, the Government of Canada published a notice of intent (see footnote 3) to develop regulations that would require an average 5% renewable fuel content based on gasoline volumes by 2010 and an average 2% for diesel fuel and heating distillate oil volumes by no later than 2012.

On April 23, 2007, the Government of Canada established the ecoAgriculture Biofuels Capital Initiative (see footnote 4) for which Agriculture and Agri-food Canada (AAFC) is responsible. This four-year $200 million initiative would provide repayable contributions of up to $25 million per project to help farmers overcome the challenges of raising the capital necessary for the construction or expansion of renewable fuel production facilities.

Another program in support of the Renewable Fuels Strategy is the ecoENERGY for Biofuels Initiative (ecoENERGY) (see footnote 5) managed by NRCan. Announced on December 3, 2007, the ecoENERGY program supports the production of renewable alternatives to gasoline and diesel and encourages the development of a competitive domestic industry for renewable fuels. This program will invest up to $1.5 billion over nine years in support of renewable fuels production in Canada.

The 2007 budget also made $500 million available over eight years to Sustainable Development Technology Canada, (see footnote 6) overseen by Environment Canada (EC) and NRCan to establish — in collaboration with the private sector — large-scale facilities for the production of next-generation renewable fuels. Next-generation renewable fuels produced from non-food feedstocks (such as wheat straw, corn stover, wood residue and switchgrass) have the potential to generate greater environmental benefits in terms of GHG emission reductions than traditional renewable fuels.

In addition to these commitments, the 2008 budget provided a further $10 million over two years for scientific research and analysis on renewable fuels emissions to support the development of regulations, and demonstration projects to assess the technical feasibility of biodiesel under Canadian climate and conditions.

The proposed Amendments will further support the use of renewable fuels in Canada and increase the demand for these fuels. Domestic production levels are expected to be influenced by the initiatives in place under the Renewable Fuels Strategy. Combined with other Government of Canada programs, the proposed Amendments would assist in the creation of jobs in rural areas and provide new markets opportunities for rural Canada.

Actions in other Canadian jurisdictions

Some provinces have established minimum renewable diesel content requirements for distillates. The following table summarizes the provincial requirements for distillates that have been announced or implemented to date.

Table 1: Legislated Provincial Renewable Fuel Mandates for Distillates

Province	Regulated Level	Implementation Timeframe
Manitoba	2%	2009
Alberta	2%	2011
British Columbia	3% 4% 5%	2010 2011 2012

Actions in international jurisdictions

Renewable diesel requirements have been implemented by various jurisdictions, including the United States, the European Union and Brazil.

United States

The U.S. Energy Policy Act of 2005 established the Renewable Fuels Standard (RFS), requiring 7.5 billion gallons (approximately 34 billion litres) of renewable fuels to be blended into gasoline by 2012. The Energy Independence and Security Act of 2007 expanded the program and established what is commonly referred to as RFS2, with annual volume requirements that increase to 36 billion gallons (about 164 billion litres) by 2022. The RFS2 also created various renewable fuel categories, and requirement for biomass-based diesel, with each category having lifecycle greenhouse gas performance threshold standards and specific volume requirements.

As of July 31, 2010, five states and one city have renewable diesel mandates in effect:

• Minnesota has a 5% requirement for all diesel fuel sold in the state. The Minnesota mandate increases to 10% in 2012 and 20% in 2015, but only from April through October.
• Oregon has a 2% mandate that increases to 5% when annual in-state production of biodiesel reaches 15 million gallons.
• Washington State has a mandate for 2% biodiesel or renewable diesel content. This mandate increases to 5% once in-state feedstock and oil-seed crushing capacity can meet a 3% requirement.
• Pennsylvania has a 2% mandate for all diesel fuel sold in the state. This increases to 5%, 10% and 20% once in-state production can meet those levels.
• Massachusetts has a 2% renewable diesel fuel mandate that increases to 5% by 2013; however, the current mandate has been suspended indefinitely due to concerns that higher costs would be borne by the consumer as a result of the expiration of the U.S. biodiesel federal tax credit.
• Portland, Oregon, has a 10% mandate for all diesel fuel sold in the city.

Two additional states have enacted biodiesel mandates that have not yet taken effect:

• New Mexico’s 5% mandate for diesel fuel used in motor vehicles takes effect in 2012.
• Louisiana’s 2% mandate takes effect once in-state annual production from domestically grown feedstock reaches 10 million gallons.

United States biodiesel production capacity in 2009 was approximately 5.9 billion litres, while actual production was approximately 1.7 billion litres.

European Union

The Renewable Energy Directive (Directive 2009/28) came into force on June 25, 2009, and one of its core elements is a 10% binding target for renewables in the transportation sector for 2020 and the introduction of a comprehensive set of sustainability requirements for biofuels in order to be counted towards the target.

The European Union (E.U.) Biofuels Directive (Directive 2003/30/EC) set non-binding targets for biofuels use as a percentage of fossil fuel use. In 2005, the target was 2%, and in 2010, it is 5.75%. An amendment to the Fuels Quality Directive was voted in December 2008 to allow biodiesel blends of up to 7%. The related diesel fuel quality specification EN 590 was modified in 2009 to align with the directive.

Several E.U. member states have biodiesel or renewable diesel specific mandates, such as Germany (4.4%), Italy (3.5% in 2010, 4% in 2011, and 4.5% in 2012), Lithuania (5%), and Portugal (10%).

Brazil

In 2005, Brazil established minimum percentages for biodiesel in diesel fuel. The mandatory requirement is 2%, for 2008 to 2012, and 5% from 2013 onwards.

Sector profiles

Renewable fuel facilities

To increase the availability of biodiesel in Canada, the government has initiated the ecoENERGY for Biofuels program, which supports the production of renewable alternatives to gasoline and diesel and encourages the development of a competitive domestic industry for renewable fuels. The program, administered by NRCan is investing up to $1.5 billion over nine years in support of biofuels production in Canada.

There are currently seven commercial-scale biodiesel producing plants in operation in Canada, accounting for approximately 118 million litres per year in production as of 2007. Other plants are under construction, mostly in the Prairie Provinces. When considering all these biodiesel plants, the Canadian biodiesel industry would have a total production capacity of 600 million litres by 2012.

Biodiesel can be produced from a large variety of feedstocks, including vegetable oils, animal fats and recycled cooking oils (also known as yellow greases). In Canada, the most common vegetable oils are from dedicated crops such as soybean and canola. Since canola has a higher oil content, lower cloud points (see footnote 7) and pour points (see footnote 8), and is in a large net export position compared to soy, it is considered a better feedstock for biodiesel production. Currently, biodiesel produced in Canada is mainly made from yellow grease and animal fats, which are the most cost-effective feedstocks and generate relatively fewer GHG emissions than others.

Petroleum refining sector

In 2007, there were 16 refineries in Canada operated by 9 refining-marketing companies. Imperial Oil, Shell and Suncor marketed nationally and operated three or more refineries each. The other companies only operated one refinery each and, for the most part, marketed locally. In 2007, these facilities employed approximately 7 400 people in the sector. Of these facilities, four were located in Ontario, three facilities were located in each of Alberta and Quebec, two were located in British Columbia, and Saskatchewan, New Brunswick, Nova Scotia and Newfoundland and Labrador had one facility each.

Refineries in Canada have generally been operating at 90% of their capacity (95% being considered as the optimum utilization rate, taking into account maintenance shutdowns and other unplanned events). A total of 108 billion litres of crude oil was sent to refineries in 2007, with imports accounting for 49.9 billion litres. The total production of refined petroleum products was approximately 123 billion litres, of which motor gasoline is the most important refined product, representing about 36% of the total production. Diesel fuel accounts for another 23%. While the total production of refined products varies from year to year, the proportion of each product on the total does not change significantly. In January of 2007, the distribution of total domestic sales of refined petroleum products by region was 32% in Ontario, 20% in Quebec, 18% in Alberta, 11% in the Atlantic Provinces, and 19% in the other provinces and territories in Canada.

Canadian petroleum refiners and producers of other petroleum and coal products (e.g. producers of petroleum waxes, petroleum jelly, recycled motor oils) contributed an estimated $2.6 billion to Canadian gross domestic product (GDP) and accumulated $68.6 billion in total revenues in 2007. Canadian refineries supplied approximately 84% of domestic demand for refined petroleum products. Canada exported over 25 billion litres of refined petroleum products while importing 16 billion litres. (see footnote 9)

The net revenues in the petroleum refining industry have increased from $0.8 billion in 1998 to $5.2 billion in 2007 or by 20.8% per year on average. In 2007, the increase was 16%.

Fuel transportation and distribution sector

The transportation and distribution infrastructure for petroleum-based fuels is primarily dominated by national fuel producers in Canada. Regional fuel producers and independent marketers have a smaller share of the distribution system. The petroleum distribution system caters to both the transportation of crude oil to refineries as well as the distribution of the refined petroleum products to the primary storage terminals, bulk plants and service stations/cardlocks. The transportation of refined petroleum product is done by tanker trucks, rail, marine tankers or pipeline, depending on the quantity of fuel and the geographic location.

The Canadian downstream petroleum industry can be divided into three distinct regions: Western Canada, Ontario and Quebec/ Atlantic Canada. In the Quebec/Atlantic region, product movements from refineries to terminals occur primarily by ship and rail, except for the products moved to Ontario via the Trans Northern Pipeline (TNPL) and the products moved by rail between Saint-Romuald and Montréal — for which a pipeline replacement is being considered.

In 2006, approximately 80 billion litres of refined petroleum products were moved via pipelines in Canada. In 2007, crude oil and other pipeline transportation contributed approximately $1.4 billion or approximately 0.1% to GDP. The share of total transportation of goods by rail, water and truck transportation to GDP, on the other hand, was approximately $28.5 billion or nearly 2.3% in 2007.

Fuel storage terminals

There are 1 833 storage terminals spread across Canada, comprising 76 primary terminals, 614 bulk plants and 1 143 cardlock facilities. The majority of the terminals (approximately 67%) are located in the West, with Ontario and the eastern provinces accounting for 16% and 17%, respectively. Ontario, British Columbia and Quebec account for 66% of the primary terminals in Canada. These primary terminals are owned by the petroleum fuel producers and are shared to optimize efficiency. Primary terminals are, for the most part, located close to major markets and transportation modes. Multiple producers often load petroleum products at the same terminal, where the addition of proprietary additives takes place before distribution to bulk plants or retail stations. Most blending with renewable fuels would typically occur at the terminals (a small amount currently takes place at retail stations as well) and separate tanks are required on-site for renewable fuel storage before blending. Biodiesel generally requires heated tanks to prevent gelling in cold weather.

The bulk plants, representing the second level of storage facility, account for 33% of all storage facilities in Canada and are located in areas where retail distribution directly from terminals is not economical. They operate as secondary points of storage and distribution, but also of sales, and as such are typically not shared facilities (unlike primary terminals).

Cardlock facilities provide fuel to commercial truckers such as long-distance haulers and delivery vehicles. These are controlled access facilities, as opposed to retail stations. Diesel is the main fuel offered for sale at these facilities primarily as it is the principal fuel used by commercial fleets. In the last 30 years, cardlock facilities have become the principal suppliers of fuel to commercial trucking operations. Due to the lack of availability of total cardlock supply data for Canada, it is difficult to accurately estimate the share of cardlock sales volume. However, it is likely that cardlock operations account for roughly 70% of all diesel fuel demand in Canada.

Some producers may be considering the possibility of reconfiguring existing refineries in order to produce hydrotreated vegetable oil (HVO). HVO has significant physical advantages over biodiesel in that it has superior cold flow properties and higher energy content. The transportation, storage and blending of HVO does not require temperature regulation (such as heated and insulated tanks and lines), significantly reducing costs. However, HVO is currently less economic than biodiesel, resulting in a low level of supply.

Retail sector

Marketing and retailing of fuel is carried out by many different firms. Some of these firms are integrated refiner-marketers who produce the fuel, distribute it and market it through affiliated or licensed operators who own the individual retail outlets. Approximately 28% of retail stations are owned or operated by integrated refiner-marketers. Independent marketers (the remaining 72%) buy their product from Canadian fuel producers or import fuels and tend to be smaller operators.

The number of retail stations has declined steadily from around 20 000 in the late 1980s to less than 13 000 in 2008. Quebec and Ontario had the largest number of retail stations accounting for more than half of the total, followed by Alberta and British Columbia with 13% and 11%, respectively. It should be noted that the retail market for distillate represents a small portion of overall diesel fuel and heating distillate oil sales in western Canada (approximately 35%), while in Ontario and Quebec it represents approximately 50%.

Agricultural sector

In the primary agriculture sector, large farms dominate production accounting for only 2.5% of farms, but 40% of revenues. In 2007 and 2008, as commodity prices have risen, farm market receipts and net farm income for grain and oilseed farms have also increased. Canada ranks as the second largest in the world for the availability of arable land per person which also accounts for Canada being a large producer and exporter of agricultural products. Canada’s share of land suitable for agricultural production accounts for only a small percentage (5%) of the total land in Canada.

The agriculture, forestry, fishing and hunting sector contributed nearly 2.2% to Canadian GDP in 2007, of which crop production accounted for approximately 54.5%. The crop production sector employed nearly 298 844 persons. In 2007, the value of crops exported was nearly $13 billion while imports totalled $6.4 billion with the United States being the largest trading partner, followed by Japan.

Regulatory and non-regulatory options considered

Status quo

As described previously, the Regulations include provisions requiring an average 2% requirement for renewable content in diesel fuel and heating distillate oil but do not specify a start date for this requirement. This requirement was subject to the demonstration of technical feasibility under the range of Canadian conditions. The technical feasibility has been assessed by NRCan through the NRDDI project and is supportive of the implementation of the 2% requirement for renewable content in diesel fuel and heating distillate oil as long as sufficient time is provided to the fossil fuel industry for infrastructure readiness. The option of taking no action, e.g. of not setting the coming-into-force date was rejected as it would diminish the effectiveness of the Renewable Fuel Strategy and would not result in achieving further reduction of GHG emissions that will arise by requiring renewable fuel content based on distillates volumes.

Proposed Amendments

To set a coming-into-force date for the 2% requirement, it is necessary to amend subsection 40(3) of the Regulations. Therefore, the proposed Amendments are the only option.

Benefits and costs

An analysis of benefits and costs was conducted to assess the impacts of the proposed Amendments on stakeholders, including the Canadian public, industry and Government.

Analytical framework

The approach to cost-benefit analysis identifies, quantifies and monetizes, where possible, the incremental costs and benefits of the proposed Amendments. The cost-benefit analysis framework applied to this study incorporates the following elements:

Regions — The costs and benefits have been estimated on a regional basis. The regions are defined as “West,” which includes British Columbia, Alberta, Saskatchewan and Manitoba; “Ontario,” and the “East,” which includes Quebec, New Brunswick, Nova Scotia, and Prince Edward Island and Newfoundland and Labrador. These regions have been defined as such in order to preserve the confidentiality of the data collected for this analysis. Since the volumes of diesel fuel or heating distillate oil sold or delivered for use in the Yukon, the Northwest Territories, Nunavut and the regions of Quebec north of 60° north latitude are excluded from a producer or importer’s distillate pool, these regions have not been included in the analysis.

Incremental impact — Impacts are analyzed in terms of incremental changes to emissions, costs and benefits to stakeholders and the economy. The incremental impacts were determined by comparing two scenarios: one with and the other without the proposed Amendments. The two scenarios are presented below.

Timeframe for analysis — The time horizon used for evaluating the economic impacts is 25 years. The first year of the analysis is 2011, when the proposed Amendments are expected to come into force.

Costs and benefits — These have been estimated in monetary terms to the extent possible and are expressed in 2007 Canadian dollars. Whenever this was not possible, due either to lack of appropriate data or difficulties in valuing certain components, incremental impacts were evaluated in qualitative terms.

Discount rate — A discount rate of 3% is used in the analysis for estimating the present value of the costs and benefits under the central analysis. A sensitivity analysis of discount rates and other key variables to test the variability of cost estimates was also conducted.

The proposed Amendments do not specify the type of renewable fuel used to meet the 2% requirement. Biodiesels (see footnote 10) typically have lower energy content than petroleum diesel, higher cloud point temperatures and are generally blended only up to 5%, since high blend levels (i.e. 20%) may not be compatible with certain vehicle technologies. However, according to NRCan, in low-level blends of B2-B5, this lower energy content is not noticeable and no significant change in fuel consumption is observed. Kerosene can be added to biodiesel blends to improve the cloud point in winter temperatures. Kerosene has about a 2.5% lower energy content than diesel fuel. With kerosene, the effect on energy content may be more significant because much higher volumes of kerosene are expected to be blended than of biodiesel. A pour point depressant is an additive that lowers the temperature at which a fluid will continue to flow under standard conditions. Pour point depressants can be added to renewable diesel blends without a loss in energy content.

Hydrotreated vegetable oil (HVO) (see footnote 11) has physical properties that allow it to be blended seamlessly into fossil diesel fuel and therefore can be mixed up to 100% blends. HVO typically has a higher cetane count and slightly higher energy content than fossil diesel. (see footnote 12) However, it is currently relatively expensive and supply is limited to less than a handful of production centres in Southeast Asia, Finland, the Netherlands and the United States.

Benefit and cost estimates are based primarily on Environment Canada’s updated study of the proposed Amendments conducted in 2010. (see footnote 13)

Business-as-usual scenario

The business-as-usual (BAU) scenario is based on provincial mandates that were in place as of December 1, 2010. Provincial mandates have been put in place in three provinces (Manitoba, British Columbia and Alberta) with varying levels of renewable diesel requirements (see Table 1).

To estimate the demand volumes for biodiesel as a result of provincial requirements, it is necessary to estimate the “business- as-usual” demand volumes for diesel fuel and heating distillate oil over the 25-year period. To achieve that, average annual growth rates of diesel fuel and heating distillate oil demand obtained from NRCan’s “Canadian Energy Outlook: The Reference Case 2006” (see Table 2) were used to grow the actual 2009 diesel fuel and heating distillate oil demand volumes. (see footnote 14)

Demand volumes for biodiesel as a result of provincial requirements were calculated by multiplying the estimated demand volumes for diesel fuel and heating distillate oil by the officially mandated renewable fuel requirements in those provinces. Annual demand for renewable fuel is therefore estimated to increase from 274 million litres per year in 2011 to 483 million litres per year by 2035. It is expected that these provincial requirements can be met through existing and planned annual biodiesel production capacity, estimated to total approximately 600 million litres by 2012 (based on volumes supported under the ecoENERGY for biofuels program). Table 3 shows estimated demand volumes for diesel fuel, heating distillate oil and biodiesel due to the provincial requirements.

Table 2: Annual Growth Rates for Diesel Fuel and Heating Distillate Oil Demand (2011–2035)

Fuel	West	Ontario	East
Diesel fuel	0.0198	0.0179	0.0105
Heating distillate oil	0.0194	0.0150	0.0047

Source: NRCan Canadian Energy Outlook: The Reference Case 2006.

Table 3: Estimated Cumulative Demand for Diesel Fuel, Heating Distillate Oil and Renewable Diesel Under the BAU Scenario (2011–2035)

(Million litres)

Demands	West	Ontario	East	Total
Diesel fuel demand	404 182	206 112	201 742	812 036
Heating distillate oil demand	3 681	25 847	64 814	94 342
Biodiesel demand over the 25-year period	9 653	0	0	9 653
Average annual biodiesel demand	386	0	0	386

The estimated reductions in GHG emissions attributable to provincial mandates under the BAU were based on the life cycle emission reduction factors for each of the different types of biodiesel and for HVO. Life cycle emission factors for biodiesel and HVO were estimated using NRCan’s GHGenius model, version 3.19, under average Canadian conditions, and were compared with life cycle emission factors for conventional diesel fuel in order to obtain GHG emission reduction factors for the different renewable diesel fuel types. The resulting GHG emission reduction factors are presented in Table 4 below (e.g. in the case of canola, the displacement of 1 litre of diesel from fossil fuels results in an incremental reduction of 3.012 kg of CO₂e emissions).

Table 4: GHG Emission Reduction Factors for Biodiesel From Soy, Canola and Tallow and for HVO

Canola B100 (kg CO2e/L)	3.012
Soy B100 (kg CO2e/L)	2.704
Tallow B100 (kg CO2e/L)	3.228
U.S. soy B100 (kg CO2e/L)	2.463
HVO Palm (kg CO2e/L)	1.470

Kerosene is added to biodiesel blends to improve the cloud point in winter temperatures. To estimate the changes in emissions, a life cycle emissions reduction factor for kerosene would ideally be used. At the same time, since kerosene and diesel have a similar production pathway, it is not likely that life cycle emissions will differ greatly between the two. It is therefore assumed that the emissions reduction factor for kerosene will be zero, pending the conclusion of NRCan analysis now underway.

It was further assumed that given the current and planned production of renewable fuels in Canada, Canadian biodiesel would be produced from soy, canola and tallow. The proportion of feedstocks used to make Canadian biodiesel from 2011 to 2016 was estimated by NRCan and is based on projected usage provided by companies that have signed, or intend to sign a contribution agreement under the ecoENERGY for biofuels program. In consultation with NRCan and AAFC, EC has assumed an annual 2% decrease in the proportion of tallow used relative to vegetable oil in each region from 2017 to 2035. This is because vegetable oils have lower cloud points than tallow (see Table 9 below) and therefore as vegetable oils become more available, refiners will tend to choose biodiesel made from them over biodiesel made from tallow. This reduces the need to use kerosene or pour point depressants and would therefore be more efficient and reduce carbon emissions over time. The distribution of feedstocks over time is presented in the table below.

Table 5: Distribution of Feedstocks for the Production of Canadian Biodiesel

feedstocks	2011	2015	2020	2025	2030	2035
WEST
Canola	43%	45%	49%	54%	58%	62%
Tallow	57%	55%	51%	46%	42%	38%
ONTARIO
Soy	60%	67%	70%	72%	75%	78%
Tallow	40%	33%	30%	28%	25%	22%
EAST
Soy	53%	60%	63%	66%	69%	72%
Tallow	47%	40%	37%	34%	31%	28%

Fuel prices were estimated by applying growth rates from an NRCan oil price forecast to historical prices for diesel and heating oil. The values are presented below in Figure 2.

Figure 2: Estimated Diesel and Heating Oil Wholesale Prices

The reductions in GHG emissions attributable to provincial mandates under the BAU scenario were estimated by multiplying the BAU demand volumes of Canadian canola fatty acid methyl esters and tallow acid methyl esters, hydrotreated vegetable oils and kerosene over the 25-year period by the corresponding GHG reduction factors. The provincial mandates are estimated to achieve approximately 28.7 Mt CO₂e of GHG emission reductions over a 25-year period (or an average of 1.1 Mt CO₂e per year).

Regulatory scenario

Following the effective date for the 2% biodiesel content requirement, the demand for renewable diesel is expected to increase over and above the demand forecasted in the BAU scenario. The additional renewable diesel demand is the difference between the BAU demand and the total demand required to meet the proposed Amendments. The total annual demand for renewable diesel, to meet both provincial and federal requirements, is estimated to increase from approximately 583 million litres in 2011 to 858 million litres in 2035, or about 40% per year higher on average than under the BAU scenario.

The incremental renewable diesel demand is presented in Table 6 below.

Table 6: Estimated Incremental Demand for Renewable Diesel Under the Regulatory Scenario (2011–2035)

(Million litres)

Demand	West	Ontario	East	Total
Renewable diesel demand over the 25-year period	1 931	3 562	2 618	8 111
Average annual renewable diesel demand	77	142	105	324

Given the current BAU demand associated with provincial renewable diesel mandates, it is assumed that the increased demand for renewable diesel under the regulatory scenario would require increased production capacity beyond existing levels. However, during the first year of the coming into force of the proposed Amendments, some level of imports, primarily from the United States, would be needed while domestic production capacity increases. For the purpose of the analysis, the following assumptions are made:

• Biodiesel plants are assumed to have a lifespan of 20–25 years.
• Biodiesel demand over and above the 2011 capacity of approximately 500 million litres (based on volumes supported under the EcoENERGY for biofuels program) would be met in 2011 through imports from the United States until capacity increases to 600 million litres in 2012.
• For 2012–2035, it is assumed that 90% of incremental demand will be met by domestic production of biodiesel and 10% by imports of HVO. It is further assumed that imported HVO is a NExBTL-type product produced from palm oil. Volumes of HVO imports were estimated based on an industry survey. (see footnote 15)
  

Costs to industry

Cost of producing biodiesel

Investments would be needed to build additional renewable fuel production facilities. The capital costs are modelled by NRCan to be approximately $30 million for a 30-million-litre capacity animal fats-based plant and $25 million for a 30-million-litre capacity vegetable oil-based plant. Including operating costs, total costs would be approximately $1.01 per litre for a 30-million-litre capacity animal fats-based plant and $1.09 per litre for a 30-million-litre capacity vegetable oil-based plant. Based on this information, the present value of the incremental cost of producing biodiesel over the 25-year period is estimated to be about $4.8 billion.

Table 7: Present Valueof Incremental Cost of Producing Biodiesel (2011–2035)

(Constant 2007 $M)

Cost	West	Ontario	East	Total
Cost of producing biodiesel	719.1	2,407.4	1,650.9	4,777.4

Fuel producers and importers

Fuel producers and importers of diesel fuel and heating distillate oil would bear a portion of the incremental cost associated with the proposed Amendments. The different properties between regular diesel fuel and renewable fuels blended diesel would require some new infrastructure and upgrades. Specifically, biodiesel must be transported and stored separately from the base diesel fuel. Unblended biodiesel also requires heated tanks to prevent gelling in cold weather. As the renewable fuel content in diesel fuel and heating distillate oil increases with the proposed Amendments coming into force, investments will be needed to upgrade or modify refinery installations and distribution and blending systems. The investments to be made comprise both one-time capital investments incurred in the first year of the implementation of the proposed Amendments, as well as ongoing additional operations and maintenance costs. Based on information provided by fuel producers and importers, investments of $157.2 million will be required to produce diesel fuel and heating distillate oil blended with renewable fuels. In addition to the capital costs, $112.4 million in operation and maintenance costs will be incurred.

Incremental capital costs for terminal upgrades will also be incurred by fuel producers, as these are owned and operated by them. Due to confidentiality of the cost data, the information provided by the fuel producers was aggregated for all refinery and terminal upgrades and/or modifications at the regional level. The capital costs for terminals include the building of truck, rail or barge receiving facilities, purchase of new storage capacity, the installation of blending equipment, the upgrade of lines, pumps, seals and vapour recovery systems, as well as the installation of heating systems for tanks and lines.

The details of the incremental costs to fuel producers and importers for the 25-year analysis period are presented in the table below.

Table 8: Present Value of Incremental Costs to Fuel Producers and Importers (2011–2035)

(Constant 2007 $M)

Costs	West	Ontario	East	Total
Capital costs	22.7	39.7	94.8	157.2
Operation and maintenance costs	15.2	3.1	94.1	112.4
Imports of biodiesel	4.2	5.9	2.1	12.2
Imports of kerosene	1,286.3	3,797.5	1,452.5	6,536.3
Imports of HVO	608.1	0	156.1	764.2
Renewable diesel transportation costs	29.7	97.1	66.7	193.5
Administrative costs	2.5	2.2	2.5	7.1
Total	1,968.7	3,945.5	1,868.8	7,783.0

It should be noted that the cost to fuel producers and importers of purchasing Canadian biodiesel have not been included here, as the cost of producing biodiesel has already been accounted for in the costs to biofuel producers outlined in Table 7. The avoided costs to fuel producers and importers from displacement of diesel fuel and heating distillate oil due to the use of domestic and imported biodiesel, kerosene and HVO is accounted for in the benefit section.

The source of the biodiesel, regardless of the region, will of course depend on availability, quality and cost, but it is assumed in this analysis that it will come from within Canada. It is expected that during the first year, some imports from the United States would be needed to meet the demand until domestic renewable diesel production capacity is increased.

Differences are expected in how national versus regional fuel producers and marketers will meet the proposed Amendments. National fuel producers and importers operating in the West would choose to blend in high concentrations (B5 (see footnote 16)) in the West only during the warmer months, mostly April to September, in order to help them meet their national 2% average. Therefore, in the West, kerosene would be required only during the season transition months of March, April, May and August, September, October with no blending occurring during winter months. The situation is quite different in Ontario and in the East. Since there are no existing provincial regulations for renewable content in diesel fuel and heating distillate oil in these regions, the volumes of biodiesel that regional fuel producers and importers operating in these regions would need to blend in order to meet the federal mandate would be higher.

In addition, soy and tallow fatty acid methyl esters both have higher cloud points than canola fatty acid methyl esters (which is expected to be the dominant biodiesel source in the West), as can be seen in Table 9, and therefore require greater use of kerosene for a longer period of time in order to meet year-round cloud point specifications. In the regulatory scenario, canola fatty acid methyl esters are not used in Ontario and in the East and these regions use higher proportions of tallow fatty acid methyl esters relative to the West.

Table 9: Cloud Point Specifications of Different Biodiesel Types

Biodiesel type	Cloud point (degrees Celsius)
TFAME (tallow)	+15
CFAME (canola)	+2
SFAME (soy)	–3

Kerosene is assumed to be imported mostly from the United States. The estimated cost of kerosene is 4.9 cents per litre higher than conventional diesel fuel. This is based on the average historic differential in wholesale prices for kerosene and No. 2 distillate during winter months (October to March) for the last three years (2007–2010), according to the Energy Information Administration of the United States Department of Energy. (see footnote 17) Gallons were converted to litres and the U.S. price differential was converted into Canadian currency using the average historical exchange rate for the last three years (2007–2010) from the Bank of Canada. (see footnote 18) The total cost of the incremental imports of kerosene over the 25-year period is estimated to be $6.5 billion.

It can also be seen in Table 8 that in both the West and the East, it is predicted that some volumes of HVO would be used. Higher volumes of HVO would be blended in the West, due to greater accessibility of the product in that region. In addition, blenders in the West are already using HVO to meet provincial requirements and therefore already have the necessary infrastructure and planning to deal with HVO. This product is desirable due to its high cetane number and low cloud point relative to biodiesel (can go to −25°C). It is currently produced in relatively low quantities and must be transported long distances (from Singapore, Finland, the Netherlands and the United States to a certain extent), rendering it costly. The volumes of HVO used to calculate the costs and the average differential cost of 35 cents per litre between HVO and diesel fuel were provided by the industry. The total incremental cost of the imported HVO over the 25-year period is estimated to be $764 million.

Some fuel producers are or have been investigating the possibility of producing HVO themselves, but have also indicated that the capital costs remain too high. Most producers would prefer to blend with HVO, but current availability and prices of the product render it inaccessible at this time.

The estimated costs of transportation of renewable diesel are approximately $193.5 million and are based on the information provided by fuel producers. These costs vary depending on the proximity of the refinery to renewable fuel production facilities. An approximate average transportation cost of 4.0 cents per litre has been used to estimate the total transportation costs. This cost is similar to cost used by the U.S. Environmental Protection Agency in the regulatory impact analysis study for its Renewable Fuel Standard.

The administrative costs of $7.1 million can be attributed to the regulatory requirements of measuring distillates and renewable fuel volumes, reporting, and record keeping. These costs to meet the specific requirements of the proposed Amendments would be incurred in addition to those respecting the provincial mandates.

Retail outlets

The incremental costs to fuel retail outlets primarily include one-time capital costs of $3 million for retail site conversion, including purchase of new tanks and/or cleaning of old tanks in order to accommodate the new blended fuel and installation of new filters. Additional operating and maintenance costs were estimated to be negligible.

Table 10: Present Value of Incremental Costs to Upgrade Retail Outlets (2011–2035)

(Constant 2007 $M)

Capital Costs	West	Ontario	East	Total
Diesel Fuel	0.88	0.99	0.60	2.47
Heating Distillate Oil	0.26	0.15	0.18	0.58
Total	1.14	1.14	0.78	3.05

Costs to consumers

The values in the literature for the energy content of biodiesel relative to diesel fuel vary from 5% to 10%. However, operability studies carried out by NRCan’s National Renewable Diesel Demonstration Initiative and others have found that in low-level blends of B2–B5, no significant change in fuel consumption is observed. Therefore, it has been assumed that there is no cost to consumers associated with the use of biodiesel in blended fuel.

Hydrotreated vegetable oil has a slightly (about 2%) higher energy content than fossil diesel (SAE, 2008). Again, in low-level blends, it has been assumed that there are no savings to consumers associated with decreased fuel purchases due to the higher energy content of HVO.

Kerosene has about a 2.5% lower energy content than diesel fuel. However, as relatively high proportions of kerosene are expected to be included in the blended fuels, the costs to consumers of additional fuel purchases due to the lower energy content of kerosene has been considered. For example, in 2% biodiesel blends with biodiesel made from canola, up to 22% of the blend must be kerosene; while with biodiesel made from lard, up to 92% of the blend must be kerosene. This increase in consumer expenditure was calculated as the product of the incremental volumes of diesel fuel and heating distillate oil multiplied by the projected retail blended diesel fuel prices in Canada. The results are shown in the table below.

Table 11: Present Value of Incremental Costs to Consumers (2011–2035)

(Constant 2007 $M)

Increments	West	Ontario	East	Total
Diesel fuel
Incremental diesel blend purchases due to the lower energy content of kerosene (ML)	52	172	58	282
Incremental cost of diesel blend purchases ($M)	31.5	103.7	35.8	171.1
Heating distillate oil
Incremental heating oil blend purchases due to the lower energy content of kerosene (ML)	14	24	16	63
Incremental cost of heating oil blend purchases ($M)	7.9	13.7	9.0	30.6
Total cost of incremental diesel and heating oil purchases ($M)	39.5	117.4	44.8	201.7

Costs to the Government

The government has incurred costs in order to set up and monitor the regulations requiring 5% renewable content in gasoline. The incremental costs to set up and monitor the 2% requirement in diesel fuel and heating distillate oil were deemed to be negligible.

Benefits to Canadians

Avoided costs of purchasing diesel fuel and heating distillate oil

The proposed Amendments would result in volumes of conventional diesel fuel and heating distillate oil that would otherwise be produced or imported into Canada being displaced by renewable diesel and kerosene. The avoided costs of the displaced diesel fuel and heating distillate oil are therefore an incremental benefit of the proposed Amendments. The present value of the avoided costs of purchasing diesel fuel and heating distillate oil was estimated by multiplying the displaced volumes by their respective projected prices. The results are presented in the table below.

Table 12: Present Value of Incremental Avoided Costs of Purchasing Diesel Fuel and Heating Distillate Oil (2011–2035)

(Constant 2007 $M)

Avoided Cost	West	Ontario	East	Total
Diesel fuel	1,704.8	4,518.0	2,108.4	8,331.2
Heating distillate oil	394.5	703.2	486.1	1,583.8
Total	2,099.3	5,221.2	2,594.5	9,915.0

Reduced emissions of greenhouse gases

Achieving a renewable diesel volume equal to 2% of Canada’s diesel fuel and heating distillate oil pool would result in an average incremental volume of 323 million litres per year of renewable fuel being blended with diesel fuel and heating distillate oil each year. This is expected to result in an incremental lifecycle GHG emission reduction of an average of about 1 Mt CO₂e per year. This is a significant contribution to the reduction in air pollution associated with GHG emissions, which is equivalent to taking a quarter of a million vehicles off the road. Over the 25-year period, the cumulative reductions in GHG emissions attributable to the proposed Amendments are estimated to be approximately 23.6 Mt CO₂e.

The incremental reductions in GHG emissions for the regulatory scenario are calculated as the product of the GHG emission reduction factors in Table 4 (as used for the BAU scenario) and the corresponding incremental volume of Canadian canola fatty acid methyl esters, soy fatty acid methyl esters and tallow fatty acid methyl esters, hydrotreated vegetable oils and kerosene required to meet the 2% federal mandate. In addition, as some imports of biodiesel (primarily from the United States) would be needed to meet the shortfall in domestic production, the GHG emissions have been adjusted to reflect the emission factor of American SME.

The largest gains in GHG emission reductions would occur in Ontario and the East, accounting for approximately 80% of the reductions. This is primarily attributed to the fact that renewable diesel is not currently used in those regions.

Table 13: Present Value of Estimated Incremental Benefits of GHG Emission Reductions (2011–2035)

(Constant 2007 $M)

Fuel	West	Ontario	East	Total
Diesel fuel
GHG emission reductions (Mt CO2e)	3.7	8.8	6.2	18.7
Regulated scenario estimate $25/tonne	76.8	183.3	130.0	390.1
Heating distillate oil
GHG emission reductions (Mt CO2e)	0.9	2.3	1.7	4.9
Regulated scenario estimate $25/tonne	20.5	49.2	35.0	104.7
Total diesel fuel and heating distillate oil
GHG emission reductions (Mt CO2e)	4.6	11.1	7.9	23.6
Total benefit for Canada	97.3	232.5	165	494.8

The value of GHG reductions is critically dependent on the climate change damages avoided at the global level. These damages are usually referred to as the social cost of carbon (SCC). Estimates of the SCC vary widely. For example, experts such as Tol, Nordhaus and Hope have reported mean SCC values in the range of $10 to $25 per tonne of CO₂e, whereas Stern has reported a value closer to $100. In large part this variability relates to uncertainties around key parameter choices in the estimation of the SCC, for example the appropriate discount rate to use in the calculation. It is generally acknowledged that estimates, even from the same model, vary widely depending on the chosen levels of key variables. While research by Environment Canada to determine the appropriate SCC for use in cost-benefit analysis is continuing, an estimated value of $25 per tonne of CO₂e has been adopted for this analysis. This value is consistent with the expected U.S. price of carbon and the trading value of permits in the European Climate Exchange. It is also generally consistent with the values presently being used by the U.S. government as well as by the European Commission. Based on this estimate, the present value of incremental GHG emission reductions under the regulatory scenario is estimated to be $494.8 million under the central scenario.

Impact on air quality and health

Health Canada is currently conducting a health impact analysis of biodiesel use in Canada, and although the study is not finalized, preliminary results are presented here to provide a general indication of potential effects. The study includes an analysis of the impact of biodiesel use on mobile sector emissions from on-road heavy duty diesel vehicles (HDDVs), and the impacts of those emission changes on air quality and health. These impacts are evaluated relative to those associated with the use of conventional diesel fuel. Light-duty diesel vehicles, which form a very minor component of the Canadian vehicle fleet, are not included due to a lack of relevant emissions data. Mobile emissions modelling and air quality modelling have been completed in collaboration with Environment Canada.

Estimating the health impacts of a predicted change in emissions is complex and involves some uncertainty, such as projecting impacts to future years. However, as detailed below, Health Canada’s preliminary analyses indicate that the health impacts associated with on-road use of B2 or B5 in Canada are likely to be minimal.

Mobile sector air contaminant emissions

The specific scenarios examined in the analysis of biodiesel impacts on Canadian mobile sector emissions include a comparison of nationwide use of B2 or B5 or B20 (summer only) versus conventional diesel, for the years 2006, 2010, 2015 and 2020. Vehicle emissions of the following air pollutants were considered: particulate matter (PM_2.5, PM₁₀ and TPM); carbon monoxide (CO); nitrogen oxides (NO_x); volatile organic compounds (VOCs); mobile source air toxics (benzene, 1,3-butadiene, formaldehyde, acetaldehyde, acrolein); and several polycyclic aromatic hydrocarbons (PAHs). For the B2 scenario, the results reveal minor reductions (approximately 1%–2%) in on-road HDDV emissions in 2010 of all compounds except NO_x and a 0.36% increase in NO_x. These reflect overall on-road mobile emission changes of less than 1% for all compounds. The effects of nationwide use of B5 (2010) would result in 2%–4% reductions in on-road HDDV emissions for most compounds and a 1% increase in NO_x emissions. These reflect changes in overall on-road emissions for all compounds of less than 2%. The use of B20 in 2010 (May to September only) would result in the following changes in summer on-road mobile emissions: 8% reduction in PM_2.5, 2% increase in NO_x, and less than 4% reductions in air toxics and CO. All emission impacts are estimated to diminish over time due to the introduction of new vehicle technologies. It should be noted that the scenarios considered here (i.e. nationwide use of B2, B5 or B20) are not directly comparable to the assumptions of the cost-benefit analysis (incremental impacts of the federal Renewable Fuels Regulations above existing provincial mandates). However, incremental on-road emission effects due to the proposed Amendments are expected to be less than those reported for the B5 scenario of the Health Canada analysis.

Air quality and health impacts

The impacts on Canadian air quality of changes in mobile sector emissions due to biodiesel use were examined by Health Canada for the B5 and B20 scenarios using photochemical modelling. Results of national on-road B5 or B20 (summer only) use in Canada suggest very minimal impacts on mean ambient concentrations of PM_2.5, tropospheric ozone (O₃), CO, nitrogen dioxide (NO₂) and sulphur dioxide (SO₂) of less than 1% in 2006 and 2020 compared to conventional diesel. The human health implications of these changes in air quality were assessed nationally and include both mortality and morbidity outcomes. Preliminary national results indicate that some minimal health benefits would be expected in 2006 under a B5 scenario, and that these would be reduced by 2020.

Incremental health benefits due to the changes in on-road emissions associated with the proposed Amendments are expected to be less than those estimated for the B5 scenario of the Health Canada analysis.

Impact of a spill or leak to soil

Health Canada also undertook modelling to examine the impacts of biodiesel and biodiesel blends on fuel movement following a spill or leak to soil. Preliminary results indicate that biodiesel fuel components are expected to migrate less than diesel fuel components, thus resulting in contamination plumes that would affect a smaller volume of soil. Although a number of data gaps were identified, this analysis suggests that the risk that biodiesel fuels would impact on human health following an uncontrolled release to the environment would be more manageable than for conventional diesel fuel.

Impact on agriculture

Agriculture and Agri-Food Canada (AAFC) conducted an internal analysis of the impact of 2% biodiesel targets on the Canadian agriculture sector in early 2007, considering all jurisdictions in Canada. Based on the AAFC analysis, the agriculture sector would experience very small impacts. These impacts are discussed in more detail below.

Impact on the crop sector

Based on the AAFC analysis, the proposed Amendments are expected to have no measurable impact on the crops sector. There could be minor increases in domestic oilseed crushing but overall oilseed acreages planted are expected to show only marginal impacts. There are no measurable changes in producer surplus for crop producers as a result of increased biodiesel production. The biodiesel market can serve as a new market outlet where producers can sell off-grade seed.

This minimal impact is due to the fact that Canada is a price taker in the world market for crops, and changes in Canadian demand would not have any significant impact on world prices. However, there could be small shifts in local prices as a result of increased demand for renewable fuel feedstock, but no changes are expected in the prices of other crops.

Impact on livestock

As negligible impacts are expected on crop prices, livestock feed prices are consequently not expected to show any significant change as a result of the proposed Amendments. While larger scale biodiesel production has the potential to increase protein meal availability by stimulating more oilseed crushing, biodiesel production to meet mandated levels of consumption is not expected to have any measurable impacts on the availability of protein meal. As oilseed acreages planted are expected to show very little change, there will be no measurable effect on the availability of feed grains for livestock producers.

In addition, no changes are expected in the trade of live animals or of meat, or in other related sectors such as poultry and dairy. Impacts on employment in the livestock industry are expected to be negligible.

Impact on land use

The proposed Amendments are not expected to result in changes in land use. Changes in cropping activities as a result of the renewable diesel requirement are expected to take place within the existing crop land base. Since no significant changes in crop prices or land use would occur, there would be little impact on crop intensification at the national level. However, there could be a limited impact in a few regions. There may be small increases in fertilizer use as there could be small regional expansion of oilseed production, but this is not expected to result in changes on water quality or GHG emissions from the agriculture sector.

Distributional impacts

Fuel producers and importers

There are investments to be made by the fossil fuels sector due to the proposed Amendments. These investments comprise both one-time capital investments incurred in the first year of the implementation of the proposed Amendment, as well as ongoing additional operations and maintenance costs. Costs are incurred at virtually every step of the supply chain, from refineries to retailers. It is expected that these costs will be passed along down the supply chain to the final retail price.

Renewable fuels facilities

The proposed Amendments would result in an increase in domestic biodiesel production with the demand for renewable fuel expected to increase from 583 million litres in 2011 to 858 million litres in 2035. While forecasts of renewable fuel production are somewhat uncertain, it is assumed that the majority of the renewable fuel demand would be met through domestic production.

In the longer term, as the demand for renewable fuels continues to increase, it would be reasonable to assume that additional domestic renewable fuel production facilities would come on-line over the 25-year period.

Agricultural sector

In addition to reductions in GHG emissions, one of the key drivers for supporting renewable fuels production and use is the benefit that it can bring to the agriculture sector and rural Canada. Increased renewable fuels production in Canada will result in increased local demand for feedstocks and new markets for Canadian agricultural producers’ crops. For example, biodiesel facilities can provide a market for off-grade canola, which is not suitable for the food market.

Providing agricultural producers with the opportunity to invest in and develop profitable renewable fuels projects that use agricultural products as inputs will help to create a positive stream of income that could be more independent of commodity price swings. This would also encourage an approach that goes beyond simple commodity production to focus on new ways to add value to biomass produced on farms. Renewable fuel plants would inject additional spending into the local rural economies, broadening their tax base and generating additional jobs at the local level.

Further expansion of the renewable fuel industries in Canada is expected to rely on feedstock supplied by the Canadian agricultural sector. However, the projected level of renewable fuel production in Canada is not expected to impair the agriculture sector’s ability to provide agricultural commodities for traditional uses, such as for food production and livestock feed. Consequently, downstream industries such as meat and food processing are not expected to be impacted with respect to production, employment, price and trade. Furthermore, impacts on consumer food prices are not expected.

Employment

The capital investments to upgrade the refineries, terminals and retail outlets are expected to create employment in the initial years as the industry ramps up to comply with the proposed Amendments. In addition, the transportation of renewable fuels would require expansion of the existing fuel transportation infrastructure which would also have a positive impact on employment. Due to the characteristics of biodiesel, the most likely mode of transportation from production facilities to the point where it is blended with diesel fuel would be through trucking. Some transportation would also be done through rail. However, due to lack of data, it is not possible to estimate the specific shares for these modes of transportation. Nonetheless, it is likely that the increase in renewable fuel being transported would also result in an increase in employment in this sector.

As demand and, consequently, production of renewable fuels increase as a result of the proposed Amendments, new jobs would be created in the renewable fuel industry. According to NRCan, a biodiesel plant with an annual production capacity of 30 million litres would require 20 employees for operations. Taking into consideration these employment numbers and assuming 10 additional biodiesel plants would be built, the renewable fuels production sector would be responsible for a total of approximately 200 direct jobs per year, over the period considered. This is a maximum estimate of the employment impacts on the renewable fuels sector, considering that if larger plants are constructed, they would likely employ less people per megalitre (ML) of capacity (due to economies of scale). Blenders have also indicated their preference for using HVO to blend with biodiesel. There are currently no HVO production facilities in Canada and any intentions to start-up such facilities would be expected only in the medium to long term.

As with any industrial sector, the biofuels production sector not only creates direct employment, but it also creates indirect employment. Subsequently, the expenditure of employees’ salaries creates induced impacts within the economy. For diesel fuel alone, it is estimated that a 2% renewable fuel standard would entail not only direct employment in biodiesel facilities, but would also indirectly create an additional 4 000 employment positions. (see footnote 19) In the state of Georgia, an analysis using the IMPLAN model to predict the economic impact of an increase in biodiesel production estimated that a 15-million-gallon (annual production of approximately 57 million litres) biodiesel plant would generate a total of 132 new jobs. (see footnote 20)

Consumers

In addition to the direct cost of incremental volumes of blended diesel purchases, consumers would likely experience a small increase in the price of diesel fuel at the pump as the incremental costs for the petroleum refining sector are passed on to consumers. Assuming an upper bound in which all of the estimated incremental costs are passed along, the corresponding cost to the consumer would be up to $2.7 billion. (see footnote 21) In that case, the average cost increase to consumers across Canada would be one third of a cent per litre of diesel fuel, an amount likely to be unnoticeable in the usual day-to-day price fluctuations experienced in the diesel fuel market. For a typical class 7 or 8 truck consuming 80 000 litres of diesel fuel per year, this would increase fuel costs by an estimated $5 per week.

Competitiveness

The Canadian economy is highly integrated with the United States economy. As the United States has implemented similar requirements for renewable fuel content in diesel, no international competitiveness impacts are anticipated on the refining industry.

Conclusions

Although the proposed Amendments impose costs on industry and consumers, these costs are likely to be manageable (e.g. one third of a cent per litre of diesel for consumers). They will also result in benefits from reduced GHG emissions, and combined with other Government of Canada programs, they would assist in the creation of jobs in rural areas and opportunities for rural Canada to participate in biodiesel production. While realized costs and benefits will be sensitive to changes in key parameters such as diesel fuel price forecasts, expected values arising from this analysis are summarized in the table below.

Table 14 suggests an overall net cost of $2.4 billion over 25 years on a net present value basis. This equals an average annual cost of $94 million in net present value terms. In this respect, costs exceed benefits by a ratio of 1.2 to 1, without taking into account the unquantified role that the 2% biodiesel requirement plays in supporting broader Canadian policy objectives relating to the Renewable Fuels Strategy and climate change. Table 14 also indicates that the net socio-economic cost per tonne of GHG emissions avoided in Canada through this measure, without accounting for the global value of the GHG reductions in terms of the social cost of carbon, is about $121 per tonne.

A sensitivity analysis reveals that these impacts are robust across a range of plausible variations in the underlying assumptions. At the same time, this analysis shows that actual impacts could differ from these central estimates. For example, the net cost could decline significantly under a higher assumed SCC value, and will also vary depending on changes to other key parameters, as detailed in the sensitivity analysis section below.

Table 14: Incremental Cost-Benefit Statement (2011–2035)

(2007 $ million)

Costs and Benefits	Base Year: 2011	2023	Final Year: 2035	Total 10 Year (2011–21)	Total 25 Year (2011–35)	Average Annual
A. Quantified industry costs
Biofuel producers
Cost of producing biodiesel	306.9	277.9	308.7	2,417.5	4,777.4	191.1
Sub-total	306.9	277.9	308.7	2,417.5	4,777.4	191.1
Blenders, importers and retailers
Capital costs — Blenders	9.0	9.0	9.0	83.5	157.2	6.3
Operation and maintenance costs	6.6	6.4	6.5	59.8	112.4	4.5
Cost of imports of biodiesel	12.6	0.0	0.0	12.2	12.2	0.5
Cost of imports of HVO	0.0	40.7	50.5	399.5	764.2	30.6
Cost of imports of kerosene	142.8	401.2	503.1	2,920.0	6,536.3	261.5
Biodiesel transportation costs	12.4	11.4	13.4	94.2	193.5	7.7
Administrative costs — Blenders	0.4	0.4	0.4	3.8	7.1	0.3
Capital costs — Retailers	3.1	0.0	0.0	3.0	3.1	0.1
Sub-total	186.8	469.2	582.8	3,576.0	7,786.1	311.4
Total industry costs	493.6	747.0	891.5	5,993.5	12,563.5	502.5
B. Quantified consumer costs
Additional blended diesel and heating oil consumption	4.6	12.4	151.6	91.4	201.7	8.1
Total consumer costs	4.6	12.4	151.6	91.4	201.7	8.1
TOTAL COSTS	498.2	759.4	1,043.1	6,084.9	12,765.2	510.6
C. Quantified benefits
Avoided diesel and heating oil consumption	301.3	600.2	783.5	4,412.9	9,915.0	396.6
Avoided social costs of carbon from GHG emission reductions (SCC at $25/tonne)	23.3	29.1	42.9	213.3	494.8	24.1
TOTAL BENEFITS	324.6	629.3	826.4	4,626.1	10,409.8	416.4
D. NET PRESENT VALUE	(173.6)	(130.2)	(216.7)	(1,458.8)	(2,355.4)	(94.2)
D1. Net present value — Avoided SCC at $100/tonne	(103.5)	(42.9)	(88.0)	(818.9)	(870.6)	(34.8)
Reduction in GHG emissions (Mt CO2e)	1.0	0.9	1.1	9.5	23.6	0.9
Cost to benefit ratio					1.2 times
Socio-economic cost per tonne ($/T) (see footnote 22)					$120.8
E. Qualitative Impacts
Fuel producers and importers	There could be additional costs related to new volume measurement equipment if current measurement equipment is inadequate. This could impose costs over those identified above.
Agriculture	Small changes in local prices of crops used as renewable fuel feedstock are expected as a result of increased demand for these crops; however, no impacts are expected in the prices of other crops. Minor increases in domestic oilseed crushing but overall oilseed acreages are expected to show only marginal impacts. No measurable changes in producer surplus for crop producers. No expected impacts on feed prices and no measurable effect on the availability of feed grains for livestock producers. Changes in cropping activities are expected to take place within the existing crop land base, with little impact on crop intensification at the national level.
Health	The use of B2 would have very minimal impacts on criteria air contaminants with an overall neutral effect on human health.
Employment	Some increases in employment are expected due to increased transportation of renewable fuels, construction of renewable fuel plants, and upgrades to refineries, terminals and storage facilities.

Sensitivity analysis

A sensitivity analysis was carried out to determine the direction and magnitude of changes to the final results associated with assumptions regarding variations in key variables. This includes varying diesel and heating oil prices, the social cost of carbon, the required kerosene volumes and the discount rate.

Diesel and heating oil prices

As the analysis is sensitive to the forecasts for diesel and heating oil prices over the relevant time period, Environment Canada (EC) has incorporated a range of +/−10% on forecasted wholesale and at-the-pump diesel and heating oil pre-tax prices in order to better reflect the level of uncertainty on this key parameter.

Table 15: Sensitivity to Diesel and Heating Oil Prices

(Constant 2007 $M)

cost	−10% Scenario	Central Scenario	+10% Scenario
Cost of purchasing HVO	712.7	764.2	805.3
Cost of purchasing kerosene	5,923.6	6,536.3	7,043.6
Cost to consumer	182.8	201.7	220.7
Total cost	12,082.0	12,765.2	13,332.7
Avoided cost of purchasing diesel and heating oil	(8,923.5)	(9,915.0)	(10,759.8)
Net present value	(2,663.7)	(2,355.4)	(2,078.1)

Lower wholesale diesel and heating oil prices make diesel fuel and heating distillate oil more competitive compared to biodiesel. In response to a 10% reduction, the present value of the net cost of the proposed Amendments would rise by $300 million to $2.6 billion. Conversely, if the price of diesel and heating oil were to be 10% higher, the present value of the net cost of this measure would decline by a similar amount to approximately $2 billion. The results demonstrate a relatively high sensitivity to diesel and heating oil price assumptions.

Social cost of carbon

Estimates of the social cost of carbon (SCC) vary widely. For example, experts such as Tol, Nordhaus and Hope (see footnote 23) have reported mean SCC values in the range of $10 to $25 per tonne of CO₂e, whereas Stern has reported a value closer to $100. In large part, this variability relates to uncertainties around key parameter choices in the estimation of the SCC, for example the appropriate discount rate to use in the calculation. It is generally acknowledged that estimates, even from the same model, vary widely depending on the chosen levels of key variables.

In addition, it is widely acknowledged that the SCC would normally increase by about 2% per year. Important work on the SCC has been recently conducted by the U.S. Environmental Protection Agency through an interdepartmental process. EC is currently undertaking a similar review to update its assumptions about the SCC. This work is not yet complete, and for the purposes of this analysis the Government will continue to rely on existing estimates of the SCC, which relies on proxies for the SCC, including the price of carbon on exchange markets and target prices announced by key jurisdictions.

Table 16: Sensitivity to the Social Cost of Carbon

(Constant 2007 $M)

Location	GHG Emission Reductions (Mt CO 2 e)	Low Estimate $10/tonne	Central Scenario Estimate $25/tonne	High Estimate $100/tonne
West	4.6	38.9	97.3	389.2
Ontario	11.1	93.0	232.5	930.3
East	7.9	66.0	165.0	660.1
Total for Canada	23.6	197.9	494.8	1,979.6
Net present value		(2,652)	(2,355)	(871)

Sensitivity analysis on the $10 to $100 range (including a growth rate of 2% per year) was conducted. The results, presented above, reveal benefit estimates are sensitive to SCC values, with the present value of GHG reduction benefits ranging from $198 million to $1.9 billion, and the net present value of the Regulations ranging from a cost of $871 million to almost $2.7 billion.

Kerosene volumes

The sensitivity analysis to kerosene volumes is based on two scenarios. The first (HVO in heating oil) scenario assumes that instead of using biodiesel in heating distillate oil, HVO would be used and there would be no need to use kerosene in heating oil. The second (no kerosene) scenario assumes that there would be no use of kerosene in both diesel fuel and heating distillate oil. It is assumed that biodiesel is blended during the summer months without the need of kerosene and that a pour point depressant would be used in furnace oil instead of kerosene.

Table 17: Sensitivity to Kerosene Volumes

(Constant 2007 $M)

Costs	No Kerosene in Heating Oil Scenario	Central Scenario	No Kerosene Scenario
Costs
Cost of producing biodiesel	3,760.9	4,777.4	4,777.4
Cost of purchasing HVO	1,872.1	764.2	764.2
Cost of purchasing kerosene	5,483.3	6,536.3	0
Cost to consumer	172.0	201.7	0
Total cost	11,730.7	12,765.2	6,036.4
Benefits
Avoided cost of purchasing diesel and heating oil	9,067.5	9,915.0	3,927.2
Benefits of GHG emission reductions at $25/tonne	443.1	494.8	494.8
Total benefit	9,510.6	10,409.8	4,422.1
Net present value	(2,220.1)	(2,355.4)	(1,614.3)

The sensitivity analysis shows that the results are somewhat sensitive to this assumption. However, even in the extreme case of zero use of kerosene, the net present value of the proposed Amendments would still be a net cost of $1.6 billion.

Discount rates

The sensitivity analysis to the discount rate is based on a scenario with a 0% discount rate and a scenario with a 7% discount rate. The results are presented in the table below.

Table 18: Sensitivity to Discount Rate

(Constant 2007 $M)

Discount rate	0%	3%	7%
Costs
Cost of producing biodiesel	6,947.9	4,777.4	3,148.6
Cost of purchasing HVO	1,104.4	764.2	508.2
Cost of purchasing kerosene	9,796.2	6,536.3	4,128.3
Cost to consumer	301.2	201.7	128.0
Total cost	18,777.9	12,765.2	8,291.4
Benefits
Avoided cost of purchasing diesel and heating oil	14,862.9	9,915.0	6,271.7
Benefits of GHG emission reductions at $25/tonne	746.4	494.8	311.5
Total benefit	15,609.3	10,409.8	6,583.1
Net present value	(3,168.6)	(2,355.4)	(1,708.2)

The analysis indicates that the net present value of the proposed Amendments is sensitive to the discount rate assumptions.

Rationale

The Government of Canada is committed to reducing GHG emissions and to increase the use of renewable fuels through a number of regulatory and non-regulatory actions. In order to do so, the Government of Canada has adopted a comprehensive Renewable Fuels Strategy to reduce GHG emissions, encourage the use and production of renewable fuels and promote economic growth and sustainable development. A number of initiatives have been put in place to achieve the objectives of the Renewable Fuels Strategy.

One of the key elements of the Renewable Fuels Strategy was to require 2% renewable diesel in distillate fuels. In order to achieve this objective, a number of regulatory and non-regulatory options were considered. Given that voluntary and market-based instruments have had only limited success in increasing the use of renewable fuels and cannot guarantee that renewable fuels would be blended in Canada, they were considered unlikely to achieve the 2% renewable diesel content requirement. The use of regulations in combination with a trading system was considered to be an effective way of achieving this requirement. While reducing GHG emissions, this approach also provides flexibility to industry to meet the requirement and ensures production and use of renewable fuels in Canada. Combined with other Government of Canada programs, it would also assist in the creation of jobs in rural areas and opportunities for rural Canada to participate in biodiesel production.

As a consequence, a cost-benefit analysis was conducted for the selected regulatory instrument, which indicated that it would result in a reduction of approximately 23.6 Mt CO₂e of GHG emissions over a period of 25 years. The incremental cost of achieving these reductions is estimated to be $12.8 billion over the same period with associated benefits of $10.4 billion or a net average annual incremental cost of approximately $90 million. The overall impacts are estimated to be about one third of a cent per litre of diesel fuel and heating distillate oil, which would likely go unnoticed in the day-to-day fluctuations in diesel fuel and heating distillate oil prices.

As a consequence of the above, the proposed Amendments are considered to be an effective way of fulfilling the Government of Canada’s commitment outlined in the Renewable Fuels Strategy, and make an effective contribution to its national greenhouse gas objectives.

Consultation

Consultation process

Since 2006, Environment Canada organized a number of consultation and information sessions with various stakeholders on the proposed regulatory approach for requiring renewable fuel content based on gasoline, diesel fuel and heating distillate oil volumes. A complete description of the consultation process, as well as responses to comments, were provided in the regulatory impact analysis statement (RIAS) published in the Canada Gazette, Part II, on September 1, 2010. (see footnote 24)

In May 2009, an information session (see footnote 25) was organized by Environment Canada to communicate the key decisions taken by the Government of Canada on developing the proposed Regulations. At the information session, Environment Canada also outlined the next steps in the regulatory development process, which include drafting, consulting and publishing the proposed Regulations in the Canada Gazette.

In the summer of 2009, in order to ensure the workability of a regulatory design, Environment Canada set up a technical advisory working group comprised of the key stakeholders from the most affected industries. The technical advisory working group reviewed the draft document for the proposed regulatory text, and provided advice on the definitions, workability and technical details. (see footnote 26)

At the same time, Environment Canada offered to consult with the Canadian Environmental Protection Act National Advisory Committee (CEPA NAC) on the proposed Regulations respecting renewable fuels. Four provinces, namely Saskatchewan, Ontario, Quebec and New Brunswick, took up the offer and had bilateral discussions with Environment Canada. One province, New Brunswick, provided comments on the proposed Regulations.

The National Renewable Diesel Demonstration Initiative

During consultations, Canadian industry sectors and end-users raised questions related to the large-scale use and integration of renewable diesel into Canadian fuel distribution networks. The National Renewable Diesel Demonstration Initiative (NRDDI), led by NRCan, was designed to address these technical feasibility questions in advance of the proposed Amendments coming into effect and supported demonstration projects with non-repayable contributions. The assessment by NRCan through the NRDDI has led to the conclusion that renewable diesel can meet the Canadian petroleum industry accepted standards, subject to timing considerations for infrastructure readiness. Accordingly, the 2% requirement is being put in place by this Amendment and the proposed coming-into-force date is July 1, 2011.

Fuel quality specifications and labelling

A consultation of stakeholders was also done within the NRDDI program. Issues raised by stakeholders included the mandating of fuel quality standards and labelling of high-renewable-content fuels.

• These issues were covered in the regulatory impact analysis statement (RIAS) for the Regulations published in the Canada Gazette, Part II, on September 1, 2010.

Coming-into-force date

Bilateral meetings focused on the coming-into-force date for the 2% requirement were held with some key stakeholders on their request. While the petroleum industry and some users had concerns related to the time needed to implement the necessary infrastructure (up to 36 months) and ensure an adequate availability of biodiesel and/or renewable diesel in Canada, the biofuel industry expressed the need for an early start date to ensure a market for their product.

• In proposing the coming-into-force date, Environment Canada has taken into consideration the views of stakeholders and the needs of both the petroleum refining and renewable fuels industries. It has also accounted for the extended first compliance period as well as carrying forward of pre-distillate compliance units, trading of compliance units, carrying back of compliance units and other flexibilities already in the Regulations. The 60-day comment period provides stakeholders further opportunity to present their views to Environment Canada.

Implementation, enforcement and service standards

Implementation

For the purpose of implementing the requirements of the Regulations, Environment Canada is undertaking a number of compliance promotion activities. These activities are targeted toward raising awareness and encouraging the regulated community to achieve a high level of overall compliance as early as possible during the regulatory implementation process. This would include the following:

• Developing and distributing basic compliance promotion material (including explanatory notes) nationally to regulatees and stakeholders;
• Focusing on those regulatees who would be most impacted by the Regulations within the first few years;
• Upon request, distributing additional information, industry-specific information or focused information regionally in a tailored approach at a later time; and
• Training Environment Canada compliance promotion staff in a comprehensive manner to respond to regulatees’ technical or regulatory questions.

The Regulations already include provisions requiring an average 2% renewable fuel content in diesel fuel and heating distillate oil based on annual volumes. The proposed Amendments implement this requirement by providing the coming-into-force date. Once published, the proposed Amendments will be addressed through the activities and materials noted above.

As the regulated community becomes more familiar with the requirements of the Regulations, these activities are expected to decline to a maintenance level. Compliance promotion activities will be revisited from time to time to ensure that the Regulations be implemented in the most effective and efficient manner.

Enforcement

The Regulations were made under the Canadian Environmental Protection Act, 1999 (CEPA 1999), and enforcement officers will, when verifying compliance with the Regulations, apply the Compliance and Enforcement Policy implemented under the Act. This Policy would also apply when verifying compliance with the proposed Amendments.

The Policy sets out the range of possible responses to violations, including warnings, directions, environmental protection compliance orders, ticketing, ministerial orders, injunctions, prosecution, and environmental protection alternative measures (which are an alternative to a court trial after the laying of charges for a CEPA 1999 violation). In addition, the Policy explains when Environment Canada will resort to civil suits by the Crown for cost recovery.

When, following an inspection or an investigation, an enforcement officer discovers an alleged violation, the officer will choose the appropriate enforcement action based on the following factors:

• Nature of the alleged violation: This includes consideration of the damage, the intent of the alleged violator, whether it is a repeat violation, and whether an attempt has been made to conceal information or otherwise subvert the objectives and requirements of the Act.
• Effectiveness in achieving the desired result with the alleged violator: The desired result is compliance within the shortest possible time and no repetition of the violation. Factors to be considered include the violator’s history of compliance with the Act, willingness to cooperate with enforcement officers, and evidence of corrective action already taken.
• Consistency: Enforcement officers will consider how similar situations have been handled in determining the measures to be taken to enforce the Act.

Environment Canada will monitor renewable fuel content in gasoline, diesel fuel and heating distillate oil and compliance with the Regulations.

Service standards

There are no service standards associated with the proposed Amendments.

Performance measurement and evaluation

Measuring the performance of regulatory activities to ensure they continually meet their initial objectives is an important responsibility for the regulating department. The regulatory activities that would be required for the proposed amendments will be considered when measuring the performance of the Renewable Fuels Regulations. The evaluation and reporting of performance of the Regulations would take place via several regular assessment activities that will vary in scope of analysis and that will be carried out in conjunction with other partners, as required. The evaluation and reporting, and the various assessments and reporting requirements that apply to the Regulations, would also take into consideration the regulatory requirements of the proposed Amendments.

Further details on the evaluation, reporting and assessments activities for the Renewable Fuels Regulations are available in the Regulatory Impact Analysis Statement (RIAS) that was published with the Regulations on September 1, 2010, in the Canada Gazette, Part II. (see footnote 27)

A detailed performance measurement and evaluation plan (PMEP) was developed for the Renewable Fuels Regulations. The PMEP is currently being revised to include elements for the proposed 2% renewable fuel requirement for diesel fuel and heating distillate oil. The revised PMEP will be made available, upon request, from Environment Canada after the publication of the amendments in the Canada Gazette, Part II. The various evaluations pertaining to the Regulations are highlighted below.

The objective of the Renewable Fuels Regulations is to reduce GHG emissions by mandating an average of 5% renewable fuel content in most of the produced or imported gasoline, thereby contributing to the protection of Canadians and the environment from the impacts of climate change. The objective of the proposed Amendments is to further reduce GHG emissions by mandating an average of 2% renewable fuel content in most of the diesel fuel and heating distillate oil produced or imported. The Regulations and the proposed Amendments support the Renewable Fuels Strategy’s objective to expand Canadian production of renewable fuels by ensuring demand for renewable fuels in the marketplace. It is estimated that the Regulations would result in an incremental GHG reduction of about 1 Mt CO₂e per year.

The Renewable Fuels Regulations and the proposed Amendments seek to influence primary suppliers and other entities such as blenders or sellers of fuel that elect to participate in the trading mechanism. The proposed requirement to add at least 2% renewable fuel content to the volume of diesel fuel and heating distillate oil that is produced or imported on an annual basis will support two intermediate outcomes of the Regulations:

• Increase the volume of renewable content in Canadian fuels; and
• Achieve an incremental reduction of greenhouse gases from the displacement of fossil fuels.

Performance of the proposed Amendments will be measured with the Regulations through a set of key indicators. The indicators will also be developed to reflect the activities that would be undertaken by the Government and regulated parties. These indicators would be evaluated to assess whether the immediate as well as long-term results have been achieved. The indicators developed for the Renewable Fuels Regulations will be adjusted, where appropriate, to include reference to the 2% requirement for diesel fuel and heating distillate oil.

The immediate outcomes that will serve to track the performance of the Regulations, and the key indicators to monitor performance of the Renewable Fuels Regulations, will also be adjusted to include consideration of the proposed Amendments for the 2% requirement. These outcomes would be achieved via a series of activities related to the development and implementation of the Regulations, including the proposed Amendments.

In addition to measuring and reporting performance as described above, several formal evaluations of the Regulations, the proposed Amendments, and supporting activities, will be conducted through different initiatives. These include the evaluation plan of Environment Canada’s components of the regulation of renewable fuel content in gasoline, diesel fuel and heating distillate oil, which may also encompass data from external sources or published materials to support a broader scope of enquiry. The plan for this evaluation will be in the 2011–12 fiscal year.

Other indirect impacts of the Regulations and proposed Amendments, such as those on the agricultural community, renewable fuels producers and other areas, will be monitored, as appropriate, through the evaluation of other programs supporting the Renewable Fuels Strategy led by Agriculture and Agri-Food Canada. Specifically, NRCan will evaluate its ecoENERGY for biofuels program and AAFC will conduct an evaluation of its ecoABC initiative in 2010–11 and will coordinate an analysis of the Renewable Fuels Strategy in 2010–11.

Contacts

Leif Stephanson
Chief
Fuels Section
Oil, Gas and Alternative Energy Division
Environment Canada
351 Saint-Joseph Boulevard, 9th Floor
Gatineau, Quebec
K1A 0H3
Telephone: 819-953-4673
Fax: 819-953-8903
Email: fuels-carburants@ec.gc.ca

Luis G. Leigh
Director
Regulatory Analysis and Valuation Division
Environment Canada
10 Wellington Street, 24th Floor
Gatineau, Quebec
K1A 0H3
Telephone: 819-953-1170
Fax: 819-997-2769
Email: Luis.Leigh@ec.gc.ca

PROPOSED REGULATORY TEXT

Notice is hereby given, pursuant to subsection 332(1) (see footnote a) of the Canadian Environmental Protection Act, 1999 (see footnote b), that the Governor in Council proposes, pursuant to sections 140 (see footnote c) and 326 of that Act, to make the annexed Regulations Amending the Renewable Fuels Regulations.

Any person may, within 60 days after the date of publication of this notice, file with the Minister of the Environment comments with respect to the proposed Regulations or a notice of objection requesting that a board of review be established under section 333 of that Act and stating the reasons for the objection. All comments and notices must cite the Canada Gazette, Part I, and the date of publication of this notice, and be sent by mail to the Chief, Fuels Section, Oil, Gas and Alternative Energy Division, Energy and Transportation Directorate, Department of the Environment, Gatineau, Quebec K1A 0H3, by fax to 819-953-8903 or by email to fuels-carburants@ec.gc.ca.

A person who provides the Minister with information may submit with the information a request for confidentiality under section 313 of that Act.

Ottawa, February 3, 2011

JURICA ČAPKUN
Assistant Clerk of the Privy Council

REGULATIONS AMENDING THE RENEWABLE FUELS REGULATIONS

AMENDMENTS

1. (1) The definition “pre-distillate compliance period” in subsection 1(1) of the Renewable Fuels Regulations (see footnote 28) is replaced by the following:

“pre-distillate compliance period” « période précédant la période de conformité visant le distillat »

“pre-distillate compliance period” means the period that begins on December 15, 2010 and that ends on June 30, 2011.

(2) Paragraph (a) of the definition “distillate compliance period” in subsection 1(1) of the Regulations is replaced by the following:

• (a) the period that begins on July 1, 2011 and that ends on December 31, 2012; and

2. (1) Paragraph 4(7)(a) of the Regulations is replaced by the following:

• (a) under section 29 — if the volume is the volume of a batch referred to in subparagraph 29(e)(iii) or (iv) — or under paragraph 32(1)(d) or (2)(d) or any of subsections 32(4), (5) and (8) may be expressed in cubic metres to three decimal places, rather than in litres, if that unit is indicated in the record; and

(2) Section 4 of the Regulations is amended by adding the following after subsection (8):

Rounding — percentages of volume

(9) The percentage of a volume of renewable fuel that is determined for the purpose of the definition “high-renewable-content fuel” in subsection 1(1) or of subsection 17(1) is to be rounded to the nearest whole number percentage and, if the percentage is equidistant between two whole number percentages, to the nearest even whole number percentage.

3. The marginal note to subsection 8(2) of the English version of the Regulations is replaced by “Distillate pool”.

4. The description of RF_G in subsection 21(2) of the English version of the Regulations is replaced by the following:

RF_G is the volume, expressed in litres, that the primary supplier determined for RF_G in accordance with subsection 8(1) for that gasoline compliance period; and

5. (1) The description of RF_D in subsection 22(2) of the English version of the Regulations is replaced by the following:

RF_D is the volume, expressed in litres, that the primary supplier determined for RF_D in accordance with subsection 8(2) for that distillate compliance period; and

(2) Section 22 of the Regulations is amended by adding the following after subsection (3):

Assignment of excess units — subsection (3)

(4) When the pre-distillate compliance period ends, any distillate compliance units referred to in subsection (3) that are in excess of the number that are carried forward under that subsection must be assigned by the primary supplier, under subsection 7(3), as part of the primary supplier’s value for DtG_DG in subsection 8(1) for the gasoline compliance period in effect at that time.

6. Section 25 of the Regulations is amended by adding the following after subsection (4):

Elective participants

(5) At the end of the pre-distillate compliance period, all of an elective participant’s distillate compliance units are cancelled.

7. (1) The portion of subsection 31(1) of the Regulations before paragraph (a) is replaced by the following:

31. (1) For the trading period in respect of each compliance period, a participant must make a record in a compliance unit account book of the gasoline compliance units and of the distillate compliance units that they, as the case may be,

(2) Paragraph 31(1)(b) of the English version of the Regulations is replaced by the following:

• (b) transferred in trade, received in trade, or cancelled during the trading period in respect of the compliance period; or

(3) Paragraph 31(2)(m) of the Regulations is replaced by the following:

• (m) in the case of an elective participant,
  
  • (i) the number of their distillate compliance units cancelled under subsection 25(5), and
  • (ii) if they end their participation in the trading system, the number of compliance units cancelled on the date on which they ended their participation;

8. Paragraph 32(3)(a) of the Regulations is amended by striking out “or” at the end of subparagraph (i), by adding “or” at the end of subparagraph (ii) and by adding the following after subparagraph (ii):

• (iii) was later blended at a blending facility to result in liquid petroleum fuel that was not high-renewable-content fuel;

9. Paragraph 34(3)(e) of the English version of the Regulations is replaced by the following:

• (e) for a batch that was imported, the province via which importation occurred, the date of importation of the batch and its country of origin;

10. Subsection 40(3) of the Regulations is replaced by the following:

Distillate requirements

(3) Subsection 5(2) comes into force on July 1, 2011.

11. Paragraph 10(d) of Schedule 5 to the Regulations is replaced by the following:

• (d) by an elective participant
  
  • (i) in the case of distillate compliance units, under subsection 25(5) of these Regulations at the end of the pre-distillate compliance period, and
  • (ii) under paragraph 11(3)(c) of these Regulations as a result of the elective participant ending their participation in the trading system.

COMING INTO FORCE

12. These Regulations come into force on the day on which they are registered.

[9-1-o]

Footnote 1
www.ec.gc.ca/lcpe-cepa/eng/regulations/detailReg.cfm?intReg=186

Footnote 2
“Report on the Technical Feasibility of Integrating an Annual Average 2% Renewable Diesel in the Canadian Distillate Pool by 2011”, NRCan.

Footnote 3
The notice of intent can be accessed from http://gazette.gc.ca/rp-pr/p1/2006/2006-12-30/html/notice-avis-eng.html.

Footnote 4
Additional information on the program is available at www.ecoaction.gc.ca/index-eng.cfm.

Footnote 5
Ibid.

Footnote 6
Additional information on the program is available at www.sdtc.ca/en/index.htm.

Footnote 7
The cloud point is the temperature at which dissolved solids in a liquid are no longer completely soluble.

Footnote 8
The pour point is the lowest temperature at which oil or other liquids will pour under standard conditions.

Footnote 9
Note that the preceding numbers for production, sales, imports and exports do not add up due to inventory changes, the refineries own consumption of products, and other reasons.

Footnote 10
The term “biodiesel” refers collectively to renewable diesel produced from canola, soy and animal fats (tallow) via conventional transesterfication. “Canola fatty acid methyl esters” refers to biodiesel from canola oil, “soy fatty acid methyl esters” refers to biodiesel from soybean oil and “tallow fatty acid methyl esters” refers to biodiesel from tallow.

Footnote 11
Hydrotreated vegetable oil is renewable diesel produced using hydrotreatment and isomerization processes. This renewable diesel is indistinguishable from diesel derived from fossil fuels.

Footnote 12
Garrain, D.; Herrera, I.; Lago, C.; Lechon, Y.; and Saez, R. (2010). Renewable Diesel Fuel from Processing of Vegetable Oil in Hydrotreatment Units: Theoretical Compliance with European Directive 2009/28/EC and Ongoing Projects in Spain. Smart Grid and Renewable Technology, 2010 (1) 70-73.

Footnote 13
Updating the Cost-Benefit Analysis of the Proposed 2% Renewable Fuels Regulation, Final Report, EcoRessources, December 2010.

Footnote 14
Historical data was obtained from The Supply and Disposition of Petroleum Products, Statistics Canada, 2010.

Footnote 15
Updating the Cost-Benefit Analysis of the Proposed 2% Renewable Fuels Regulations, Final Report, ÉcoRessources, December 2010.

Footnote 16
B2, B5, and B20 refer to blended fuels containing 2%, 5%, and 20% biodiesel by volume in conventional diesel fuel.

Footnote 17
Energy Information Administration (EIA, 2010) Refiner Petroleum Product Prices by Sales Type. Available online: http://tonto.eia.doe.gov/dnav/pet/pet_pri_refoth_dcu_nus_m.htm.

Footnote 18
Bank of Canada (2010). Monthly and Annual Average Exchange Rates. Web site: http://www.bankofcanada.ca/en/rates/exchange_avg_pdf.html.

Footnote 19
BBI Biofuels Canada (2006). Economic Impact Study for a Canola-Based Biodiesel Industry in Canada. Prepared for the Canola Council of Canada, 146 p.

Footnote 20
Shumaker, G. A., McKissick, J., Ferland, C., and Doherty, B. (2002). A Study on the Feasibility of Biodiesel Production in Georgia.

Footnote 21
Note that if a portion of the costs of producing biodiesel in Canada are subsidized by the Canadian government, this portion of the costs will technically be felt by Canadian taxpayers rather than by the refiner/marketers and blenders and fuel consumers.

Footnote 22
The socio-economic cost per tonne is calculated by subtracting the sum of all of the non-GHG benefits from the total costs of the proposal and then dividing by the tonnes of GHGs reduced by the measure.

Footnote 23
Watkiss and Downing (2008), “The Social Cost of Carbon: Valuation estimates and their use in UK policy.” IAJ The Integrated Assessment Journal, Bridging Sciences & Policy, Vol. 8, Iss. 1 (2008), pp. 85–105.

Footnote 24
Available at : http://canadagazette.gc.ca/rp-pr/p1/2010/2010-04-10/html/reg1-eng.html.

Footnote 25
The information presented can be accessed at www.ec.gc.ca/energie-energy/default.asp?lang=En&n=BDB8F633-1.

Footnote 26
Technical issues raised and the means proposed to address them can be accessed from www.ec.gc.ca/ceparegistry/documents/participation/renewable_fuels/default.cfm.

Footnote 27
www.ec.gc.ca/lcpe-cepa/eng/regulations/detailReg.cfm?intReg=186.

Footnote 28
DORS/2010-189

Footnote a
S.C. 2004, c. 15, s. 31

Footnote b
S.C. 1999, c. 33

Footnote c
S.C. 2008, c. 31, s. 2