Investment in the Canadian oil sands has increased rapidly since the resource was first commercialized by Great Canadian Oil Sands (now Suncor) in the 1960s. This growth is forecast to continue, despite fluctuations in the economy and new energy technologies, because of the world demand for oil and the unique advantages of the oil sands.
The latest wave of oil sands development is gathering momentum, with previously shelved expansions now being reactivated and new expansions being initiated. It is believed this latest wave will entail a more disciplined approach to development by both industry and government occupied by continuing scrutiny from non-governmental organizations and non-industry stakeholders. The rapid increase in world oil price, released by Alberta Energy indicate that Alberta exports about 1.3 million bbl/d of crude oil to the UnitedStates, supplying 15 percent of U.S. crude oil imports, or seven percent of U.S. oil demand.13
Investment in the oil sands gives companies a unique opportunity to add reportable reserves at relatively low risk. Business opportunities also exist in ancillary industries such as construction, engineering, petrochemicals, electricity generation, metals, housing, and transportation.
In recent years, investment in Alberta’s oil sands has been robust. From 2001 to 2011, an estimated $133.4 billion was invested in oil sands projects.14 The oil sands investment reached $21.6 billion in 2011.15 However, entering the latest wave of development, oil sands investment is increasing at a modest pace with an estimated $125 billion in oil sands-related projects currently underway or proposed.16
About 136,000 Albertans are directly employed in the oil and gas extraction and mining sectors, which accounts for one out of every 15 jobs in the province. According to the Conference Board of Canada, between 2012 and 2035, development in the oil sands industry will support 880,000 person years of employment over the examined period.17
uniquely accompanied by stagnating North American natural gas prices has accelerated development. Construction and operating costs are lower than they have been in several years and all observers wonder whether this trend will be short-lived. The Conference Board of Canada forecasts that while industry costs for Alberta’s oil sands projects will climb at a very rapid pace over the next three years, buoyant oil prices should ensure that profits return to pre-recession highs by the end of 2014.
Geography and Reserves
Alberta’s oil sands underlie a vast area of the province, located primarily in the regions of Peace River, Athabasca (the Fort McMurray area), Cold Lake (north of Lloydminster) and stretching into Saskatchewan. These areas contain an estimated 1.7 trillion barrels (initial volume in place) of crude bitumen. Of this amount, 168.7 billion barrels are considered to be proven reserves5 (about 99 percent come from the oil sands; and the remaining 1.5 billion barrels come from conventional crude oil). Based on these figures, Alberta has the third-largest proven crude oil reserve in the world, accounting for about 11 percent of total global oil reserves.6 With new and emerging technologies, this reserve estimate could be increased to as much as 315 billion barrels.7 Companies
Australia 1% Canada 2%
Alberta 1/10 of 1%
have barely scratched the surface of the resource, extracting only about four percent of the initial established crude bitumen reserves to date.8
Source: Alberta Energy, Alberta’s Oil Sands: the Facts (April 2011) online:
active projects in the Alberta oil sands
recovery rates for mining projects
Advantages of Investing in the Oil Sands
The oil sands are increasingly seen as a critical strategic component of U.S. and global energy security. World crude oil demand is expected to advance one percent a year, from 85 million barrels a day in 2008 to 105 million barrels a day by 2030.18
The Canadian oil sands represent a viable supply alternative to the world’s growing demand for oil and offer significant reserve and production growth potential with little associated strategic or political risk. The location, depth and size of the oil sands deposits can be determined with a high degree of accuracy and at minimal cost compared to conventional exploration. For mining operations in particular, recovery rates approach 90 percent, which is substantially higher than conventional sources.
Investment in the oil sands also provides
increasing from levels experienced during the recession, industry players are still enjoying low operating costs relative to pre-recession levels. Labour turnover has decreased dramatically, leading to productivity and efficiency gains. Oil sands service providers and equipment manufacturers have been able to rein in prices as a result of the recession and increased competition. These changes have led large developers to reissue project cost projections at significantly lower figures and with the recent upswing in oil prices, investment potential is increasing.19 Improvements driven by technological innovation and operational experience are anticipated to amplify this trend. Some industry forecasters and observers have warned, however, that as crude prices remain high and new projects are approved, the oil sands should prepare for a potential labour crunch in 2013, particularly in the areas of engineering and construction trades.
Integrated mining and SAGD operations are estimated to be economical at US$61/bbl (WTI). Any significant
escalation in material and labour costs or natural gas and diluent price increases pose a risk to this outlook. 4
However, advancement in recovery and upgrading technologies hold the potential to improve the economics
associated with oil sands operations.20
The Canadian oil sands also has a unique opportunity to provide substantial and long-term operating efficiencies for the U.S. refining sector, which has experienced declining margins and an under-utilization of capacity in recent years. U.S. refiners were historically able to maintain reasonable profit margins by taking advantage of the price spread between light and heavy crude oil. However, when the light-heavy crude price spread collapses as it has in recent years and there is little discount between heavy and light oil, heavy refiners are unable to realize any benefits from purchasing heavy crudes. One driver of the tightened spread is the dramatic decline in production and supply to the U.S. of heavy crude oil from Mexico and Venezuela. Provided that the necessary transportation and infrastructure is developed, additional volumes of blended bitumen from the Canadian oil sands could offset such decline and support the economic fundamentals of
Analysts forecast a two- to five-fold increase in production by 2030, which will meet an estimated 16 percent of North American demand.
companies with a unique and relatively low- risk opportunity to add reportable reserves. In Canada, both in situ and mined bitumen are recognized as part of typical oil and gas public disclosure. The U.S. Securities and Exchange Commission allows for in situ and mineable bitumen reserves to be reported as proved reserves.
One of the most significant drivers of growth in the oil sands has been the reduction of exploration, development and operating costs. While such costs are gradually
Current forecasts indicate that by 2019 bitumen production will increase to 3.2 million barrels per day.
refinery naphthas and lighter grade conventional and synthetic oils). The Southern Lights pipeline, which went into service July 2010, will help meet the increasing demand for diluent by petroleum producers in Western Canada. This pipeline extends from the U.S. international border to Edmonton, Alberta, and offers petroleum producers in Western Canada a reliable supply of diluents from U.S. refineries and supply centers.
Oil sands projects and developers are exposed to various risks and challenges, including:
z Cost Overruns and Delays. Many oil sands projects have encountered cost overruns and delays.
Historically, some fully integrated oil sands mining projects have faced cost overruns of over 55 percent,
largely attributable to labour shortages, engineering-related change requested during the construction
phase and the difficulties inherent in managing large-scale projects, particularly those involving upgraders.
The risk of recurrence of such overruns
has been considerably mitigated
z Emissions Controls. Legislative measures have been introduced to address climate change. Alberta became the first jurisdiction in North America to legislate greenhouse gas (GHG) reductions for large industrial facilities. The regulatory regime requires facilities in Alberta emitting over 100,000 tonnes of carbon dioxide equivalent per year to reduce their emissions intensity by a specified amount. Emitters that fail to meet the target have the option of buying Alberta-based carbon offsets, or paying $15 per tonne
over reduction targets into the Climate Change and Emissions Management Fund. The fund supports 6
projects and technologies aimed at reducing GHG emissions in the province. See the Environmental
Concerns section located on page 34 for further information regarding emissions control and climate
z Reliance on Natural Gas. Most oil sands projects rely heavily upon natural gas for energy, steam, power or hydrogen production for use in the upgrading process. It is estimated that the oil sands industry alone is consuming 500 million to 800 million cubic feet (MMcf ) per day of natural gas, or approximately three to five percent of total Canadian natural gas production. Using current technology, in situ projects require about 1,000 cubic feet of natural gas per barrel of bitumen recovered. Mining projects need 250 cubic feet of natural gas per barrel of bitumen and upgraders use up to 500 cubic feet of natural gas per barrel of synthetic crude. Natural gas usage is estimated to increase as the production from oil sands projects increases dramatically over the next several years.
z Reliance on Water. The Water Management Framework imposes strict limits on water usage for the Lower Athabasca River. Together all oil sands projects can withdraw no more than three percent of the average yearly flow of the Athabasca River for their business use. During periods of low river flow, Alberta Environment limits water consumption to 1.3 percent of annual average flow. At times, this can mean that industrial users will be restricted to less than half of their normal requirements given current approved development. Many in situ projects recycle up to 90 percent of the water used in their operations and use deep-well saline water as an alternative to river water wherever possible. Industry is continually working on making production more efficient so water usage is further reduced. In mining operations, 7.5 to 10 barrels of water is used for every barrel of upgraded bitumen. However, with recycle rates of 40 to 70 percent, this means only three to 4.5 barrels of water make up is required. For in situ operations, about 2.5 to four barrels of water is required for every barrel of bitumen extracted. Recycle rates of 70 to 90 percent for in situ operations significantly reduce the required amounts of water make up.
through operational improvements, technological innovation and greater industry and government planning.
z Supply of Diluent. Condensate and other products are used to dilute unprocessed bitumen product (typically in the 20 to 30 percent by blend volume range), but diluent supply is declining and falling short of demand. To ensure that diluent supply does not hinder oil sands development, industry players are seeking to adapt to shortages and reduce demand, including the potential use of heated pipelines and blending with alternate viscosity reducers (such as
Companies have barely scratched the surface of the resource, extracting only about four percent of the initial established crude bitumen reserves to date.
Mindful of these challenges, the industry has implemented general strategies to mitigate cost overruns and avoid risk, which include:
tighter control over project management;
partnering with government bodies to address education concerns and preparing the workforce for future employment opportunities in the industry;
use of temporary worker immigration programs;
modularizing construction components to improve productivity;
improving materials management practices to help avoid on-site delays;
increasing emphasis on developing and deploying new technologies that reduce the use of natural gas and fresh water resources; and
recycling materials where possible.
slurry and pumped through hydro-transport pipelines into a separation vessel. There it settles into three layers: sand, middlings (a sand, clay and water mixture) and bitumen froth.
Location and Extraction
Alberta’s oil sands deposits are distributed in three main areas:
z Athabasca region (1.3 trillion barrels);
z Cold Lake (200 billion barrels); and
z Peace River (155 billion barrels).
Together, these areas encompass 140,200 km2 (54,131 mi2) of Northern Alberta and contain 15 bitumen- bearing deposits. The government of Alberta currently estimates that 420 km2 (162 mi2) are disturbed by oil sands mining, which accounts for 0.3 percent of Alberta’s total land area. Exploration continues to expand the boundaries of the recognized deposits, especially in Alberta’s neighbouring province of Saskatchewan.
Extraction is accomplished either through mining or via in situ methods. Each method is described in more detail below. In situ methods are becoming more widely used out of necessity as a greater proportion of the remaining reserves are located too deep underground to be accessed by conventional surface mining. Of the total 168.7 billion barrels remaining as established bitumen reserves, it is estimated that approximately 80 percent of the total proven oil sands reserves will be recoverable via in situ techniques. Alberta Energy reports that there are 127 active oil sands projects in Alberta. Of these, five are mining projects with the remaining projects employing various in situ recovery methods.
Surface mining operations involve clearing trees and brush from the site and removing the overburden from the ground surface to reveal the oil sands. Giant hauler trucks, up to three stories in height, transport the oil sands from the mine face to a crusher and slurry operation. The crushers and sizers break up any lumps in the sand. The crushed material is then transported to the processing plant, where it is mixed into a hot water
The bitumen froth is skimmed off the top, cleaned and processed to remove fine clay particles and water. It is diluted with naphtha and processed further to remove any remaining minerals and water. Clean bitumen is transported to a refinery or upgraded on site. The middlings undergo a secondary separation whereby air is injected into the mixture to recover an additional two to four percent of bitumen. The bottom sand is mixed with water and pumped into tailings ponds, where it settles. In August 2010, Shell Canada announced its new Atmospheric Fines Drying Technology as part of its effort to speed up reclamation and minimize the need for increased tailings ponds.22
In Situ Extraction 8
In situ methods typically use heat from injected steam to reduce the viscosity of the bitumen, allowing it to be pumped to the surface. The main method of in situ extraction is steam-assisted gravity drainage (SAGD).
SAGD involves drilling pairs of horizontal wells into the oil sand deposits. Continuous low pressure steam is injected into the upper well, creating a high-temperature steam chamber. This softens the bitumen so that it flows downwards into the reservoir and through the lower second horizontal well where it is pumped to the surface. The bitumen product is then mixed with a diluent (typically naphtha or condensate) so it can be shipped to market. A SAGD project uses natural gas to generate steam and uses large amounts of water, although, as noted above, up to 90 percent of the water can be recycled. After the water and the remaining sand particles are removed, the bitumen is diluted and shipped by pipeline to an upgrader or refinery.
From 25 to 75 percent of the bitumen in place can be recovered using SAGD, which can be applied to thinner reservoirs by utilizing lower steam injection pressure. SAGD works best in high permeability reservoirs which require lower injection pressures and lower steam-to-oil ratios. SAGD is viewed as the most economical in situ method currently used. Operations employing SAGD can be viable at production levels as low as 10,000 to 15,000 bbl/d and can accommodate gradual production increases.
It is estimated that approximately 80 percent of the total proven oil sands reserves will be recoverable via in situ techniques.
Table 1 - Evaluating Your Potential Investment – Mining vs. SAGD
amount of water that can be recycled in SAGD projects
estimated number of years without decline in production
Oil sands players are focusing most of their investment in technological innovation on mitigating extraction and other operating costs.
A number of existing and proposed projects are introducing variants on the traditional mining and in situ extraction methods, which are anticipated to reduce operating costs and decrease the environmental impact of operations. Most producers’primary objective, particularly for in situ projects, is to lessen reliance on natural gas. A number of techniques have been developed:
z Toe-to-Heel Air Injection (THAITM) – The THAI process ignites oil in the reservoir and creates a vertical wall of fire moving from the toe of the horizontal well toward the heel, which burns the heavier oil components and drives the lighter components into the production well. By creating heat in situ, the process requires no steam injection from the surface. The process has the potential to upgrade the bitumen in the reservoir; it could therefore substantially reduce production and capital costs, minimize usage of natural gas and fresh water and significantly lower greenhouse gas emissions. A study of the THAI injection method utilized by Petrobank at its Kerrobert project suggests that the recovery factor for proved plus probable reserves rises from 10 percent to 26 percent with the use of the technology.23
z Asphaltene Injection – This technique uses asphaltene residue from the upgrader to produce the gas needed to generate steam and to power the upgrader as well as hydrogen required to feed the hydrocracker unit, the net result of which is a reduction in overall operating costs. This method is primarily associated with the Opti-Nexen Long Lake project, but a variant of this technology is expected to be deployed in the Synenco-Sinopec Northern Lights project.
z VAPEXTM – This process is very similar to SAGD whereby two parallel wells are drilled. Where SAGD injects steam, VAPEXTM injects a vaporized hydrocarbon solvent such as ethane, propane or butane into the oil sand deposit, along with a displacement gas to thin the bitumen and allow it to be pumped to the
surface. VAPEX burns no natural gas and requires no water processing or recycling. Its carbon dioxide emissions are lower and it can be operated at reservoir temperature with little to no heat loss. Devon Canada Corporation has been conducting field trials with the participation of the Alberta and Federal governments to develop and test the technology. N-Solv technology, similar to VAPEXTM, uses a solvent- based process that could potentially reduce capital costs by up to 50 percent and energy costs by up to 85 percent when compared to other in situ methods like SAGD.
z Heavy Oil to Light Oil Upgrading Technology (HTL™) – In 2005, Ivanhoe Energy Inc. acquired the patented process for Rapid Thermal Processing (RTPTM) and applied this process to upgrade heavy crude and bitumen. The upgrading process occurs at moderate temperatures, at atmospheric pressure and in the absence of air, to rapidly convert feedstock to high value output by using hot sand to facilitate thermal cracking. The end product requires no diluents or blending agents for pipeline transportation. The process
11 has been successfully tested at a commercial demonstration facility in Bakersfield, California. It is hoped that HTL™ will solve some of the technical problems associated with traditional upgrading technologies and protect the producer from price fluctuations in blending agents and natural gas—all at a lower cost than traditional upgrading technologies. HTL™ will be employed at Ivanhoe’s Athabasca interests.
z Mobile Ore Preparation Equipment – In its estimated $4.4-billion Voyageur South oil sands expansion, Suncor Energy Inc. is expected to use mobile ore preparation equipment instead of the current truck and shovel system. With the new technology, ore is fed with a shovel directly to a mobile ore preparation system that crushes the ore and drops it onto a portable conveyor system where it is then transported to a slurry facility that blends the mined product. From the facility, the blend undergoes hydro-transport through a pipeline that begins to separate the oil and sand through churning action as it makes its way to the central bitumen processing plant. Although costly, one of these machines can replace 15 mine trucks. This is expected to reduce the size of the mine-hauling truck fleet required to transport ore, which in turn reduces air emissions, noise pollution and the number of workers needed for transport.24
z Liquid Addition to Steam for Enhanced
Recovery (LASER) – After conducting
Players and Projects
pilot projects since 2002, Imperial Oil Ltd. began phased integration of LASER technology into their commercial operations at Cold Lake. LASER involves injecting light oil into the production well with the steam to enhance recovery, as compared to steam injection alone.
z Solvent-Aided Process (SAP) – SAP involves a small amount of hydrocarbon solvent being added to the injected steam during SAGD. The solvent dilutes the oil to reduce its viscosity over and above what is accomplished by heating alone. Cenovus is planning to employ
Oil sands players are focusing most of their investment in
technological innovation on mitigating input costs.
Major Existing Producing Projects
Syncrude Canada Ltd. is the world’s largest producer of synthetic crude oil from oil sands and the largest single
source producer in Canada. It supplies about 15 percent of Canada’s oil requirements, with a production
capacity of 350,000 bbl/d (56,000 m3/d).
Syncrude has approximately five billion barrels of proven and probable reserves (with an additional 2.2 billion barrels of prospective reserves) situated on three leased sites. By 2016, Syncrude expects to extract 185 million barrels (29,400,000 m3) of oil per year, the equivalent to 500,000 bbl/d (79,000 m3/d). Taking into account fully realized prospective reserves, such a production level could be sustained for well over the next 40 years.
The company is a joint venture between seven partners, including Canadian Oil Sands Limited, Imperial Oil,
SAP to boost production at its proposed Narrows Lake project.
Investment in technological improvements has been critical to the viability of the oil sands industry. Our expectation is that innovation will continue to be focused on reducing reliance on natural gas, enhancing the efficiency of the upgrading process and mitigating environmental effects of both extraction and upgrading.
Suncor Energy, Nexen, ConocoPhillips, Mocal Energy (a subsidiary of Nippon Oil Exploration), Murphy Oil
and Sinopec (China’s state-controlled China Petroleum & Chemical Corp.) who purchased ConocoPhillips’
9.03-percent interest for US$4.65 billion in April 2010.25
Suncor Energy Inc. is an integrated energy company that pioneered the world’s first commercially successful
oil sands operation in 1967 near Fort McMurray, in northeastern Alberta. On August 1, 2009, Suncor merged
with Petro-Canada and became Canada’s largest energy company by market capitalization. The combined
company’s current upstream production is approximately 710,000 barrels of oil equivalent per day (boe/d).
Existing upstream production is supported by 7.5 billion barrels of proved and probable reserves.
In the oil sands, Suncor’s mining and in situ leases cover over 1,800 sq. km and contain nearly 13 billion barrels of bitumen resources. The company has 2,600 employees working on oil sands projects.
Suncor’s mining operations are currently located east of its main oil sands facility at Steepbank and Millennium. With the merger of Suncor and Petro-Canada, the Fort Hills Oil Sands Project has been added to Suncor’s mineable oil sands assets. The project, in which Suncor has a 60-percent interest, is estimated to contain more than four billion barrels of bitumen resource. Voyageur South – a proposed project to extend Suncor’s mining operations – is expected to produce 120,000 bbl/d of bitumen during its estimated 40-year operational life. Suncor currently has two complete upgraders at its Fort McMurray operations, as well as upgrading assets at the company’s Edmonton refinery. Suncor’s Voyageur upgrader and the Fort Hills Oil Sands Project are outlined in further detail below.
Suncor’s in situ projects are located at MacKay River and Firebag. The first two stages of Firebag have been in operation since 2003 and 2005, respectively. Together, they produce approximately 60,000 bbl/d. The
$3.6-billion third stage achieved first oil in July 2011 and has planned production capacity of approximately 62,500 bbl/d. Preliminary work is underway on a fourth stage, with production set to begin in late 2012. Suncor recently received approval to develop three additional stages of the project, with stage four of the project expected to begin production in the first quarter of 2013.
Athabasca Oil Sands Project
Shell Canada Energy operates the Athabasca Oil Sands Project, a mining project located 75 km north of Fort
McMurray, Alberta, and comprising the Muskeg River Mine, the Jackpine Mine and the Scotford Upgrader. It
is a joint venture between Shell Canada (60 percent), Marathon Oil Canada (20 percent; previously held by
Western Oil Sands) and Chevron Canada (20 percent).
At full production, the Muskeg River Mine can produce 155,000 bbl/d (24,600m3/d) of crude bitumen, a naturally occurring, semi-solid form of crude oil. The Muskeg River Mine stands on a Shell Canada lease containing more than five billion barrels (790,000,000 m3) of mineable bitumen, 1,650 million barrels (262,000,000 m3) of which is expected to be recovered over the next 30 years. Regulatory approval has been obtained for expansion of the Muskeg River Mine and the Jackpine Mine,26 enabling production up to a total of 470,000 bbl/d.
In January 2010, Korea National Oil Corporation (KNOC) won approval to proceed with its 10,000-barrel-per-
day BlackGold SAGD project. KNOC purchased 100 percent of the Black Gold oil sand leases from Newmont
Mining in August 2006. The leases contain approximately 150 million barrels of recoverable bitumen.
CNRL’s Horizon integrated mining, extraction and upgrading project began producing in 2009. While it was at a production capacity of 110,000 bbl/d in 2010, production was delayed due to operational issues at its coker unit that occurred in early 2011 and production resumed in August 2011 and soon was producing at full capacity.
Projects Under Development
In December 2012, Japan Petroleum Exploration Co., Ltd. (Japex) approved development of its Hangingstone oil sands project south of Fort McMurray through its subsidiary Japan Canada Oil Sands Ltd (Jacos). The project will use SAGD to produce 20,000 b/d, which might be expanded to 30,000 b/d later. Jacos holds a 75% interest in the project company. Nexen Inc. holds the remainder.
In October 2012, Baytex Energy announced that it had acquired a 100 percent working interest in 46 sections of undeveloped oil sands leases in the Cold Lake area of Alberta for $120 million. Baytex Energy received regulatory approval to construct a bitumen recovery scheme using steam-assisted gravity drainage. Proved plus probable reserves total 43.7 million barrels.
In September 2012, Osum Oil Sands Corp. received regulatory approval for the development of a 35,000-barrel- per-day oil sands project using both SAGD and cyclic steam stimulation recovery processes near Cold Lake. Reserves linked to the project are estimated to contain 359 million barrels.
In March 2012, Koch Exploration received approval of its Gemini thermal oilsands project in the Cold Lake region in northeastern Alberta. The steam assisted thermal drainage operation will produce 10,000 bbl/d and is estimated to cost approximately $410 million.
In January 2012, MEG Energy Corp. received regulatory approval from the ERCB for 210,000 bbl/d design production capacity for the third phase of its Christina Lake project. The third phase is a multi-stage expansion of the previous two phases, which produced 3,000 bbl/d and 22,000 bbl/d respectively. The third stage is
valued at approximately $6 billion and will use steam assisted gravity drainage. 14
In December 2011, Athabasca Oil Sands Corp. received regulatory approval for its MacKay River oil sands project, which is a 150,000 bbl/d steam assisted gravity drainage project. The first phase is expected to produce 35,000 bbl/d, with construction beginning in 2014. The project is 40-percent owned by Athabasca and 60-percent owned by a subsidiary of PetroChina.
In March 2011, Suncor announced that it had finalized its strategic alliance with Total E&P Canada Ltd. under which Suncor acquired a 36.75-percent working interest in the Total-operated Joslyn joint venture with Total now holding 38.25 percent, Occidental Petroleum holding 15 percent and Inpex Canada Ltd. holding 10 percent. Suncor will also receive approximately $1.75 billion from the transaction. Total acquired a 49 percent interest in Suncor’s Voyageur upgrader and upon completion, Suncor will operate the planned 200,000 barrel per day facility. Total also acquired a portion of Suncor’s interest in the Fort Hills oil sands project resulting in Suncor now holding a 40.8-percent interest, Total holding 39.2 percent and Teck Resources Ltd. holding the remaining 20 percent. Suncor and Total have agreed to develop the Fort Hills mine and Voyageur upgrader in parallel so that both come on stream in 2016. The companies have also confirmed the Joslyn North Mine timetable with production expected to begin in 2017, subject to receiving the necessary permits and approvals.
Imperial Oil operates the Leming, Maskwa, Mahihkan and Mahkeses plants in the Cold Lake area. As an expansion to the existing plants, Imperial Oil recently completed its Nabiye plant, which includes a cogeneration plant, sulphur recovery facilities and a drilling plan that reduces the number of well pads. Aggregate production from Imperial’s Cold Lake operations averaged 144,000 bbl/d of bitumen in 2010. Inter Pipeline Fund recently announced that it plans to spend $25 million to expand pipeline systems around Cold Lake, which will include expansions to the Nabiye plant. The company is also developing the country’s largest open-pit mining operations at its Kearl oil sands project north of Fort McMurray, which is slated to begin in late 2012. With over four billion barrels of estimated recoverable bitumen resource, Kearl is one of Canada’s largest and highest quality oil sands deposits. Initial development will start at around 110,000 bbl/d with a goal of ramping up to 345,000 bbl/d.
The front-end engineering and design for the first phase of BP and Husky Energy’s Sunrise Project, an in situ development designed to eventually produce 200,000 bbl/d, was completed in early 2010. BP and Husky also entered into a joint venture in respect of a refinery previously owned by BP, which will be expanded to handle 170,000 bbl/d of oil sands production. Husky also recently purchased a refinery in Ohio, which will be retrofitted to process heavy crude and bitumen from Husky’s operations in Alberta.
The first phase of OPTI Canada and Nexen Inc.’s Long Lake SAGD project with upgrading facilities is complete; bitumen production and on-site upgrading began in October 2008. Regulatory approval has been received for a second-phase, SAGD and upgrader complex, whereby Nexen will phase-in production. Regulatory approval is also in place for a third-phase SAGD project at the same location. In February 2011, production from the project dropped 14 percent from production levels in the previous month. Various operational
difficulties and poor steam-to-oil ratios have continued to increase costs and reduce output. OPTI began restructuring its finances in 2009 and is currently undergoing strategic alternatives review regarding its capital structure. Future expansion and development of the Long Lake project is uncertain.
Total E&P Canada Ltd. is continuing to develop its Joslyn Lease with the Joslyn North Mine in the regulatory approval process and the Joslyn South Mine planned for the future. This project will combine conventional mining with SAGD for a total capacity of 200,000 bbl/d by 2020. Total also owns half of the Surmont SAGD project in a joint venture with the Canadian subsidiary of Houston-based ConocoPhillips. Surmont Phase 1 has a design capacity of 27,000 bbl/d of bitumen and is currently producing. Surmont Phase 2, which would increase production to a total of 110,000 bbl/d, has been sanctioned and is scheduled to begin production in 2015. After acquiring Synenco Energy Inc., Total owns a 50-percent share (with Sinopec Corporation owning
15 the remaining 50-percent share) in the Northern Lights Project, which is estimated to have 1.08 billion barrels of bitumen. Total has also received regulatory approval to build a bitumen upgrader near Edmonton, Alberta, which will produce 300,000 barrels of crude oil a day received.
Devon Canada Corporation’s Jackfish 1 SAGD project, located 15 km southeast of Conklin, Alberta, is currently producing 35,000 bbl/d. Production commenced in 2011, and with Jackfish 2 and Jackfish 3 currently under evaluation, total production could reach 105,000 bbl/d by 2015.
Statoil Canada Ltd.’s Kai Kos Dehseh SAGD project is comprised of four proximate fields containing roughly
2.2 billion barrels of bitumen. The project initiated steam injection in September 2010 and commenced
production in the first quarter of 2011. Also, during the first quarter of 2011, Statoil sold a 40-percent interest
in the project to PTTED (the Thai national oil company) for US$2.2 billion. Total capacity of the project is
projected to be in the neighbourhood of 200,000 bbl/d by 2020.
Connacher Oil and Gas Limited anticipates combined bitumen production from its Pod One and Algar Great Divide SAGD projects to average between 14,500 bbl/d and 16,500 bbl/d for 2011. The company was also proposing to expand productive capacity to a combined target of 44,000 bbl/d, but in early 2012, the company’s board of directors initiated a review process to examine all strategies available.
Shell Canada has disclosed plans for a $27-billion expansion of its Scotford facility, entitled the Scotford Upgrader 2 Project. The project is expected to increase the facility’s capacity by an additional 400,000 bbl/d.
In March 2010, Devon announced that it will buy a 50-percent stake in BP’s undeveloped Kirby oil sands project for $500 million and will pay an additional $150 million to cover initial capital costs. Devon will be the operator of the Kirby project, which lies in close proximity to Devon’s Jackfish SAGD project. Like Jackfish, Kirby is expected to be a multi-stage SAGD development.
In February 2011, the government of Alberta, NWU and CNRL entered into a partnership agreement to construct and operate a bitumen refinery near Redwater, Alberta. The agreement will allow the province to take oil sands royalties in kind in the form of bitumen rather than in cash under the government’s BRIK Program. The first phase, to be completed by the summer of 2014, will process 50,000 bbl/d, three-quarters of which will be provided by the province and the rest by CNRL. The first phase will also capture more than 3,000 tonnes daily of carbon dioxide, which will be transported by the Alberta Carbon Trunk Line for enhanced oil recovery operators. The refinery can be expanded in two additional identical phases of 50,000 bbl/d of bitumen at a future date.
New Market Entrants
Although Canadian companies and U.S.-based multinationals have been an integral part of the development of Alberta’s oil sands, more recent market entrants from Asia and Europe have invested in the oil sands. For example:
z In January 2011, Statoil divested 40 percent of its Kai Kos Dehseh Project to PTT Exploration and Production (PTTEP) of Thailand for US$2.2 million in cash. PTTEP is owned 65 percent by PTT Public Company Limited, one of the largest power and utility companies in Southeast Asia, in which the government of Thailand holds a 51 percent interest.
z In May 2010, Penn West Energy Trust joint ventured with China Investment Corp. (CIC) in a transaction
worth $2.6 billion to form a partnership to develop Penn West’s bitumen assets located in the Peace River 16
area. Penn West contributed oil sands properties valued at $1.8 billion, and has a 55 percent stake in the
partnership. CIC, the world’s largest pool of capital, contributed $817 million for a 45 percent interest in
the partnership. CIC also took a five-percent stake in Penn West for $435 million.
z In April 2010, China’s state-owned Sinopec purchased ConocoPhillips’ stake in the Syncrude project for
$4.65-billion, marking one of China’s largest investments ever in North America.
z In August 2009, PetroChina International Co. Ltd. announced that it would buy a 60-percent stake in Athabasca Oil Sands Corp.’s MacKay River and Dover oil sands projects for nearly $2 billion. Later in 2012, PetroChina bought out Athabasca’s remaining 40-percent stake for $680 million. PetroChina was also an early supporter of Enbridge Inc. in the $2.5-billion Northern Gateway Pipeline project in 2005, which proposes to deliver an average of 525,000 bbl/d of crude oil to the west coast of British Columbia for export, but has not yet received necessary approvals to proceed.
The catalysts for this influx of overseas investment are identical to the drivers for North American companies – rising prices and decline of conventional reserves. The oil sands represent a dependable source of production with easily estimated reserves that deliver steady returns to balance the volatility of increasingly expensive conventional exploration efforts.
Alberta Oil Sands Transactions 2001-2013
The data in Table 2 outlines major oil sands acquisitions in recent years, many of which involved Bennett Jones as counsel (denoted in the table with *). Pricing is reflected in USD (million).
Table 2 - Alberta Oil Sands Transactions 2001-2013
It added needed capacity for light/sour crude (thus the LSr name) between Cromer and Clearbrook. The LSr Pipeline was brought into operation in February 2009. Construction and line fill of Enbridge’s Alberta Clipper Pipeline from Hardisty, Alberta, to Superior, Wisconsin, was completed in October 2010. Current capacity of the Clipper is 450,000 bbl/d, with ultimate capacity of up to 800,000 bbl/d available.
The growth in extraction and production has been matched by significant investment opportunities in upgrading facilities and transportation infra- structure.
Over 80 percent of bitumen produced in Canada is exported to the U.S. through existing pipelines. The bulk is delivered to upgraders in Petroleum Administration for Defense District (PADD) II (U.S. Midwest region), with the balance delivered to PADD III (Gulf Coast) and PADD IV (Rocky Mountain). The National Energy Board’s most recent oil sands report indicates that the industry should maximize its volumes in its traditional markets of PADD II, PADD IV and Washington State, with further market expansions and extensions later in the decade into California, PADD III and the Far East.
As demand for oil grows, markets with great potential for Canadian crude continue to emerge. California and the U.S. Gulf Coast both provide significant demand for medium and heavy crudes. Crude oil is currently shipped to California via pipeline and tanker. The U.S. Energy Information Administration predicts that a new or expanded pipeline to California will eventually be required to serve the growing demand of that market.
Proposed pipeline expansions to new and existing markets include proposals by corporations such as Enbridge Inc., Kinder Morgan and TransCanada Pipelines Limited to build and operate new pipelines and storage terminals.
Enbridge, for instance, has proposed the Northern Gateway Pipeline that would transport crude oil from Edmonton, Alberta, to a new marine terminal in Kitimat, British Columbia, whereby it would be shipped to China and other Asia-Pacific markets.The Northern Gateway Pipeline is currently seeking regulatory approval, and would represent a further expansion to Enbridge’s existing pipeline systems in Canada and the U.S. Enbridge’s Southern Lights diluent delivery system came into service July 2010 and carries product through 2,556 kilometres of pipeline originating near Chicago, Illinois, and terminating in Edmonton, Alberta. The Southern Lights project also includes the LSr Project, a 313-mile, 20-inch crude oil pipeline from Cromer, Manitoba, to Clearbrook, Minnesota.
In June 2010 TransCanada commenced commercial operation of the first phase of the Keystone Pipeline System. Keystone’s first phase was highlighted by the conversion of natural gas pipeline to crude oil pipeline and construction of an innovative bullet line that brings the crude oil non-stop from Canada to market hubs in the U.S. Midwest. An extension of the Keystone Pipeline from Steele City, Nebraska, to Cushing, Oklahoma, went into service in February 2011.The further proposed extension is a 2,673-kilometre (1,661-mile), 36-inch crude oil pipeline that would begin at Hardisty, Alberta, and extend southeast through Saskatchewan, Montana, South
Dakota and Nebraska. It would incorporate a portion of the Keystone Pipeline (Phase II) through Nebraska and 20
Kansas to serve markets at Cushing, Oklahoma, before continuing through Oklahoma to a delivery point near
existing terminals in Nederland, Texas, to serve the Port Arthur, Texas, marketplace. The Keystone XL Pipeline is
cited as having an initial commercial capacity of 500,000 bbl/d and is estimated to cost approximately US$7
billion. In January, 2012, the construction of the project was rejected. In May, 2012, TransCanada changed the
original proposed route and filed a new application for a Presidential Permit with the U.S. Department of State.
The Governor of Nebraska, Dave Heineman approved the new route in Nebraska in January, 2013. Pending a
decision on the Presidential Permit, TransCanada believes the pipeline will still be operational by 2015.
Kinder Morgan completed construction in late 2008 on the Anchor Loop project, its Transmountain Pipeline expansion, which runs across Jasper National Park and Mount Robson Provincial Park. The addition of the Anchor Loop increased the capacity of the Trans Mountain pipeline system from 260,000 bbl/d to 300,000 bbl/d, and helped to alleviate capacity constraints on Kinder Morgan’s existing system resulting from increased oil sands production.
Essentially all of the bitumen extracted from the oil sands must be upgraded; oil sands operators must therefore decide whether or not to do field upgrading. Upgrading transforms bitumen into synthetic crude oil, which commands a higher price when sold to refineries. Upgrading requires substantial capital and technological resources. The process enables producers to eliminate risks arising from the heavy oil/light oil price differential and further eliminates diluent cost risk and supply issues. Ultimately, the question for producers is whether the promise of higher, more stable netbacks (that generally result from an upgraded product) will offset the substantial capital costs.
The location of upgrader facilities has been influenced by economies of scale and cost factors such as shortages of skilled labour. Integrated oil sands operators have chosen to locate, expand existing and convert existing upgraders in the U.S. where larger facilities provide cost advantages over Canadian greenfield or expansion projects.
In October 2006, Encana and ConocoPhillips entered into a US$15-billion joint venture that includes Encana’s heavy oil projects in the North Athabasca region, along with ConocoPhillips refineries in the states of Illinois and Texas. The partnership plans to expand processing capacity at these facilities from approximately 60,000 bbl/d to 550,000 bbl/d by 2015.27 Husky Energy and BP have entered into a similar arrangement in their Sunrise project, where Husky transferred 50 percent of its oil sands holdings for 50 percent of BP’s refinery near Toledo, Ohio. Husky acquired the Lima refinery in Ohio and plans to reconfigure and expand it to process heavy crude oil and bitumen.28
The possible regulatory and environmental impediments to the addition of oil sands upgrading/refining capacity in the U.S. have yet to be adequately assessed, but in Alberta they are better known and quantifiable. The issues companies confront in acquiring U.S. upgrading/refining capacity may ultimately prove more disruptive to project timelines than the constraints faced in Alberta projects. In addition, there is a significant governmental push to encourage producers to upgrade in Alberta. Currently, there are five operating upgraders in Alberta with a capacity of approximately 1.13 million bbl/d.
percentage of total global oil reserves in Alberta oil sands
Given the magnitude of projected economic activity, oil sands producers will not be the only beneficiaries of the unprecedented development now underway. Aside from the necessary infrastructure developments, a plethora of ancillary opportunities exist in many sectors, including electricity generation, petrochemicals, heavy metals and construction equipment.
Both in situ and mining-based oil sands projects require large quantities of electricity and are vulnerable to the electricity grid— in service date delays and to fluctuations in price. To secure power supplies, producers
have increasingly turned to generating electricity on their project sites through cogeneration. A cogeneration 22
plant, also known as a combined heat and power (CHP) facility, uses heat recovery and natural gas to run a
combustion turbine to power a generator and produce electricity. A heat recovery steam generator then
captures the remaining heat that would normally be wasted and uses it to produce low- and high-pressure
steam and hot water, which is then used in the oil sands production process.
Cogeneration, with back-up from the electricity grid, provides a reliable supply source and helps oil sands producers meet their needs for electricity. Oil sands producers may choose to generate excess power in order to supply the grid or bilateral power customers, depending on the outlook for Alberta power prices.
Some suggest that the answer to the oil sands’natural gas and electricity requirements may be the construction of nuclear power plants. Alberta’s Provincial Energy Strategy (announced December 2008) identified nuclear power as a potential source of clean, low-emission power. In December 2009, the government released the results of the Alberta nuclear consultation. Among its key findings was that most Albertans polled (45 percent) preferred that nuclear power plants be
considered on a case-by-case basis. As a result, the
Alberta government has decided to maintain its existing policy where power generation options are proposed by the private sector in the province. Any nuclear power proposal would be considered on a case-by-case basis.
The massive increase in production also represents a significant opportunity for investors in the petrochemical industry. The bitumen upgrading process produces off-gas from which ethane and other light hydrocarbons could be extracted and used by the petrochemical industry. Currently, ethane and most of the other light hydrocarbons remain in the off-gas and are used as fuel for operations. The
The bitumen upgrading process produces off-gas from which ethane and other light hydrocarbons could be extracted
and used by the petrochemical industry.
National Energy Board has estimated that by 2015
Alberta’s bitumen resource base could provide a
secure, substantial, and stable-priced feedstock for the petrochemical industry. In Alberta, there may be a
significant opportunity for bitumen-based ethylene, comparable to the production that has occurred on the
U.S. Gulf Coast.
The potential synergy of extraction, upgrading, refining and petrochemical processing facilities located in close proximity is already being exploited in Alberta. Williams Energy of Tulsa, Oklahoma, for example, has entered into an arrangement with Suncor to remove synthetic gas liquids from off-gas produced by Suncor’s upgrader near Fort McMurray. Williams processes the synthetic gas liquids at its nearby facility and ships the extracted olefins mix via pipeline to its Redwater, Alberta, facility, where it produces propane, propylene and olefin concentrate.
estimated decrease in developers’ costs
estimated number of years without decline in production
Structuring your Transaction or Project
Land sale spending in Alberta surged in 2010 due to a combination of new plays, enhanced oil sands technologies and a rebound in oil prices. From April 2010 to March 2011, 365,969 hectares of Crown oil sands leases were sold, totaling $54.927 million in land sale revenue with an average price of $150.09 per hectare. This average price is up from $133.42 per hectare for the same period in 2009/2010. An annual summary of oil sands public offerings is provided in the table below29:
Table 3 - Summary of Oil Sands Public Offerings - By Fiscal Year (April to March) - Leases and Permits
The vast majority of multi-party oil sands projects are structured as joint ventures or partnerships. Preference for a particular structure is most often based on income tax planning, with commercial objectives being another major consideration.
Acquisitions are generally made by purchasing a participating interest in a joint venture or an interest in a partnership. The operating agreements that come into effect upon closing of an acquisition are often the subject of detailed negotiation and discussion, since these documents set out the ongoing development and governance of the project through its life-cycle.
Foreign Investment Approvals
An oil sands investment, regardless of whether the target is a bitumen extraction project, an upgrader, a transportation project or a derivative play, may be subject to Canadian regulatory approvals, two of the most common being:
The Investment Canada Act (ICA), which governs the acquisition of control of a Canadian business whose total asset book value exceeds $354 million (for 2014, adjusted annually for inflation). Acquisitions by state- owned foreign enterprises are subject to additional specific guidelines. Investments can also be subject to a national security review.30 State-owned investors should expect to be required to file information to address the following issues:
z their standards and transparency of corporate governance and public disclosure;
z the role of their board of directors;
z the presence and role of independent directors;
z the mechanisms available to the state to influence the business decisions of the enterprise; and
z any other matters that might be relevant to determining whether and to what extent the enterprise is likely to be run on a commercial basis.
In June, 2013, amendments to the Investment Canada Act were enacted that expand the definition of state-owned foreign enterprises (“Foreign SOEs”) to include:
z an entity that is controlled in fact or influenced, directly or indirectly, by a foreign government;
z an individual who is acting under the direction of a foreign government or under the influence, directly or indirectly of such a government.
The amendments will create uncertainty for prospective investors who do not pass the ICA’s “bright line” control threshold.
In December 2012 the Federal Government announced that it would not approve investments by Foreign SOEs to acquire control of Canadian oil sands businesses otherwise then in “exceptional circumstances”. No guidance has been given publicly as to what this means.
Amendments to change the financial threshold and its method of calculation have been introduced.
The Competition Act, which applies to an acquisition of control where the book value of the project’s or entity’s assets (or its annual Canadian sales) exceed $73 million (adjusted annually for inflation) and the asset book value or annual Canadian sales of the parties to the transaction and their affiliates exceed $400 million.
Financing a Project
25 Generally, large existing producers deemed to be investment-grade risks have had little trouble securing financing for oil sands development. For example, the credit facilities in respect of the CNRL Horizon Project, the Nexen-Opti Long Lake Project and the Total Joslyn Project are standard facilities funded by conventional Canadian banking syndicates.
Project debt financing raises several issues within the framework of a joint venture or partnership. Depending on the partners’positions, some may have a greater desire for external financing than others. This will become an issue when granting security, as the cooperation of all partners will be required. Matters can be further complicated if the project has a combination of partners with high and low credit ratings. One possible structure is for the partners who have no need for project financing to lend into the partnership at the same rate as the less creditworthy partners, to maintain economic consistency.
The lingering effects of the global economic downturn have had an impact on the availability of debt financing in relation to oil sands projects. This has led some companies active in the oil sands to finance projects through public offerings. Bennett Jones’ Capital Markets Group has significant experience and expertise in assisting clients with such financing.
Alberta’s Royalty Framework
General Royalty Framework
In response to Albertans’ desire to receive a larger share from the development of Alberta’s non-renewable
energy resources, the provincial government released The New Royalty Framework on October 25, 2007,
and the changes went into effect on January 1,
In mid-2010, the Alberta government unveiled its Emerging Resources and Technologies Initiative, which modified the royalty rate for wells that require use of high-cost technologies. This strengthens a producer’s ability to invest in additional wells, as well as research and development. The government expects that stimulating application of new technologies in resources that have not been tapped will increase overall production, resulting in increased economic activity and secure long-term royalty revenue from new resource discoveries. The Emerging Resource and Technologies Initiative will be reviewed in 2014 and the Alberta government has committed to providing three years notice to industry at that time if it decides to discontinue the initiative.
The following provides a summary of oil sands royalty revenue collected by the government of Alberta from 2006 to 2012:
z 2006/07 - $2.411 billion
z 2007/08 - $2.913 billion
z 2008/09 - $2.973 billion
z 2009/10 - $3.160 billion
z 2010/11 - $3.723 billion
z 2011/12 - $4.513 billion
The BRIK Program
Alberta’s BRIK program is a key component of the province’s royalty regime. As the resource owner, the province
is entitled to take its royalty share of bitumen production in kind. The decision to exercise the in-kind option
for bitumen was identified in October 2007 as a way for the Crown to use its share of bitumen strategically
to supply potential upgraders and refineries in Alberta, and to optimize its royalty share by marketing those
volumes. A Request for Proposals to purchase or process 75,000 bbl/d of Crown-owned bitumen was issued
in July 2009 and negotiations began in May 2010. As previously described, the NWU/CNRL Refinery project
and the Alberta Carbon Trunk Line project are the first beneficiaries of the BRIK Program.
The guiding principles for the BRIK program are as follows:
The royalty regime will continue to be based on a revenue minus cost scheme.
Any changes to royalty systems and obligations will be open and transparent.
The BRIK framework will encourage a fair, efficient and openly competitive market.
Depending on the partners’ positions, some may have a greater desire for external financing than others.
2009. However, the Alberta government recently pulled back from The New Royalty Framework in the upstream natural gas and conventional oil sectors with the announcement of the Alberta Competitiveness Review changes on March 11, 2010. Citing several factors, including structural market changes, advancements in technology and regulatory barriers, the Alberta Competitiveness Review concluded that Alberta had lost competitiveness relative to other competing jurisdictions in Western Canada and the United States. To address this, several changes were implemented, including decreasing the
The BRIK market design must provide confidence to investors and customers and be supported by a clear and stable regulatory framework.
The BRIK market design should minimize the potential exercise of undue market power and unwarranted transfer of wealth.
Where operators are regulated to perform BRIK business functions, they will be compensated appropriately.
BRIK program design will seek to minimize costs to both industry and the Crown.
BRIK business rules will take operational constraints into consideration.
BRIK market design will respect the business investments that have been made in Alberta.
The BRIK market design will encourage more value added products based on bitumen in Alberta.
The government of Alberta expects that the BRIK program will stimulate value-added activities (such as
maximum royalty rates on natural gas and conventional oil. A world oil price sensitive sliding scale has been implemented for oil sands royalty rates ranging from one to nine percent of gross revenue in pre-payout and 25 to 40 percent of net revenue in post-payout.
upgrading, refining and petrochemical development) and, by assuming some risk and cost associated with
processing, enable Alberta to obtain increased revenue compared with taking cash based on bitumen pricing.
percentage of total global oil reserves in Alberta Oil Sands
The production of petroleum from oil sands uses significant amounts of energy, almost all derived from the combustion of fossil fuels and resulting in CO₂ emissions. As a result, oil sands operations have been criticized for their GHG emissions, both for the absolute amount (which is increasing rapidly) and in intensity (i.e., tonnes of CO₂ per barrel of oil) in comparison to conventional oil operations. That criticism has also driven opposition to transportation projects that would move bitumen to markets, such as TCPL’s Keystone pipeline to U.S. refineries and markets and Enbridge’s Gateway project to Pacific markets.
There are alternative perspectives on the oil sands compared to conventional oil emissions intensity difference. For example using a complete life-cycle analysis, the percentage differences between oil sands and conventional oil becomes smaller. Applying the well-to-wheels approach, in which the amount of GHG emissions for the entire life-cycle of oil is included (i.e., including extraction, processing, distribution and end use of the refined product by the consumer), GHG emissions associated with oil sands oil are often stated to be five to 15 percent higher than those for average crude oil operations. The percentage increases, however, if GHG emissions are measured for only a portion of the life-cycle, such as from extraction to distribution, i.e., well-to-pump.
Recently, disputes with the European Union and California have arisen over the treatment of oil sands oil for purposes of the Low Carbon Fuel Standards (LCFS) being developed in those jurisdictions. Canadian government, provincial government and industry officials have argued against the high GHG intensity numbers assigned to oil sands oil for purposes of those standards, suggesting that they are discriminatory and/or inaccurate. In addition, some producers in the oil sands argue that the GHG emissions intensity from their facilities is lower than from other oil sands producers and that oil sands oil should therefore not be treated in a single category. Many argue that there are significant quantities of heavy oil produced in other jurisdictions which have even higher GHG emissions per unit of production than oil from the oil sands but that those sources are not treated in the same way as the oil sands for purposes of the LCFS.
The goals of optimizing the use of oil sands and reducing the amount of GHG emissions may not be mutually exclusive. As more advanced and efficient technology is developed for oil sands mining and in situ operations,
the intensity of GHG emissions is expected to decrease, whereas it is expected to increase for conventional crude oil with the shift towards use of heavier crude oil. Industry has certainly responded, not only by the ongoing technological advances which can reduce emissions per unit of production, but also, perhaps belatedly, by a determined public relations effort to ensure the broader public discussion includes a better appreciation of the broader factual context.
Governments are providing incentives to industry to reduce emissions. The government of Canada has committed to reduce GHG emissions in Canada to 17 percent below 2005 levels by 2020 in parallel with the
U.S. and its legislation. Currently this commitment seems likely to result in the application of performance standards to large emitters on a sector by sector basis with the government having announced that oil and gas will be the next sector dealt with (vehicle standards are in place and a draft coal-fired electricity
standard has been made public). Many in industry favour greater flexibility using market-based approaches 28
like a cap-and-trade with offsets system or even a carbon tax. Alberta has imposed GHG emission intensity
reduction obligations on large GHG emitters under the Climate Change and Emissions Management Act and
the Specified Gas Emitters Regulation. This obligation can be met by operational improvements, by acquiring
Alberta-generated carbon credits or by paying to the provincial government $15 per excess tonne emitted.
The Alberta government has also committed approximately $2 billion towards the development of carbon
capture and storage (CCS), a process that involves capturing GHG emissions and storing them indefinitely in
geological formations under the earth’s surface or using them to enhance production from certain oil fields
(Enhanced Oil Production or EOR). It has also announced the intention to give extra carbon offset credits to
those who successfully sequester CO₂ in geological formations. The federal government has also committed
hundreds of millions of dollars to support CCS. While Alberta will be relying significantly on CCS to manage
emissions in the future, CCS is not without its challenges, both technical and economic.
The primary regulators for oil sands projects are the AER and Alberta Environment. However, depending on the type of oil sands operation (either surface mine or in situ extractions) and where the site is located, many other regulators can be involved. The application review process for oil sands mine operations is more in-depth than for in situ operations because of the greater land disturbance and necessity of tailings ponds. Each of the oil sands operations may require an environmental assessment and the completion of an Environmental Impact Assessment report, depending on the scope of the proposed project.
If the oil sands operation remains within the province and does not involve a federal authority, the environmental assessment will involve other provincial regulators such as Alberta Culture and Community Spirit; Alberta Health and Wellness; Alberta Tourism, Parks and Recreation; Alberta Transport; the Alberta Utilities Commission; and the Natural Resources Conservation Board.
Where the proposed oil sands project expands beyond the provincial boundaries or involves a federal authority, there will be a joint environmental assessment review conducted by provincial and federal regulators, including federal regulators such as the Canadian Environmental Assessment Agency; Environment Canada; Fisheries and Oceans Canada; Health Canada; Natural Resources Canada; Transport Canada; and Parks Canada. After the environmental assessment review is completed, the application is subject to final approval by the applicable regulatory board to determine if the proposed project is in the public interest. In making this decision, the board will balance economic, social and environmental factors and may require a hearing before a joint panel of representatives from the provincial and federal governments, the AER or a judge, as litigation could result. The board has the authority to impose conditions on any approval granted and it will continually monitor projects to ensure compliance.
The regulatory process has gradually shifted and is becoming increasingly more stringent. The ERCB has released new guidelines for oil sands mining operations and continues to make changes to some of its guidelines. Two recent ERCB directives are: Directive 081: Water Disposal Limits and Reporting Requirements for Thermal In Situ Oil Sands Schemes and Directive 082 Operating Criteria: Resource Recovery Requirements for Oil Sands Mine and Processing Plant Operations.
Although the regulatory process for Alberta oil sands are becoming more stringent, both the government and the industry remain committed to working together in the most efficient way possible to attain the
goals of maximizing returns and protecting the public interest. This is exemplified by the Responsible Energy Development Act, wherein the provincial government creates a single regulatory agency (i.e. AER) replacing the Energy Resources Conservation Board and exercising certain environmentally-oriented powers and functions previously held by the Ministry of Environment and Sustainable Resource Development. AER is responsible for regulating oil, gas, oil sands and coal developments from initial application and construction to production reclamation. The Responsible Energy Development Act was designed to establish a more efficient, integrated and collaborative regulatory system at the provincial level to maximize investment appeal.
First Nations Issues
The courts have established that both the federal and provincial governments have a duty to consult with, and where necessary accommodate, First Nations or Aboriginal people if treaty or aboriginal rights may
29 be adversely affected by government actions. Therefore, where the government of Alberta, through its regulatory agencies, intends to approve an oil sands project on or near lands over which First Nations or Métis communities have claimed traditional hunting, trapping or fishing rights, the duty to consult will be triggered.
The provincial government often delegates the procedural aspects of such consultation to project proponents. The government has developed Alberta’s First Nations Consultation Guidelines on Land Management and Resource Development, which sets out the process for determining whether consultation is necessary and the role of government departments and the project proponent in the consultation process.
The degree of consultation required depends on the strength of the rights claimed by the affected Aboriginal group and the nature and level of the potential impact on those rights. At minimum, consultation will require that the First Nation or Aboriginal group be notified of the scope, location and potential adverse impacts of the project.
Although the ultimate responsibility for the adequacy of consultation efforts lies with the government, the project proponent must meet with the affected First Nation or Aboriginal group to explain the government process and discuss the impacts on the treaty or aboriginal rights claimed, as well as avoidance or mitigation of those impacts. Where consultation is necessary, it must occur before decisions are made, i.e., during the planning of the project before the application for government approval. In addition, the environmental and regulatory approval process for a project may require the project proponent to consult with affected Aboriginal groups. Environmental impact assessments often require identification and assessment of any adverse impacts of a project on Aboriginal and treaty rights. Securing the effective participation of Aboriginal groups in these processes may require that the project proponent fund enter into consultation protocol agreements with Aboriginal groups.
Governments must ensure that adequate consultation has taken place and that appropriate accommodation of affected Aboriginal and treaty interests is undertaken if necessary. Failure to adequately consult and, if necessary, accommodate Aboriginal concerns puts the project developer at risk of having project approvals challenged in Court, and potentially quashed on the basis that they violate constitutionally-protected Aboriginal and treaty rights.
Proponents of large oil sands projects with the potential to significantly impact the traditional territories of Aboriginal groups may also negotiate impact benefit agreements with affected Aboriginal groups to ensure effective consultation and address concerns related to the proposed projects. These agreements may address commitments made in the regulatory and environmental review process, funding arrangements to address social concerns (such as educational and training opportunities), environmental mitigation and consultation and information-sharing protocols for the long term. Increasingly, First Nations and other Aboriginal groups are seeking agreements whereby their communities would secure long-term economic benefits from oil sands development on their traditional lands.
Among the many rewards for investors in the Canadian oil sands are:
z A substantial resource base with a long reserve life and an opportunity to increase reportable reserves.
z A long-range forecast of little or no decline in production over a 25-year period.
z A stable political environment with well-developed, sophisticated and continually improving legal and regulatory regimes.
Investors are strongly advised to take legal advice early in their strategizing from legal counsel with extensive experience in the unique nature of oil sands transactions and projects. Bennett Jones LLP has played an integral role in the Canadian oil and gas industry for nearly 90 years and has extensive contacts throughout the industry. We are happy to answer questions from prospective investors.