NRDDI - Executive Summary
PDF Version: National Renewable Diesel Demonstration Initiative Infrastructure Project – Final Report (PDF, 971 KB)
In 2006, the Canadian government proposed Regulations under the Canadian Environmental Protection Act that, amongst other requirements, would mandate the requirement for an average of two percent renewable content in the diesel and heating oil pool by 2012 upon successful demonstration. In April 2010, the federal government indicated that no fixed timeline would now be associated with the two percent regulation and that "this requirement would only be brought into force once the technical feasibility of renewable diesel fuel use under a range of Canadian conditions has been demonstrated" (Environment Canada, 2010).
In this context, the Canadian government requires a study that addresses the necessary infrastructure, capital and other costs and time frame required for the implementation of a 2% national renewable diesel mandate across Canada under the conditions prescribed by the proposed Regulations. The principal objective of this project is to assess these issues. More specifically, this mandate involves the following tasks: assessment of the existing blending, storage and distribution infrastructure for renewable content in diesel and heating oil in place on January 1st 2010; assessment of what infrastructure remains to be installed in order for regulated parties to comply with the regulations, as well as the estimated costs and lead times of these new investments; estimation of incremental renewable diesel (biodiesel, hydrotreated vegetable oil (HVO), etc.) and kerosene requirements to meet fuel specifications, based on projected regional blending schedules; and an evaluation of the industry's ability to ensure that distillate pools with biocontent can be kept separate from those without.
The results of these Tasks were obtained by carrying out a literature review and also through extensive consultation with industry proponents. The majority of the large petroleum producers in Canada agreed to participate in this study. In order to preserve the confidentiality of the commercially sensitive information provided by the petroleum producers, for the purposes of this report the results have been aggregated by region. The region defined as "West" includes British Columbia, Alberta, Saskatchewan and Manitoba. There is a central region that includes only the province of Ontario and is therefore referred to simply as "Ontario" throughout the text. The region defined as "East" includes Quebec and the Atlantic provinces.
Existing and necessary additional infrastructure for the storage, blending and distribution of renewable content in diesel and heating oil and their lead times
Biofuel distribution in Canada is not achieved by the same means as fossil fuels; infrastructure must be modified for the transportation and distribution of first generation biofuels. Since the biodiesel industry is still at an embryonic phase and its development is fast, the best practices are not always used for the different distribution activities: transportation is currently done mostly by truck or rail, storage is primarily done by petroleum producers, especially for pure biodiesel for which there are no primary terminals, and blending is done largely through splash blending due to lack of infrastructure. Quebec is an exception with 65% to 75% of the blending is done by in-line injection directly at terminals.
Below we provide a description of the existing and additional necessary renewable diesel infrastructure that could realistically be put in place by a series of milestone dates. First we present the infrastructure that is already in place and then we describe the projects that are currently underway and their estimated completion dates. Finally, we describe the new projects that are awaiting regulatory certainty to be started and the estimated length of time required for these infrastructure additions/modifications. It should be noted that in most cases, new infrastructure will only be made operational during the Spring or Summer. This is to avoid beginning operations during the winter months, which can be more problematic due to cloud point issues. Therefore, if regulatory certainty is attained in December and a project takes a year to complete, it will still not be made operational until at least April of the following year. This important point should be taken into account when analysing lead times for new infrastructure.
The lead times for the upgrade of a terminal or refinery site are approximately one to three years. Longer lead times are usually associated with larger investments, such as truck, rail and/or marine receipt facilities. Permitting and planning are typically the most time-intensive steps in the process, totalling 9 to 18 months. The planning stage is the most unpredictable at this point, as many respondents are waiting for regulatory certainty to begin their planning in earnest. Respondents noted that accelerating lead times in order to meet a mandated regulatory start date, although possible in some cases, can lead to significant cost overruns due to plans and permitting being rushed. The lead times for sales site (commercial and retail) upgrades are very short, three to six months, since the types of modifications are minor (tank cleaning, new filters, inspections).
Existing infrastructure as of January 2010
Investments in new renewable diesel infrastructure have been made at two refineries in the West: at the Consumer's Co-op Refineries Ltd. (CCRL) refinery in Regina, Saskatchewan and the Chevron refinery-terminal in Burnaby, British Columbia. In addition, ten terminals had received modifications or upgrades to accommodate biodiesel. Seven out of the ten terminals are located in the West and are operated by Imperial Oil, Shell and Suncor. The investments in the West were made in order to meet provincial regulations in Manitoba and British Columbia and in anticipation of regulations in Alberta and Saskatchewan. Three of the ten upgraded terminals are located in the East, are operated by Norcan and Canterm (under the ownership of Olco) in Montreal and Québec City, and are not due to any federal or provincial regulations.
All of the investments have been related to the storage and blending of biodiesel, at the refinery or terminal, such as the installation of new B100 receipt tanks and/or modification of existing tanks (cleaning, treating and installation of filters, usually one tank per site), temperature control equipment (heating and insulation), blending equipment (in-line or at the rack), modification of blending electronics and billing systems and customer education. Three sites received truck offload facilities and two sites received rail and marine offload facilities, respectively.
A total of approximately 200 sales sites (commercial and retail) had already been upgraded in order to accommodate biodiesel blends. The majority of these sites are in the East, due to Quebec already having a market for biodiesel blends, and are operated by independents. The remaining sites are in the West (no sites in Ontario). The investments in the West were put in place in order to meet the provincial regulations, whereas those in the East were not.
Projects currently underway
New infrastructure projects that are currently underway are described below and listed according to their expected completion dates. In order to preserve the confidentiality of the data provided by the respondents, refinery and terminal infrastructure additions are described together. It should be noted that all projects that are currently underway are located in the West and have been put in place in order to meet existing provincial regulations.
January 2011 – It is predicted that three refinery and/or terminal upgrades in the West only could be put in place by January 2011 (although it should be noted that actual biodiesel blending would not likely occur before early April, due to cold temperatures). These infrastructure additions include truck receipt facilities for biodiesel at two sites, rail receipt facilities at one site, new tanks and lines with heating, facilities for rack blending directly into truck and rail, as well as in-line blending facilities.
June 2011 – By this date, it is estimated that in addition to the infrastructure described above, additional infrastructure at one refinery/terminal could be operational. This site upgrade would include heated storage tanks and a heated in-line blending system, as well as truck offload facilities.
December 2011 – No additional infrastructure is anticipated for this date.
June 2012 – One additional site infrastructure upgrade could be completed by this date. It will include heated storage tanks and a heated in-line blending system, as well as truck offload facilities.
Approximately 230 additional sales sites have been upgraded to accommodate biodiesel blends since January 2010.
Projects awaiting regulatory certainty
The majority of new infrastructure projects that would be put in place in order to meet the proposed federal regulations are awaiting regulatory certainty to be put into action. These projects are described below and listed by their estimated required lead times from regulatory certainty. In order to preserve the confidentiality of the data provided by the respondents, refinery and terminal infrastructure additions are described together.
6 months – None of the planned additional infrastructure could be in place by this time.
12 months – One proposed project in the East could be completed by this time. The project involves the installation of heated storage tanks and a heated in-line blending system at a refinery or terminal site.
18 months – No additional planned infrastructure modifications could be in place by this time.
24 months – It is estimated that the majority (10 sites) of large-scale infrastructure additions could be in place by this time. In addition to the one site in the East completed at 12 months, it is expected that two refinery and/or terminal sites could be upgraded in the West, four in Ontario and three in the East. One site will invest in pipeline testing and pipeline protocol changes in order to possibly transport B5 by pipeline. Two sites will receive marine receipt and piping facilities, one site will receive rail receipt facilities and three sites will receive truck receipt facilities. Three sites will receive rack blending facilities and one site will receive equipment for batch blending of ultra low-sulfur kerosene (ULSK) with seasonal diesel. Most sites will also include heated tanks and lines as well as upgrades to blending electronics.
30+ months – For this date, in addition to the infrastructure put in place by 24 months, it is estimated that the remaining six sites comprised of one refinery and/or terminal site upgrade would be completed in the West, two in Ontario and three in the East. All six sites will receive rail receipt facilities and five will also receive truck receipt facilities. Five sites will install rack blending equipment; two will install in-line blending equipment. All sites will either install new tanks and/or clean existing tanks, as well as tank and line heating systems.
It is estimated that approximately 1500 additional sales sites (commercial and retail) will need to be converted in order to meet the federal regulations.
Biodiesel and kerosene requirements
The situation in the West is unique because of existing provincial mandates. The marginal volumes of biodiesel being blended in order to meet the proposed federal requirements are relatively low (notably because the regional producers/blenders in the West would already be meeting the proposed federal requirement via their blending for provincial regulations). National refiner/marketers operating in this region will choose to blend in high concentrations (B5) only during the warmer months, mostly April to September, in order to help them meet their national 2% average. Therefore kerosene is required only during the season transition months of March, April, May and August, September, October.
The situation is quite different in Ontario and the East. Since there are no existing or planned provincial regulations for renewable content in diesel/heating oil in these regions, the volumes of biodiesel that will need to be blended in order to meet the federal mandate will be higher. Due to the regional nature of their operations, regional producers/blenders will have less flexibility in terms of where and when they blend with biodiesel. Therefore, in this region, there are significant volumes of biodiesel that will be blended during the winter months, which requires large volumes of kerosene. Nevertheless, in all regions blenders will seek to minimize biodiesel blending during the colder months.
Costs of infrastructure additions/upgrades and additional kerosene
The costs for the upgrade of one refinery or terminal site range from $0.5 million to $16.3 million, the average being around $7.5 million. The costs depend largely on the extent of the infrastructure additions. Sites that require marine and/or rail offloading infrastructure for biodiesel had the highest costs, usually in the $7 million to $16 million range. Truck offloading equipment, new tanks, equipment for heating and inline or blending at the rack are all also significant expenses, ranging from $1 million to $7 million.
Table 1 presents the total infrastructure additions and their costs, by region:
TABLE 1 – NUMBER OF REFINERY AND/OR TERMINAL SITES RECEIVING NEW INFRASTRUCTURE ADDITIONS AND/OR UPGRADES AND THEIR COSTS
|Number of sites||Total Cost
|Number of sites||Total Cost
|Number of sites||Total Cost
The cost of upgrading a retail site is very low, from $400 – $2000 on average. However, the number of retail sites that are expected to be upgraded is high, approximately 1500. Based on estimates from the respondents, it is expected that a total of $1.8 million will need to be spent on upgrading retail sites across the country in order to sell biodiesel blends due to the proposed federal regulations.
Table 2 presents the marginal annual costs of blending with kerosene in order to meet cloud point requirements. For the purposes of this calculation we have used a price differential of 4.9 CAN cents/litre between kerosene and conventional diesel. 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) (EIA, 2010). The table is based on projected 2013 demand for diesel in Canada as it can be assumed that all blending infrastructure would be in place at that time.
TABLE 2 – ANNUAL COSTS OF ADDITIONAL KEROSENE
|Federal mandate only||Total|
|Volume* (m3)||Cost (million $)||Volume* (m3)||Cost (million $)||Volume* (m3)||Cost (million $)|
|Ontario + East||10,723||0.53||472,277||23.14||483,000||23.67|
*Based on 2013 demand.
In some cases producers and blenders will be using HVO instead of biodiesel in order to meet the federal and provincial requirements (primarily because HVO has superior cold flow properties). This is mainly due to the fact that in some regions, companies will have to blend biocontent during the winter months to adhere to provincial regulations especially in BC, for the 5% provincial regulation. The use of HVO would also result in savings in avoided ULSK purchases as well as by reducing the need for specialized infrastructure to store and blend it.
However, HVO is currently very expensive relative to biodiesel. The price differential will vary according to changes in feedstock prices but is currently in the range of about 0.3 – 0.4 $/L. Therefore, for the provincial regulations only in the West, it is expected that about $18 – $21 million will be spent annually on HVO, based on 2013 demand (no HVO is intended to be used in Ontario and the East in the absence of federal regulations). The incremental annual costs of HVO for the federal regulations only is expected to be approximately $9 – $12 million in the West and $1.8 – $2.4 million in Ontario and the East. A significant portion of these costs are related to transportation, since for the moment and in the near future the product is only available in Singapore and Europe. It should be noted that some respondents indicated that they are considering plans to install facilities to produce this product themselves.
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