North American Oil Sands: History of Development, Prospects for the Future
Released: 2008-01-17T00:00:00

Introduction

Current world oil reserves are estimated at 1.292 trillion barrels. The Middle East accounts for 58% of world oil reserves, and the Organization of Petroleum Exporting Countries (OPEC) accounts for 70%. The Middle East also leads in reserve growth and undiscovered potential, according to the Energy Information Administration (EIA).

The United States' total oil reserves are estimated at 22.7 billion barrels, a scant 1.8% of the world's total (see Appendix A ). U.S. crude oil production is expected to fall from 5.4 million barrels per day (mbd) in 2004 to 4.6 mbd in 2030, while demand edges up at just over 1% annually. Net imports of petroleum are estimated by the EIA to increase from 12.1 mbd (58% of U.S. consumption) to 17.2 mbd (62% of U.S. consumption) over the same time period.

When it comes to future reliable oil supplies, Canadian oil sands will likely account for a larger share of U.S. oil imports. Oil sands account for about 46% of Canada's total oil production, and oil sand production is increasing as conventional oil production declines. Since 2004, when a substantial portion of Canada's oil sands were deemed economic, Canada has been ranked second behind Saudi Arabia in oil reserves. Canadian crude oil exports were about 1.82 million barrels per day in 2006, of which 1.8 mbd or 99% went to the United States. Canadian crude oil accounts for about 18% of U.S. net imports and about 12% of all U.S. crude oil supply.

An infrastructure to produce oil, upgrade, refine, and transport it from Canadian oil sand reserves to the United States is already in place. Oil sands production is expected to rise from its current level of 1.2 (mbd) to 2.8 mbd by 2015. However, infrastructure expansions and skilled labor are necessary to significantly increase the flow of oil from Canada. For example, many refineries are optimized to refine only specific types of crude oil and may not process bitumen from oil sands. One issue likely to be contentious is the regulatory permitting of any new refinery capacity because of environmental concerns such as water pollution and emissions of greenhouse gases.

Challenges such as higher energy costs, infrastructure requirements, and the environment, may slow the growth of the industry. For example, high capital and energy input costs have made some projects less economically viable despite recent high oil prices. Canada ratified the Kyoto Protocol in 2002, which bound Canada to reducing its greenhouse gas (GHG) emissions significantly by 2012 but according to the government of Canada they will not meet their Kyoto air emission goals by 2012. The Pembina Institute reports that the oil sands industry accounts for the largest share of GHG emissions growth in Canada.

Major U.S. oil companies (Sunoco, Exxon/Mobil, Conoco Phillips, and Chevron) continue to make significant financial commitments to develop Canada's oil sand resources. Taken together, these companies have already committed several billion dollars for oil sands, with some projects already operating, and others still in the planning stages. Many of these same firms, with the U.S. government, did a considerable amount of exploration and development on "tar sands" in the United States, conducting several pilot projects. These U.S. pilot projects did not prove to be commercially viable for oil production and have since been abandoned. Because of the disappointing results in the United States and the expansive reserves in Canada, the technical expertise and financial resources for oil sands development has shifted almost exclusively to Canada and are likely to stay in Canada for the foreseeable future. However, with current oil prices above $60 per barrel and the possibility of sustained high prices, some oil sand experts want to re-evaluate the commercial prospects of U.S. oil sands, particularly in Utah.

This CRS report examines the oil sands resource base in the world, the history of oil sands development in the United States and Canada, oil sand production, technology, development, and production costs, and the environmental and social impacts. The role of government—including direct financial support, and tax and royalty incentives—is also assessed.

World Oil Sands Reserves and Resources4

Over 80% of the earth's technically recoverable natural bitumen (oil sands) lies in North America, according to the U.S. Geological Survey (USGS) (see Appendix B ). Canadian oil sands account for about 14% of world oil reserves and about 11% of the world's technically recoverable oil resources.

What Are Oil Sands?

Oil sands (also called tar sands) are mixtures of organic matter, quartz sand, bitumen, and water that can either be mined or extracted in-situ using thermal recovery techniques. Typically, oil sands contain about 75% inorganic matter, 10% bitumen, 10% silt and clay, and 5% water. Bitumen is a heavy crude that does not flow naturally because of its low API (less than 10 degrees) and high sulfur content. The bitumen has high density, high viscosity, and high metal concentration. There is also a high carbon-to-hydrogen molecule count (i.e. oil sands are low in hydrogen). This thick, black, tar-like substance must be upgraded with an injection of hydrogen or by the removal of some of the carbon before it can be processed.

Oil sand products are sold in two forms: (1) as a raw bitumen that must be blended with a diluent (becoming a bit-blend) for transport and (2) as a synthetic crude oil (SCO) after being upgraded to constitute a light crude. The diluent used for blending is less viscous and often a by-product of natural gas, e.g., a natural gas condensate. The specifications for the bit blend (heavy oil) are 21.5 API and a 3.3% sulfur content and for the SCO (light oil) are 36 API and a 0.015% sulfur content.

U.S. Oil Sand Resources

The USGS, in collaboration with the U.S. Bureau of Mines, concluded in a 1984 study that 53.7 billion barrels (21.6 billion measured plus 32.1 billion speculative) of oil sands could be identified in the United States. An estimated 11 billion barrels of those oil sands could be recoverable. Thirty-three major deposits each contain an estimated 100 million barrels or more. Fifteen percent were considered mineable and 85% would require in-situ production. Some of the largest measured U.S. oil sand deposits exist in Utah and Texas. There are smaller deposits located in Kentucky, Alabama, and California. Most of the deposits are scattered throughout the various states listed above. As of the 1980s, none of these deposits were economically recoverable for oil supply. They are still not classified as reserves (see Figure 1 ).

Canadian Oil Sand Resources

Canadian oil sand resources are located almost entirely in the province of Alberta. The Alberta Energy and Utility Board (AEUB) estimates that there are 1.6 trillion barrels of oil sands in place, of which 11% are recoverable (175 billion barrels) under current economic conditions (see Table 1 ). Mineable reserves at the surface account for 35 billion barrels (20%) and in-situ reserves at 141 billion barrels (80%). The AEUB estimates that the ultimate amount to be discovered (ultimate volume-in place) is 2.5 trillion barrels: about 2.4 trillion in-situ and 140 billion surface-mineable. Of this ultimate discovered amount, about 314 billion barrels are expected to be recovered (175 billion barrels in reserves now and another 143 billion barrels anticipated. See Table 1 ). However, EIA estimates only 45.1 billion barrels (reserve growth and undiscovered potential) to be added to Canada's reserve base by 2025.

Oil sands occur primarily in three areas of Alberta: Peace River, Athabasca, and Cold Lake (see Figure 2 below). Current production is 1.1 million barrels per day and is expected to reach 2.0 mbd by 2010 and 3.0 mbd by 2015. According to the International Energy Agency (IEA), Canada's oil sands production could exceed 5.0 mbd by 2033 but would require at least $90 billion in investment.

As a result of recent high oil prices, 44 new oil sands projects are planned for Alberta between 2004 and 2012, 26 in-situ and 18 surface-mining. If all projects were to go forward, an estimated C$60 billion would be required for construction. Several of the projects are expansions of current operations. The National Energy Board (NEB) projects as much as C$81.6 billion being spent between 2006 and 2016. Eighty-two percent of the projected investment—expected to peak in 2008—is directed towards the Fort McMurray/Woods Buffalo Region of Alberta. A total of C$29 billion was spent on oil sands development between 1996 and 2004.

History of Development

Role of Industry and Government

U.S. Oil Sands

Interest in U.S. oil sand deposits dates back to the 1930s. Throughout the 1960s and 1970s, 52 pilot projects involving mining and in-situ techniques were supported by the U.S. government in collaboration with major oil companies such as Conoco, Phillips Petroleum, Gulf Oil, Mobil, Exxon, Chevron, and Shell. Several steam-assisted technologies were being explored for in-situ production. These sources have had little economic potential as oil supply. The Energy Policy Act of 2005 ( P.L. 109-58 ), however, established a public lands leasing program for oil sands and oil shale R&D.

Based on the Canadian experience with oil sands production, it was established that commercial success in mining oil sands is a function of the ratio of overburden to oil sand thickness. This ratio should not exceed one. In other words, the thickness of the overlying rock should not be greater than the thickness of the sand deposit. It was estimated by the USGS that only about 15% of the U.S. resource base has a ratio of one or less.

Major development obstacles to the U.S. oil sands resource base include remote and difficult topography, scattered deposits, and the lack of water for in-situ production (steam recovery and hot water separation) or undeveloped technology to extract oil from U.S. "hydrocarbon-wetted" deposits. The Canadian technology may not be suited for many U.S. deposits. In Texas, deposits were considered by Conoco Oil to be too viscous to produce in-situ. A Bureau of Mines experiment with oil sands production in Kentucky proved to be commercially infeasible. In Utah, there were attempts at commercial production over the past three decades by several oil companies but projects were considered uneconomic and abandoned. As of 2004, some oil sands were being quarried on Utah state lands for asphalt used in road construction, and a small amount of production is taking place in California. "Since the 1980s there has been little production for road material and no government funding of oil sands R&D," according to an official at the Department of the Interior.

A 2006 conference on oil sands held at the University of Utah indicated renewed interest in U.S. oil sands but reiterated the development challenges mentioned above. Speakers also pointed out new technologies on the horizon that are being tested in Utah. Conference organizers concurred that long-term research and development funding and huge capital development costs would be needed to demonstrate any commercial potential of U.S. oil sand deposits. A recent report on U.S. unconventional fuels (an interagency and multistate collaboration) makes a number of general recommendations (for the development of oil sands and other unconventional fuels), which include economic incentives, establishing a regulatory framework, technology R&D, and an infrastructure plan. A recommendation specific to oil sands calls for closer U.S. collaboration with the government of Alberta to better understand Canadian oil sands development over the last 100 years. The report's task force estimates that based on a "measured" or "accelerated" development pace scenario, U.S. oil sand production could reach 340,000-352,000 barrels per day by 2025.

Canadian Oil Sands

Canada began producing its oil sands in 1967 after decades of research and development that began in the early 1900s. Wells were drilled between 1906 and 1917 in anticipation of finding major conventional oil deposits. The area around Fort McMurray, Alberta, was mapped for bituminous sand exposures in 1913 by Canada's Federal Department of Mines. By 1919, the Scientific and Industrial Research Council of Alberta (SIRCA), predecessor to the Alberta Research Council (ARC), became interested in oil sands development. One of its newly recruited scientists, Dr. Karl Clark, began his pioneering work on a hot-water flotation process for separating the bitumen from the sand. In this separation process, the mined oil sand is mixed with water and a sodium hydroxide base and rotated in a horizontal drum at 80 degrees centigrade. Dr. Clark's efforts led to a pilot plant in 1923 and a patented process by 1929. He continued to improve the process through several experimental extraction facilities through the 1940s.

The technical feasibility was demonstrated in 1949 and 1950 at a facility in Bitumont, Alberta, located on the Athabasca River near Fort McMurray. The technology being tested was largely adopted by the early producers of oil sands—Great Canadian Oil Sands (GCOS), Ltd., and Syncrude. Sunoco established GCOS, Ltd., in 1952 and then invested $250 million in its oil sands project. Another major player in the oil sands business in Canada was Cities Services, based in Louisiana. Cities Services purchased a controlling interest in the Bitumont plant in 1958, then in 1964, along with Imperial Oil, Atlantic Richfield (ARCO), and Royalite Oil, formed the Syncrude consortium.

The ARC continued its involvement with oil sands R&D throughout the 1950s and 1960s. Several pilot projects were established during that period. Suncor began construction of the first commercial oil sands production/separation facility in 1964 and began production in 1967, using the hot water extraction method developed and tested by ARC. In 1967, Suncor began to produce oil sands at a rate of 12,000 barrels per day.

Just a year later, in 1968, the government of Alberta deferred an application by Syncrude Canada for a $200 million, 80,000 barrel oil sands facility. Eventually, in 1978, the Energy Resources Conservation Board of Alberta approved Syncrude's proposal to build a $1 billion plant that would produce up to 129,000 barrels per day. However, ARCO, which represented 30% of the project, pulled out of the consortium as costs of the plant climbed toward $2 billion. At that point (1978) the federal and provincial governments joined in. The federal government purchased a 15% share, Alberta a 10% share, and Ontario 5%, making up the 30% deficit. At the time, the Canadian government was promoting the goal of energy self-sufficiency, and the Alberta government agreed to a 50/50 profit-sharing arrangement instead of normal royalties for Syncrude.

The Alberta Energy Company purchased 20% of Syncrude and then sold 10% of its share to Petrofina Canada, Ltd., and Hudson Bay Oil and Gas, Ltd. The consortium grew from four to nine owners. From 1983 to 1988 Syncrude spent $1.6 billion to boost production to 50 million barrels per year. In 1984, the government of Alberta agreed to a new royalty structure for oil sands producers coinciding with Syncrude's capital expansion plans. In 1985, the Alberta government announced that existing oil sands operations and new plants would not be taxed on revenues, and the petroleum gas revenue tax would be phased out. During the same time-frame, Syncrude's cash operating costs were just under $18 per barrel with total costs over $20 per barrel, while the market price of oil fluctuated under $20 per barrel.

Because of huge capital requirements, oil sands producers lobbied for continued royalty relief and thought the government should "defer tax and royalty revenues until project expansions were completed." In 1994, the National Oil Sands Task Force (an industry/government group) was created, and the Canadian Oil Sands Network for R&D (CONRAD) agreed to spend $105 million annually to boost production and trim costs. Costs continued to fall ($15.39/bbl in 1992 to under $14/ bbl in 1994 ) as Syncrude ownership continued to change. In 1996, the National Oil Sands Task Force recommended a package of royalty and tax terms to ensure consistent and equal treatment of projects, because oil sand projects previously were treated on a project-by-project basis. The implementation of favorable royalty treatment is discussed below.

The ARC has had a successful partnership with the private sector in oil sands research and development. As a result of favorable royalty and tax terms and Alberta's $700 million R&D investment in oil sands extraction (from 1976-2001), the private sector has invested billions of dollars of development capital in oil sand projects. Syncrude has said that "partnering with ARC gave us the ability to explore a potentially valuable technology."

Oil Sands Production Process

Oil sands production measured only 1.3% of total world crude oil production in 2005. By 2025 it may reach 4.1% of total world production. But more importantly, it may mean U.S. access to extensive North American oil reserves and increased energy security.

Oil sands are either surface-mined or produced in-situ. Mining works best for deposits with overburden less than 75 meters thick. Mining requires a hydraulic or electric shovel that loads the sand into 400-ton trucks, which carry the material to a crusher to be mixed into a slurry. Using pumps and pipelines, the slurry is "hydro transported" to an extraction facility to extract bitumen (see Figure 3 ). This process recovers about 90% of the bitumen.

In 2005, mining accounted for about 52% of Alberta's oil sand production (572,000 b/d); in-situ accounted for about 48% (528,000 b/d), one-third of which was produced using the Cold Production method in which oil sands are light enough to flow without heat. The in-situ approach, which was put into commercial production in 1985, is estimated to grow to 926,000 barrels per day by 2012. Currently, the largest production projects are in the Fort McMurray area operated by Syncrude and Suncor (see Table 4 for leading producers of oil sands).

Extraction Process

The extraction process separates the bitumen from oil sands using warm water (75 degrees Fahrenheit) and chemicals. Extracting the oil from the sand after it is slurried consists of two main steps. First is the separation of bitumen in a primary separation vessel. Second, the material is sent to the froth tank for diluted froth treatment to recover the bitumen and reject the residual water and solids. The bitumen is treated either with a naphtha solvent or a paraffinic solvent to cause the solids to easily settle. The newer paraffinic treatment results in a cleaner product. This cleaner bitumen is pipeline quality and more easily blended with refinery feedstock. After processing, the oil is sold as raw bitumen or upgraded and sold as SCO.

Production Technology

For in-situ thermal recovery, wells are drilled, then steam is injected to heat the bitumen so it flows like conventional oil. In-situ production involves using various techniques.

One technique is the Cyclic Steam Stimulator (CSS), also known as "huff and puff." CSS is the most widely used in-situ technology. In this process, steam is added to the oil sands via vertical wells, and the liquefied bitumen is pumped to the surface using the same well.

But a relatively new technology—steam-assisted gravity drainage (SAGD)—has demonstrated that its operations can recover as much as 70% of the bitumen in-place. Using SAGD, steam is added to the oil sands using a horizontal well, then the liquefied bitumen is pumped simultaneously using another horizontal well located below the steam injection well (see Figure 4 ). The SAGD process has a recovery advantage over the CSS process, which only recovers 25%-30% of the natural bitumen. Also, the lower steam to oil ratio (the measurement of the volume of steam required to extract the bitumen) of SAGD results in a more efficient process that uses less natural gas. SAGD operations are limited to thick, clean sand reservoirs, but it is reported by the industry that most of the new in-situ projects will use SAGD technology. A number of enhanced SAGD methods are being tested by the Alberta Research Council. They could lead to increased recovery rates, greater efficiency, and reduced water requirements.

The emerging Vapor Extraction Process (VAPEX) technology operates similarly to SAGD. But instead of steam, ethane, butane, or propane is injected into the reservoir to mobilize the hydrocarbons towards the production well. This process eliminates the cost of steam generators and natural gas. This method requires no water and processing or recycling and is 25% lower in capital costs than the SAGD process. Operating costs are half that of the SAGD process.

A fourth technique is cold production, suitable for oil sands lighter than those recovered using thermal assisted methods or mining. This process involves the co-production of sand with the bitumen and allows the oil sands to flow to the well bore without heat. Imperial Oil uses this process at its Cold Lake site. Oil sand produced using in-situ techniques is sold as natural bitumen blended with a diluent for pipeline transport.

The overall result of technology R&D has been to reduce operating costs from over $20/barrel in the early 1970s to $8-12/barrel in 2000. While technology improvements helped reduce some costs since 2000, total costs have risen significantly as discussed below, because of rising capital and energy costs.

Upgrading46

Upgrading the bitumen uses the process of coking for carbon removal or hydro-cracking for hydrogen addition (see Figure 5 ). Coking is a common carbon removal technique that "cracks" the bitumen using heat and catalysts, producing light oils, natural gas, and coke (a solid carbon byproduct). The coking process is highly aromatic and produces a low quality product. The product must be converted in a refinery to a lighter gas and distillate. Hydrocracking also cracks the oil into light oils but produces no coke byproduct. Hydrocracking requires natural gas for conversion to hydrogen. Hydrocracking, used often in Canada, better handles the aromatics. The resulting SCO has zero residues which help keep its market value high, equivalent to light crude.

Partial upgrading raises the API of the bitumen to 20-25 degrees for pipeline quality crude. A full upgrade would raise the API to between 30-43 degrees—closer to conventional crude. An integrated mining operation includes mining and upgrading. Many of the mining operations have an on-site upgrading facility, including those of Suncor and Syncrude. Suncor uses the coking process for upgrading, while Syncrude uses both coking and hydrocracking and Shell uses hydrocracking. (For the complete oil sands processing chain, see Figure 6 .)

A major trend among both mining and in situ producers is to integrate the upgrading with the refinery to cut costs; e.g., linking SAGD production with current refinery capabilities. Long-term processing success of oil sands will depend on how well this integration takes place and how well the industry addresses the following issues:

cost overruns, cost effective upgrading, reducing highly aromatic, high-sulfur SCO, and dependence on and price of natural gas for hydrogen production (originally used because of its low price but now considered by some to be too expensive).

The wide heavy-oil/light-oil price differential has been an incentive to increase upgrading. The price for heavy crude was as low as $12 per barrel in early 2006 and its market is limited by refineries that can process it and by its end use as asphalt. In its June 2006 report, the NEB describes numerous proposals for building upgraders.

Cost overruns for the integrated mining projects or expansions, sometimes as much as 50% or more of the original estimates, have been a huge problem for the industry. The main reasons cited by the COS report are poor management, lack of skilled workers, project size, and engineering issues.

Cost of Development and Production

Operating and total supply costs have come down significantly since the 1970s. Early supply costs were near C$35 per barrel (in 1970s dollars). Reductions came as a result of two major innovations in the production process. First, power shovels and energy efficient trucks replaced draglines and bucketwheel reclaimers, and second, hydrotransport replaced conveyor belts to transport oil sands to the processing plant.

Operating costs include removal of overburden, mining and hydro transport, primary extraction, treatment, and tailings removal. The recovery rate, overburden volumes, cost of energy, transport distances, and infrastructure maintenance all have an impact on operating costs.

Supply costs (total costs) include the operating costs, capital costs, taxes and royalties, plus a 10% return on investment (ROI). When compared to conventional new oil production starts, an oil sands project may have operating costs over 30% higher than the world average for conventional new starts. However, its nearly nonexistent royalty and tax charge makes the total cost per barrel of energy significantly less than the conventional oil project. The NEB in its Energy Market Assessment estimated that between US$30-$35 per barrel oil is required to achieve a 10% ROI.

Operating costs for mining bitumen were estimated at around C$9-$12 per barrel (C$2005)—an increase of up to C$4 per barrel since the 2004 NEB estimates. Supply cost of an integrated mining/upgrading operation is between C$36 and $40/ barrel for SCO—a dramatic increase over the C$22-$28 estimate made in 2004. These supply costs for an integrated mining/upgrading operation were expected to decline with improvements in technologies (see Table 3 ). However, natural gas prices rose 88% and capital costs rose 45% over the past two years.

Operating costs for SAGD in-situ production in 2005 were about C$10-$14 per barrel of bitumin, up from C$7.40 per barrel in 2004. Recovery rates are lower than with mining, at 40%-70%, and the price of energy needed for production is a much larger factor. The SAGD operations are typically phased-in over time, thus are less risky, make less of a "footprint" on the landscape than a mining operation, and require a smaller workforce. SAGD supply cost for Athabasca oil sand rose from between C$11-$17/barrel (bitumen) to C$18-$22/barrel; using the CSS recovery technique, supply costs are estimated higher at between C$20-$24/barrel, an increase from C$13-$19/barrel. Cost increases/decreases for in-situ operations are largely dependent on the quality of the reservoir and natural gas prices, but as SAGD and other new technologies (e.g. VAPEX) become more efficient, industry is expecting some cost declines. SAGD (in-situ) supply costs are less sensitive to capital costs than mining projects because the capital investment is far less.

Natural gas is a major input and cost for mining, upgrading, and in situ recovery: Mining requires natural gas to generate heat for the hot water extraction process, upgraders need it for heat and steam, and in situ producers use natural gas to produce steam which is injected underground to induce the flow of bitumen. Natural gas accounts for 15% of the operating costs in mining operations compared to 60% of operating costs in SAGD in-situ production. The major cost for thermal in-situ projects (SAGD, CSS) is for the natural gas that powers the steam-producing generators. For SAGD projects, 1 thousand cubic feet is needed per barrel of bitumen. Reducing the steam-to-oil ratio (SOR)—the quantity of steam needed per barrel of oil produced—is critical for lowering natural gas use and costs. SAGD has a lower SOR than CSS projects but cannot be used for all oil sand in-situ production. However, most new in-situ projects will use SAGD.

Canadian oil sand producers continue to evaluate energy options that could reduce or replace the need for natural gas. Those options include, among other things, the use of gasification technology, cogeneration, coal, and nuclear power.

Tax and Royalty on Oil Sands

In 1997 the Alberta government implemented a "Generic Oil Sands Royalty Regime" specific to oil sands for all new investments or expansions of current projects. Since then, oil sand producers have had to pay a 1% minimum royalty based on gross revenue until all capital costs including a rate of return are recovered. After that, the royalty is either 25% of net project revenues or 1% of the gross revenues, whichever is greater. The 1% pre-payout royalty rate is in stark contrast to conventional world royalties. Net project revenues (essentially net profits before tax) include revenues after project cash costs, such as operating costs, capital, and R&D are deducted. Royalty payments may be based on the value of bitumen or SCO if the project includes an upgrader. Currently, 51% of oil sand projects (or 75% of production volume) under the Generic Royalty regime are paying the 25% royalty rate. Two major oil sands producers, Suncor and Syncrude (accounting for 49% of bitumen production) have "Crown Agreements" in place with the province that have allowed the firms to pay royalties based on the value of synthetic crude oil (SCO) production with the option to switch to paying royalties on the value of bitumen beginning as early as 2009. Royalties paid on bitumen, which is valued much lower than SCO, would result in less revenue for the government. The agreements expire in 2016.

Royalty revenues from oil sands fluctuated widely between 1997 and 2005. For example, royalties from oil sands were less than $100 million in 1999, then rose to $700 million in 2000/2001, but fell in 2002/2003 to about $200 million as production continued to rise. Royalties from oil sands rose dramatically in 2005/2006 to $1 billion, and the Government of Alberta forecasts royalties of $2.5 billion in 2006/2007 and $1.8 billion in 2007/2008. Oil price fluctuations are the primary cause for such swings in royalty revenues.

The Albertan provincial government established a Royalty Review Panel in February 2007 to examine whether Alberta was receiving its fair share of royalty revenues from the energy sector and to make recommendations if changes are needed. In its September 2007 report, the panel concluded that "Albertans do not receive their fair share from energy development." When the oil sands industry was ranked against other heavy oil and offshore producers such as Norway, Venezuela, Angola, United Kingdom, and the U.S. Gulf of Mexico, Alberta received the smallest government share. This is, however, a difficult comparison to make because it is not among oil sand producers only and the fiscal regimes of the various producing countries is dynamic. However, based on a general analysis by T.D. Securities, typically, on average, world royalty rates could add as much as 45% to operating costs while the 1% rate may add only 3% to operating costs.

The Panel recommended keeping the "pre-payout, post-payout" framework intact (see footnote 52 ), which would retain the 1% pre-payout royalty rate, but in the post-payout phase, firms would be required to pay a higher net revenue royalty rate of 33% plus continue to pay the 1% base royalty.

On October 25, 2007, the Alberta Government announced and published its response to the Royalty Review Panel's report. It retained the "pre-payout," "post-payout" royalty framework but concluded that a sliding-scale rate structure would best achieve increasing the government's share of revenues from oil sands production. The pre-payout base rate would start at 1%, then increase for every dollar above US$55 per barrel (using the West Texas Intermediate or WTI price) reaching a maximum increase of 9% when prices are at or above $120 per barrel. In the post-payout phase, the net revenue rate will start at 25%, then rise for every dollar oil in priced above US$55 per barrel, reaching a maximum of 40% of net revenues when oil is $120 per barrel or higher. The new rate structure will take effect in 2009. The Government of Alberta has initiated negotiations with Suncor and Syncrude in an attempt to include them under the new oil sands royalty framework by 2009.

Oil sand firms pay federal and provincial income taxes and some differences exist in the tax treatment of the oil sands and conventional oil industries. Since the Provincial 1996 Income Tax Act, both mineable and in-situ oil sand deposits are classified as a mineral resource for Capital Cost Allowance (CCA) purposes which means mineral deposits receive higher cost deductions than conventional oil and gas operations (i.e. acquisition costs and intangible drilling costs). The provincial government of Alberta has agreed to the 2007 federal budget proposal to eliminate the CCA deduction for oil sands. The Royalty Review Panel also supported this change in its report. The federal government of Canada, however, provided some balance by reducing the general federal corporate income tax rate from 22.1% to 15% beginning in 2012.

U.S. Markets

Oil sand producers continue to look to the United States for the majority of their exports. Seventy-five percent of Canadian nonconventional oil exported to the United States is delivered to the Petroleum Administration for Defense District (PADD) II in the Midwest. This region is well positioned to receive larger volumes of nonconventional oil from Canada because of its refinery capabilities. Several U.S.-based refinery expansions have been announced that would come online between 2007-2015. If Canada were to reach its optimistic forecasted oil sands output level of 5 mbd in 2030, and maintained its export level to the United States at around 90%, it would be exporting about 4.5 mbd to the United States. This would mean that imports from Canada would reach nearly 30% of all U.S. crude oil imports. U.S. refinery capacity is forecast to increase from 16.9 mbd in 2004 to nearly 19.3 mbd in 2030, a 2.4 mbd increase—significant but perhaps not enough to accommodate larger volumes of oil from Canada, even if refinery expansions would have the technology to process heavier oil blends. Canada is pursuing additional refinery capacity for its heavier oil.

Pipelines

Oil sands are currently moved by two major pipelines (the Athabasca and the Corridor, not shown in Figure 7 ) as diluted bitumen to processing facilities in Edmonton. After reaching refineries in Edmonton, the synthetic crude or bitumen is moved by one of several pipelines to the United States (see Figure 7 ). The Athabasca pipeline has capacity of 570,000 barrels per day (b/d) while the Corridor has capacity of less than 200,000 b/d. Current pipeline capacity has nearly reached its limit. However, there are plans to increase Corridor's capacity to 610,000 b/d by 2010.

A number of new pipeline projects have been proposed or initiated that would increase the flow of oil from Canada to the United State's PADDs II, III, and V. Most of the new projects are scheduled to come online between 2008 and 2012. In addition, a couple of U.S. pipelines reversed their flow of crude oil (from south to north) to now carry Canadian heavy crude, originating from oil sands, to Cushing Oklahoma and Southeast Texas. Pipeline capacity could be a constraint to growth in the near term but the NEB predicts some excess pipeline capacity by 2009. An estimated $31.7 billion has been invested in pipeline projects for oil sands in western Canada.

Environmental and Social Issues

The Federal Government of Canada classified the oil sands industry as a large industrial air pollution emitter (i.e., emitting over 8,000 tons CO 2 /year) and expects it to produce half of Canada's growth in greenhouse gas (GHG) emissions (about 8% total GHG emissions) by 2010. The oil sands industry has reduced its "emission intensity" by 29% between 1995-2004 while production was rising. CO 2 emissions have declined from 0.14 tons/bbl to about 0.08 tons/bbl or about 88 megatons since 1990. Alberta's GHG goals of 238 megatons of CO 2 in 2010, and 218 megatons CO 2 in 2020 are not expected to be met. Reducing air emissions is one of the most serious challenges facing the oil sands industry. However, according to the Pembina Institute, a sustainable energy advocate, greenhouse gas emissions intensity (CO 2 /barrel) from oil sands is three times as high as that from conventional oil production. The industry believes if it can reduce energy use it can reduce its emissions. As emissions per barrel of oil from oil sands decline overall, the Canadian government projects that total GHG emissions will continue to rise through 2020, attributing much of the increase to increased oil sands production.

Water supply and waste water disposal are among the most serious concerns because of heavy use of water to extract bitumen from the sands. For an oil sands mining operation, about 2-3 barrels of water are used from the Athabasca river for each barrel of bitumen produced; but when recycled produced water is included, 0.5 barrels of "make-up" water is required, according to the Alberta Department of Energy. Oil sands projects currently divert 150 million cubic meters of water annually from the Athabasca River but are approved to use up to 350 million cubic meters. Concerns, however, arise over the inadequate flow of the river to maintain a healthy ecosystem and meet future needs of the oil sands industry. Additionally, mining operations impact freshwater aquifers by drawing down water to prevent pit flooding.

The freshwater used for in-situ operations is needed to generate steam, separate bitumen from the sand, hydrotransport the bitumen slurry, and upgrade the bitumen to a light crude. For SAGD operations, 90-95% of all the water used is recycled. Since some water is lost in the treatment process, additional freshwater is needed. To minimize the use of new freshwater supplies, SAGD operators use saline water from deeper underground aquifers. The use of saline water, however, generates huge volumes of solid waste which has posed serious disposal problems.

Wastewater tailings (a bitumen, sand, silt, and fine clay particles slurry) also known as "fluid fine tailings" are disposed in large ponds until the residue is used to fill mined-out pits. Seepage from the disposal ponds can result from erosion, breaching, and foundation creep. The principal environmental threat is the migration of tails to a groundwater system and leaks that might contaminate the soil and surface water. The tailings are expected to reach 1 billion cubic meters by 2020. Impounding the tailings will continue to be an issue even after efforts are made to use alternative extraction technology that minimizes the amount of tails. Tailings management criteria were established by the Alberta Energy and Utilities Board/Canadian Environmental Assessment Agency in June 2005. Ongoing extensive research by the Canadian Oil Sands Network for Research and Development (CONRAD) is focused on the consolidation of wastewater tailings, detoxifying tailings water ponds, and reprocessing tailings. Some R&D progress is being made in the areas of the cleanup and reclamation of tailings using bioremediation and electrocoagulation.

The National Research Council of Canada (NRC) is conducting research to treat wastewater tailings and recover their byproduct residual bitumen, heavy metals, and amorphous solids (fertilizers). A pilot project is underway to clean and sort tailings, and recover metals such as aluminum and titanium.

Surface disturbance is another major issue. The oil sands industry practice leaves land in its disturbed state and left to revegetate naturally. Operators, however, are responsible over the long term to restore the land to its previous potential. Under an Alberta Energy Utility Board directive (AEUB), Alberta's Upstream Oil and Gas Reclamation and Remediation Program has expanded industry liability for reclaiming sites. The directive requires a "site-specific liability assessment" that would estimate the costs to abandon or reclaim a site.

The government of Alberta's Department of the Environment established a "Regional Sustainable Development Strategy" whose purpose is, among other things, to "ensure" implementation of management strategies that address regional cumulative environmental impacts. The oil sands industry is regulated under the Environmental Protection and Enhancement Act, Water Act, and Public Lands Act. Oil sands development proposals are reviewed by AEUB, Alberta Environment, and the Alberta Sustainable Resource Development at the provincial level. Review at the federal level may also occur.

Issues for Congress

The Energy Policy Act of 2005 ( P.L. 109-58 ) describes U.S. oil sands (along with oil shale and other unconventional fuels) as a strategically important domestic resource "that should be developed to reduce the growing dependence of the United States on politically and economically unstable sources of foreign oil imports." The provision also requires that a leasing program for oil sands R&D be established. Given U.S. oil sands' strategic importance, but limited commercial success as discussed above, what level of federal investment is appropriate to reach U.S. energy policy goals? While an estimated 11 billion barrels of U.S. oil sands may be significant if it were economic, it represents a small share of the potentially recoverable resource base of unconventional fuels (e.g., 800 billion barrels of potentially recoverable oil from oil shale and another 20 billion barrels of recoverable heavy oil). Where is the best return on the R&D dollar invested for increased domestic energy supply and what are the long-term prospects for commercial application of unconventional fuels technology? Another important consideration to look at is where the oil industry is investing its capital and R&D for oil sands projects.

In light of the environmental and social problems associated with oil sands development, e.g., water requirements, toxic tailings, carbon dioxide emissions, and skilled labor shortages, and given the fact that Canada has 175 billion barrels of reserves and a total of over 300 billion barrels of potentially recoverable oil sands (an attractive investment under current conditions demonstrated by the billions of dollars already committed to Canadian development), the smaller U.S. oil sands base may not be a very attractive investment in the near-term.

U.S. refinery and pipeline expansions are needed to accommodate Canadian oil sands developments. Those expansions will have environmental impacts, but the new infrastructure could strengthen the flow of oil from Canadian oil sands. This expanded capacity will likely lead to even greater investment in Canada.

Whether U.S. oil sands are developed, Congress will continue to be faced with regulatory matters. Oil imports from oil sands are likely to increase from Canada and the permitting of new or expanded oil refineries will continue to be an issue because of the need to balance concerns over the environment on one hand and energy security on the other.

Prospects for the Future

Because capital requirements for oil sands development has been enormous and risky, government involvement was seen as being essential in Canada, particularly during sustained periods of low oil prices. This private sector/government partnership in R&D, equity ownership, and public policy initiatives over the last 100 years has opened the way for the current expansion of the oil sands industry in Alberta.

Ongoing R&D efforts by the public and private sectors, sustained high oil prices, and favorable tax and royalty treatment are likely to continue to attract the increasing capital expenditures needed for growth in Canada's oil sands industry. Planned pipeline and refinery expansions and new upgrading capacity are underway to accommodate the increased volumes of oil sands production in Canada. U.S. markets will continue to be a major growth area for oil production from Canadian oil sands. Currently, about 5% of the total oil refined in the United States is from Canada's oil sands.

Even though prospects for Canadian oil sands appear favorable, factors such as water availability, waste water disposal, air emissions, high natural gas costs, insufficient skilled labor, and infrastructure demands may slow the pace of expansion.

Prospects for commercial development of U.S. oil sands are uncertain at best because of the huge capital investment required and the relatively small and fragmented resource base. The Task Force on Strategic Unconventional Fuels reported that oil sands comprise only about 0.6% of U.S. solid and liquid fuel resources, while oil shale accounts for nearly 25% of the total resource base.

Appendix A. Estimated World Oil Resources

Appendix B. Regional Distribution of Estimated Technically Recoverable Heavy Oil and Natural Bitumen

Acronyms and Abbreviations