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The Economics of Canadian Oil Sands
Anthony Heyes,* Andrew Leach,
†
and Charles F. Mason
‡
Introduction
The large-scale extraction of unconventional oil resources, including Canadian oil sands,
together with the exploitation of shale gas (natural gas trapped in shale formations), has
significantly reshaped the global energy landscape over the past two decades. Canadian oil
sands have attracted significant attention because of their rapid growth, their significant share
of Canadian exports and foreign direct investment, and their greenhouse gas (GHG) emis-
sions and other environmental impacts. The Canadian oil sands sector highlights many of the
key issues we examine in economics and, as we will discuss here, the sector remains ripe for
further research.
Oil sands are a subsurface hydrocarbon deposit that contains a type of oil (called bitu-
men) that is mixed with sand, water, and clay. The world’s largest oil sands deposits are in
Canada, but there are also important deposits in Venezuela, the United States, Russia, and
several other countries. Canada’s oil sands are concentrated almost entirely in the province
of Alberta, with the three largest deposits originally estimated to contain up to 1.8 trillion
barrels of oil in place (Swart and Weaver 2012). Oil sands operations produce bitumen—a
black, viscous mixture of hydrocarbons—which is denser and higher in sulfur than most
crude oils produced globally. Oil sands bitumen can either be processed into synthetic
crude oil for use as a substitute for lighter crude oils or refined directly in complex
refineries.
Commercial exploitation of Canadian oil sands began in 1967, but the most rapid growth
has occurred since the turn of the century, when oil sands were part of a wider commodities
boom in the Canadian economy.
1
In 2017, oil sands production averaged 2.9 million barrels
per day, an almost fourfold increase over production levels in 2000.
2
Between 2000 and 2015,
*Department of Economics, Faculty of Social Sciences, 120 University Social Sciences Building, Room 9005,
Ottawa, Ontario, Canada K1N 6N5; Department of Economics, University of Sussex, England BN1 9RH; e-
mail: aheyes@uottawa.ca.
†
School of Business, University of Alberta, Edmonton, Alberta, Canada T6G 2R6; e-mail: aleach@ualberta.ca.
‡
Department of Economics, College of Business, University of Wyoming, 1000 E. University Ave. Laramie,
WY 82071; e-mail: bambuzlr@uwyo.edu.
1
Over the last two decades, the exploitation of Canada’s oil sands deposits has coincided with the dramatic
rise of oil production from shale, particularly in the United States (see Kilian 2016,2017). See Appendix
figure 1 for details on oil sands production trends and projections.
2
Canadian data used in this report are generally presented in cubic meters (m
3
). One barrel of oil is equivalent
to 0.1589 m
3
of oil.
Review of Environmental Economics and Policy, volume 12, issue 2, Summer 2018, pp. 242–263
doi: 10.1093/reep/rey006
Advance Access Published on July 13, 2018
V
CThe Author(s) 2018. Published by Oxford University Press on behalf of the Association of Environmental and Resource
Economists. All rights reserved. For permissions, please email: journals.permissions@oup.com
242
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more than 270 billion Canadian dollars (Can$) were invested in Canadian oil sands, and
direct employment in the sector grew to more than 70,000 employees (Petroleum Human
Resources Council of Canada 2014;Alberta Energy Regulator 2018). The effects on employ-
ment in the broader economy were much larger, with Kneebone (2014) estimating oil sands
as directly or indirectly contributing 400,000 jobs in Canada by 2014.
More recently, the Canadian oil sands industry has been in a period of upheaval. World oil
prices dropped more than 50 percent between June 2014 and June 2016, reaching prices that
failed to cover the variable costs of production for some oil sands production facilities (see,
e.g., MEG Energy 2016).
3
While oil sands production continued to grow during the down-
turn, capital investment and production growth expectations have both fallen significantly
since 2014. For example, Alberta Energy Regulator (2014) forecast bitumen production to
grow from 2013 levels of 2 million barrels per day to 4 million barrels per day by 2023, with
$250 billion in capital investment between 2014 and 2023. In contrast, Alberta Energy
Regulator (2018) forecast production to reach 3.6 million barrels per day by 2023, with
$160 billion in capital investment between 2014 and 2023.
This article analyzes the status of Canadian oil sands and examines the sector’s future
prospects. We start by discussing the key economic drivers of oil sands costs and how they
affect supply decisions. Then we discuss transportation issues and the challenges of get-
ting oil sands products to export markets. We next examine the likely impact of evolving
climate change policy—both within Canada and outside—on operations, as well as other
environmental issues that relate to oil sands operations. Finally, we highlight macroeco-
nomic impacts and considerations, namely the resource curse and Dutch disease. Overall,
we find the future prospects for the Canadian oil sands industry to be highly uncertain.
Key Drivers of Canadian Oil Sands Costs and
Future Supply Decisions
This section identifies the key financial variables that determine costs in the Canadian oil
sands sector, and thus producers’ supply decisions. We develop project-level cost estimates
for the two most common extraction techniques—open pit mining and in situ extraction—
and use them to project future supply decisions in response to potential changes in the key
variables.
4
Following Dixit and Pindyck (1994),Mason (2001) characterizes the decision to
develop a new resource extraction project under uncertainty as an option with a trigger price
(the price at which production of a particular project becomes profitable), and this is how we
frame our analysis. We define our trigger price in terms of the constant real dollar West Texas
3
The significant weakening of the Canadian dollar against the U.S. dollar during this period cushioned the oil
sands sector against further competitiveness losses. See Baumeister and Kilian (2016) for an analysis of the
factors that contributed to the dramatic drop in oil prices.
4
Open-pit mines tend to be larger, longer-lived, and have higher total initial capital cost per unit of pro-
duction capacity. In situ facilities are smaller in production capacity and have shorter project durations.
They rely on paired wells, with the first drilled to inject steam to heat the bitumen in the deposit to render it
less viscous and the second drilled to produce the heated bitumen. In situ facilities generally rely on natural
gas more than mines, while truck-and-shovel (i.e., open pit) mines rely more heavily on diesel fuel.
Evaluating the two project types separately allows us to be sensitive to important differences between
them in terms of typical time scales, environmental attributes, and cost structures.
The Economics of Canadian Oil Sands 243
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Intermediate (WTI) oil price at which a prototypical new oil sands project would be expected
to earn a 10 percent rate of return on capital.
Capital and Operating Costs
Oil sands projects have significant construction and operating costs. The only open pit
mine currently under construction, Suncor’s 180,000 barrels per day Fort Hills facility, is
expected to cost a total of $16.2 billion (Suncor 2018). In situ projects tend to be smaller
and less costly per unit of production capacity; for example, the Kirby North project
(40,000 barrels per day) is expected to cost $1.35 billion (Canadian Natural Resources
2016). We use these capital costs as benchmarks for our analysis. Operating and mainte-
nance costs in the sector vary significantly across facility and type of extraction (Canadian
Energy Research Institute 2015;Ollenberger, Murphy and Li 2016). Following central
estimates from these sources, we assume operation, maintenance, and production-
sustaining capital investment costs of $22 and $36 per barrel produced for in situ and
mining extraction, respectively.
Product Discounts
As noted earlier, bitumen is either converted to synthetic crude oil or diluted with natural gas
liquids and shipped as diluted bitumen for processing in complex refineries. We will focus
our analysis on diluted bitumen, as there are no projects planned that include integrated
upgraders (basically a purpose-built refinery) to convert bitumen into synthetic crude. Like
other heavier and higher-sulfur crude oil blends, diluted bitumen from oil sands is generally
discounted relative to global benchmark oil grades. During 2017, the Canadian benchmark
Western Canada Select diluted bitumen blend traded at an average of $12.77 per barrel
below the WTI price, the North American benchmark for light crude; we use this value
(adjusted for inflation) in our analysis and allow it to vary for sensitivity analysis.
5
The price
discount is due to differences in quality and geographic characteristics: oil sands diluted
bitumen is denser and thus more expensive to transport, more expensive to refine, and
yields a lower-value slate of products than a light, sweet (low-sulfur) crude in the same
location (Nimana, Canter, and Kumar 2015). Lower values for heavy crude are not exclu-
sive to oil sands bitumen. For example, Mexican Maya crude traded on the U.S. Gulf Coast
at a $6.98 per barrel discount relative to Louisiana Light Sweet Crude in 2017 (Bloomberg
data, author’s calculations). Transportation costs are also reflected in the price discounts
for oil sands diluted bitumen, with the marginal market being the U.S. Gulf Coast.
6
The
North American pipeline network has been affected by significant congestion, which has
contributed to larger than expected discounts for Canadian diluted bitumen between 2010
and 2014 (Borenstein and Kellogg 2014;Oliver, Mason, and Finnoff 2014;Kilian 2016)and
again in late 2017 and early 2018.
5
We regard this as a conservative approach. The 5- and 10-year average discounts for bitumen relative to WTI
have been $26.53 and $26.99 per barrel, respectively (Bloomberg data, authors’ calculations). The differ-
ential has also been higher since November 2017. Thus we also include a high-differential sensitivity case.
6
Thus Gulf Coast access costs $8.63 per barrel via the Enbridge system (National Energy Board 2018b) and
$10.50 per barrel via the TransCanada system (National Energy Board 2018c).
244 A. Heyes et al.
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Royalties and Taxes
Among the major costs for oil sands operators are royalties paid to the government (which
owns oil sands resources) and corporate income taxes. The oil sands royalty regime is a two-
stage system. Initially the developer pays the government a price-dependent share of gross
revenues until the project has produced a cumulative return on capital invested that is equal
to the long-term government bond (this is referred to as payout), after which the project is
subject to higher royalties based on a share of profits (Plourde 2009). At both stages, the share
of production or profits payable as royalties depends on the WTI price per barrel in Canadian
dollars. With the exception of financing costs, most project costs are used to calculate both the
payout condition and the net revenue base on which royalties are calculated.
7
In terms of corporate taxes, oil sands producers pay federal and provincial corporate
income taxes at a current combined rate of 27 percent; they also benefit from special tax
provisions available to all Canadian oil and gas production (KPMG 2015).
An unresolved issue is whether oil sands production is actually subsidized. Some research-
ers have evaluated the level of government support by examining tax expenditures provided
to the oil industry (including oil sands), which they find to be Can$2–3 billion per year
(Sawyer and Stiebert 2010). Others have argued that the marginal effective tax rate on capital
is higher in Canadian oil and gas than other industries (McKenzie and Mintz 2011), suggest-
ing that the combined effect of the current tax and royalty regimes has been to shift economic
activity away from oil sands.
Environmental Policies
Environmental policies also affect the costs faced by Canadian oil sands producers, and hence
their supply decisions. First, prices on carbon are applied through a hybrid policy that has
elements of both a carbon tax and a cap-and-trade regime (Leach 2012). Regulations in place
through 2017 provided an output-based allocation of emissions credits based on each
facility’s historical performance. In 2018, the output-based allocations changed to a
benchmark-based system under which firms receive credits based on the performance of
the 25th percentile producer, with separate allocations for in situ and mined bitumen pro-
duction.
8
Credits are bankable and tradable. If firms have insufficient credits to cover their
emissions, then they may purchase credits from another firm, make a payment to the gov-
ernment in lieu of emissions reductions, or purchase regulated emissions offsets within
Alberta. The possibility of compliance through a payment to the government sets the carbon
price in Alberta. From 2007 through 2015, this price was $Can15 per tonne. The price was
increased to Can$20 per tonne in 2016 and to Can$30 per tonne in 2017. Importantly, carbon
charges and emissions abatement costs may be deducted from revenues in calculating both
7
The initial gross revenue royalty rate is 1 percent when prices are below Can$55 per barrel and increases
linearly to a maximum of 9 percent when oil prices reach Can$120. After the project is deemed to have
reached payout, the royalty payable is the greater of the gross revenue royalty just described or a share of
profits that increases from 25 percent (when the WTI price is less than Can$55 per barrel) to 40 percent (for
oil prices at or above Can$120 per barrel).
8
One of the authors of this article, Andrew Leach, chaired the Government of Alberta’s Climate Leadership
Panel, whose recommendations were largely adopted by the government (Leach et al. 2016). The updated
regime in Government of Alberta (2017) forms the basis of our analysis.
The Economics of Canadian Oil Sands 245
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the royalty and tax base, implying that such costs are partly shared with the federal and
provincial government.
Oil sands facilities are also responsible for the reclamation of their sites after extraction has
been completed. Based on a study by the Canadian Energy Research Institute (2015), which
assumes a reclamation cost that is equivalent to 2 percent of total capital expenditures, we
assume that the future cost of reclamation is Can$0.25 per barrel for all production.
Results: Prospects for Future Oil Sands Supply
The future viability of oil sands production depends primarily on the expected evolution of
global oil prices and low-cost access to markets. Using a discounted cash flow model of two
prototypical oil sands facilities (one in situ and one mine) that produce diluted bitumen,
and based on the assumptions just presented, we estimate the costs of new oil sands pro-
duction. We then use these costs to estimate the critical (or trigger) oil price at which new
production would be viable.
9
The trigger prices that we derive are substantially higher than
realized prices for much of 2015–2017, with the bitumen mine requiring revenue levels that
would be expected with WTI prices of $84.62 per barrel in order to earn a nominal rate of
return of 10 percent on invested capital, while the trigger price for the in situ plant is $58.06
per barrel WTI. These values translate to required revenues at the plant gate (i.e., before
transportation) of $61.62 and $35.85 per barrel bitumen, respectively.
10
These estimates are
consistent with estimates from Alberta Energy Regulator (2018), which reported a required
WTI range of $75–85 per barrel for mines and $45–55 per barrel for in situ plants. These high
trigger prices clearly indicate why new development of Canada’s oil sands have slowed
significantly since 2015.
Despite the drop in oil prices in late 2014, work on Canadian oil sands projects currently
under construction has continued and those that began before the oil price crash are
expected to enter production at close to their original schedules. Given the substantial
sunk costs, expected oil prices would have to fall significantly from current levels for those
projects currently under construction to be abandoned or operating projects to shut down.
More specifically, using an analysis similar to the one used to estimate the costs of new oil
sands production, we find that while a new in situ project would not be developed unless
average oil prices were expected to remain above $58 per barrel, price expectations would
have to drop below $45 per barrel to trigger the suspension of a project for which two-thirds
of the construction costs had already been incurred. Other than projects currently under
construction, the lowest-cost future development would be expansion of some existing facil-
ities. For example, Ollenberger, Murphy and Li (2016) find that significant expansions of both
existing in situ and oil sands projects are viable at average WTI prices below $50 per barrel.
Our model predicts that a prototypical expansion of an in situ project would be viable at
approximately $50 per barrel, depending on the assumed reduction in total capital costs due
to already-sunk costs.
9
Appendix table 1 presents a list of the assumptions underlying these estimates and Appendix table 2 presents
the detailed cost estimates.
10
This includes the costs of diluting and shipping a barrel of bitumen and the discount at which diluted
bitumen trades to lighter oil blends.
246 A. Heyes et al.
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Getting Product to Market: Transport Challenges
The analysis just presented does not consider the evolving challenges to the large-scale trans-
portation of oil sands product to markets, particularly for export. We discuss these challenges
here.
Alberta Energy Regulator (2018) reports that of the 2.7 million barrels per day of total oil
sands production in Alberta in 2017, 375,000 barrels per day were used within the province,
while 650,000 barrels per day of upgraded oil sands product and 1.5 million barrels per day of
nonupgraded bitumen were removed from Alberta.
11
The latter includes product shipped to
U.S. markets and to Canadian markets outside the province. Most of these volumes move by
pipeline, although some exports occur by rail.
12
Export capacity is extremely tight. In December 2017, the largest export pipeline systems,
Keystone (27 percent), Enbridge Mainline (5–21 percent), and Trans-Mountain (23percent),
were all oversubscribed (by the percentages shown in parentheses) relative to their maximum
capacity (National Energy Board 2018). Although pipeline expansions are under way in the
Enbridge system, even a conservative production growth case would lead to export volumes
exceeding effective pipeline capacity unless additional new pipeline projects are undertaken
(National Energy Board 2016b).
The construction of new oil sands pipelines has been a key issue in North America. Pipeline
safety concerns were exacerbated by two spills of oil sands diluted bitumen (in Kalamazoo,
Michigan, and Mayflower, Arkansas, in 2010 and 2013, respectively). These safety concerns,
coupled with concerns about GHG emissions, resulted in increased opposition to pipelines,
culminating in the United States with President Obama’s rejection of the Keystone XL pipe-
line (in late 2015) and in Canada with major political battles and protests over pipeline
proposals. Although President Trump reversed the Obama administration decision on
Keystone XL in 2017, the pipeline continues to face regulatory challenges and stiff local
opposition.
Several other pipeline projects have been proposed to increase capacity to ship oil derived
from the Alberta oil sands. The TransMountain Expansion (590,000 barrels per day) to the
Canadian West Coast and the Line 3 refurbishment and Line 67 expansion of the Enbridge
system to the U.S. Midwest (370,000 barrels per day) have received Canadian regulatory
approval.
13
The proposed Northern Gateway Pipeline (525,000 barrels per day) to the
Canadian West Coast had its federal regulatory approval overturned by the courts and was
subsequently denied by the Canadian government in 2016 (Gitxaala Nation v. Canada
[2016],Government of Canada [2016]). The Energy East (1,100,000 barrels per day) pipeline,
the only proposed oil pipeline to the Canadian East Coast, was cancelled and withdrawn from
the regulatory process by TransCanada in 2017.
Shipping by rail presents the only plausible alternative to transport by pipeline. In general,
shipping oil by rail costs substantially more per barrel-mile than shipping by pipeline.
However, there are factors related to specific characteristics of the transportation of oil sands
11
We use “removals” to indicate movements out of the province, including volumes shipped to other
Canadian provinces. We use exports to denote shipments to destinations outside of Canada.
12
In December of 2017, less than 5% of total crude oil exports were shipped by rail (National Energy Board,
2018).
13
Note that construction is under way on Line 3.
The Economics of Canadian Oil Sands 247
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bitumen that narrow the gap between pipeline and rail costs. The most important of these is
that shipping bitumen by rail requires less dilution, thus reducing both the total volume of
product shipped and the costs attributable to purchase of the diluting agent. Estimates of the
per-barrel cost advantage of pipelines over rail vary from $3–4 (U.S. Department of State
2014)to$9(TransCanada Pipelines 2016). Without new pipeline capacity, it is widely
expected that oil sands production will be lower than would otherwise be the case, because
net revenues will be lower if incremental production must rely on shipments by rail. For
example, National Energy Board (2016b) estimates that a scenario with no new pipelines
constructed would lead to an 8 percent reduction in total Canadian oil output and a 13
percent (400,000 barrels per day) reduction in peak oil sands output. These findings are
driven by an estimated reduction of $9.20 in the price of diluted bitumen at the Hardisty,
Alberta, hub. The U.S. Department of State (2014) found similar results concerning oil price
levels in their analysis of the Keystone XL pipeline. Given these results, we recalculated our
model results for a scenario with higher discounts for Canadian diluted bitumen and found
that these discounts have significant impacts. More specifically, we found that under the U.S.
Energy Information Administration’s Reference Case for oil prices, a $9 per barrel additional
discount on Canadian crude would reduce the rates of return on in situ projects from 17
percent to 13 percent and on mining projects from 8 percent to 5.5 percent.
Whether reached by pipeline or rail, the United States represents the most important
market for any additional exports of Canadian oil sands production.
14
In 2017, Canada
exported 2.7 million barrels per day of heavy crudes (including diluted bitumen) to the
United States via pipeline, which represented 56 percent of total U.S. imports of this grade
of crude oil (Energy Information Administration 2017a and b). Thus there is significant
potential to increase shipments of nonupgraded bitumen to the United States. Although
there are other markets for heavier crudes such as those produced from oil sands, the U.S.
market remains the closest major market and is therefore likely to be served first.
Canadian Oil Sands and Climate Change Policies
Climate change policies in Canada, the United States, and globally are evolving rapidly. As a
producer of a carbon-based product, Canada’s oil sands sector—and its future prospects—
will clearly be affected by these policies.
Climate Impact
Operations in the Canadian oil sands affect GHG emissions in two ways. One is the emissions
generated in the process of extraction, processing, and transport. The other is the release of
carbon when the product is finally used.
Oil sands operations in Alberta are a large and growing source of GHG emissions, with
emissions increasing from 15.3 million metric tons of carbon dioxide equivalent
(MtCO
2
e) in 1990 to 69.3 MtCO
2
eby2016(Environment Canada 2018a). Oil sands
accounted for 10.2 percent of total GHG emissions in Canada in 2016 and are projected
14
Other potential markets include India and China, which could be served from the west or east coasts.
248 A. Heyes et al.
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to increase to 15.9 percent (115 MtCO
2
e) of total Canadian emissions by 2030 (Environment
Canada 2018b).
Moreover, oil refined from oil sands has higher life cycle emissions than comparable
products produced from most other crude sources (Brandt 2011;Bergerson et al. 2012;
Cai et al. 2015;Gordon et al. 2015). More specifically, the California Air Resources Board
(2015) estimates the carbon intensity values for refined products derived from Western
Canada Select (the heavy oil blend price we have used to proxy for diluted bitumen values)
to be 18.43 grams per megajoule (g/MJ), which is much greater than the 12.03 g/MJ esti-
mated for WTI crude and the 8.71g/MJ estimated for North Dakota Bakken crude. The
estimated carbon intensity of products sourced via oil sands production also varies signif-
icantly across facilities, ranging from 12.05 g/MJ for Kearl Lake bitumen to 37.29 g/MJ for
Long Lake synthetic. This suggests that depending on how it is differentiated by source,
carbon pricing applied to oil users could disproportionately affect the attractiveness of oil
sands in general and the output of facilities generating more carbon-intensive output in
particular.
Significant concerns have been raised about the impact of oil sands emissions on global
climate change. Sometimes this has involved emotional language. For example, Hansen
(2012) characterized the exploitation of oil sands resources as “game over for the climate,”
and high-profile environmentalist Bill McKibben (2011) has called oil sands “the biggest
carbon bomb on the planet.” The findings in the peer-reviewed literature have been less
definitive on the potential role of oil sands extraction in exacerbating global climate change.
Swart and Weaver (2012) find that if extracted and combusted, the entire oil sands resource
would increase global average temperatures by 0.36C and that combustion of current oil
sands reserves
15
would increase global average temperatures by 0.03C.
Implications of Climate Policy for the Oil Sands Sector
Existing research is also mixed concerning the future of oil sands development if the world
takes serious action on climate change. For example, McGlade and Ekins (2015) find that
under cost-effective policies to reduce GHG emissions to levels consistent with a 2C increase
in global mean temperature, there would be no new oil sands development and existing
production would be rapidly curtailed, with cumulative production falling sharply from
the National Energy Board (2016) forecasts (i.e., from 38 billion barrels by 2040 to 7.5 billion
barrels by 2050). Under similar global emissions constraints, McGlade and Ekins (2014) find
that future oil sand production rates depend on whether carbon capture and storage (CCS)
technology is readily available.
16
With CCS, production rates would increase to 4.1 million
barrels per day in 2035, while remaining roughly constant at current levels if CCS technology
is not viable. Chan et al. (2012) find that bitumen production increases fourfold in the
absence of global action on climate policies but that “climate policy significantly dampens
the prospects for Canadian oil sands development because global demand and the producer
15
This is estimated to be approximately 100 years of production at 5 million barrels per day, which is just
below the peak rate forecast in National Energy Board (2016b).
16
CCS is the process of capturing waste carbon dioxide from large point sources, transporting it to a storage
site, and depositing it where it will not enter the atmosphere, normally in an underground geological
formation.
The Economics of Canadian Oil Sands 249
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prices of oil are depressed, and the Canadian CO
2
policy adds to the cost oil sands
production.” Leach and Boskovic (2014) find that oil sands production is likely to continue
under a global carbon price set at the social cost of carbon if and only if a significant share of
the carbon cost is borne by oil consumers.
17
While it is likely that global action on climate change would preclude significant expansion
of oil sands production in the absence of significant technological advances, it is more dif-
ficult to assess the impact of climate change policies on the viability of existing projects in
Canada. Higher domestic carbon prices have impacts that are analogous to lower oil prices or
higher transportation costs, although with slightly different royalty implications. Carbon
costs are deductible from both the tax and royalty base, so approximately 50 percent of
any increased carbon cost is effectively passed through to provincial and federal governments
through reduced tax and royalty payments (Boskovic and Leach 2017).
The production-weighted average emissions per barrel produced from oil sands (using
2014 Alberta government data) was 0.055 metric tons per barrel. This means that each dollar
in average carbon cost would increase the average cost of existing oil sands production by
$0.055 per barrel, suggesting that it is likely that existing operations could withstand signif-
icant increases in domestic carbon prices without inducing a significant shutdown of
operations.
Overall Impact of Climate Policies
Overall, we find that the impact of evolving climate policies on oil sands development is
likely to be felt most acutely through the impacts of these policies on global oil prices. Since
roughly 80 percent of the total life cycle emissions from the production and combustion of
a barrel of bitumen occurs in refining, transportation, and final combustion, the impact of
downstream emissions pricing will likely be greater than the impact of policies affecting
only production emissions. This suggests that the greatest climate policy risks for oil sands
are from the oil market impacts of global action on climate change, not domestic climate
change policies.
Other Environmental Issues Facing Canadian Oil Sands
In addition to climate impact, there are important local environmental and ecological
impacts related to oil sands production, including the accumulation of mine tailings, land
reclamation, and negative impacts on populations of caribou and other fauna.
18
In this
section we discuss these issues in more detail as well as potential government actions aimed
at mitigating them.
17
The social cost of carbon is an estimate of the monetized damages caused by a 1 tonne increase in carbon
emitted in a year.
18
It is important to note that oil sands operations are concentrated in the northeastern corner of Alberta, a
remote area where few people live or visit. Thus justification for governmental regulation of environmental
and ecological impacts must often be based on nonuse values (i.e., the value that people assign to goods,
including public goods, even though they have never and will never directly use them).
250 A. Heyes et al.
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Accumulation of Mine Tailings
After oil sands have been mined, the ore is mixed with hot water and chemical solvents to
separate bitumen from sand, clay, and other impurities. The resulting slurry goes through an
extraction process to remove the bitumen. The remaining components are called tailings.
Tailings are transported and stored in large “ponds,” engineered systems that involve dams
and dikes. In 2015, tailings ponds in Alberta contained 1.18 trillion litres of fluid tailings and
covered more than 220 square kilometers (McNeill and Lothian 2017). The appropriate
management of these tailings, which contain many compounds that are potentially harmful
to the environment, is a major issue for the oil sands sector.
Environmental impacts
Tailings have a number of potential environmental impacts. The Council of Canadian
Academies (2015)
19
identified problems that can arise from toxic seepage into groundwater
and rivers and the potential ecological implications of catastrophic dike failures. However,
empirical evidence concerning these impacts is rather limited. In one exception, Kelly et al.
(2010) provide evidence linking elevated levels of 13 important pollutants in the Athabasca
River system in northeastern Alberta to oil sands operations, including tailings. In the longer
term, the extent to which successful reclamation of land contaminated by tailings is likely to
be feasible, and at what cost, is also disputed (Pembina Institute 2008).
There is also comparatively little evidence concerning the contribution of tailings facilitiesto
air pollution and the likely associated impacts. However, Galarneau et al. (2014) find that
tailings ponds are a much more significant source of polycyclic aromatic hydrocarbons
(PAHs), which can negatively impact human health, than previously believed. Moreover, the
environmental implications of such discharges for regional ecosystems are not well understood.
Government policies
Tailings are a classic stock pollution problem. Research and policy work have examined options
for both stemming the rate of deposition of new tailings and reducing the stock as part of efforts to
reclaim the affected landscape.
20
In an effort to slow the generation of tailings, Alberta Energy
Regulator regulates oil sands producers to encourage reduced tailings deposition.
Although the underlying physical science regarding the short- and longer-term impacts of
tailings on the environment of Alberta remains underdeveloped, attempts to actually mon-
etize or otherwise weigh those impacts in a way that could be included in a benefit–cost
analysis are essentially nonexistent. This points to an urgent need to support further research
in this area to provide credible estimates of impacts in a form that can support policy eval-
uation and appraisal.
19
The Council of Canadian Academies is a highly respected not-for-profit organization that conducts expert
evidence reviews in support of public policy development in Canada. It includes three member academies:
the Royal Society of Canada, the Canadian Academy of Engineering, and the Canadian Academy of Health
Sciences.
20
In terms of flow, the production of 1 barrel of synthetic crude oil requires approximately 2.5 barrels of water
and 2 tonnes of oil sands ore, yielding around 3.3 barrels of raw tailings. While much of the water used is
recycled from existing tailings ponds, the long-run equilibrium sees approximately 2 barrels of mature fine
tailings produced for every barrel of oil (Hrudey et al. 2010).
The Economics of Canadian Oil Sands 251
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Reclamation of Tailings and Mine Sites
Oil sands companies are responsible for restoration of their sites after use. This includes
tailings areas and land used for other purposes. There has been some progress in the reme-
diation of existing tailings ponds. Suncor Energy became the first oil sands company to
complete surface reclamation of a tailings pond. Reclaiming the 220 hectare site north
of Fort McMurray involved moving more than 65,000 truckloads of soil and the planting of
around 630,000 trees and shrubs (Marketwire 2010). However, the success of that project—
that is, the extent to which the area returns to being a self-sustaining ecosystem—can only be
assessed with the passage of time. Other reclamation technologies are in the test phase and thus
not yet commercially viable.
There has also been significant work on the reclamation of oil sands mine sites, although
the actual rate of reclamation is low. The total oil sands extraction area in Alberta is roughly
89,000 hectares, with only about 8,000 hectares of that at some stage of reclamation. Only
237.6 hectares of land (less than 0.5 percent of the total disturbed landscape) have been
certified as reclaimed and returned to government jurisdiction (Alberta Energy Regulator
2017), indicating a substantial challenge for land restoration in the future.
There is significant research on the technical challenges of restoring oil sands landscapes to
their original productive capacity after oil extraction has been completed (see, e.g., Hrudey
et al. 2010). In addition to the challenges of reclaiming lands currently used as tailings ponds,
reclamation of fenland, muskeg swamp, and boreal forest landscapes have all proven chal-
lenging. From an economic standpoint, we found nothing on the relative value of land
restored to a productive but not fully restored landscape.
In order to provide financial assurance of reclamation, companies must provide security
deposits to the government of Alberta to ensure the work is done. More specifically, com-
panies are allowed to use the value of their extraction assets, which is a function of the price of
oil, as collateral for their unfunded future reclamation liabilities. As of September 2017, the
government of Alberta held just under $1 billion in financial security (Alberta Energy
Regulator 2017), compared with the most recent public estimate of liability of $20.8 billion
(Office of the Auditor General of Alberta 2015). Going forward, as with the decommissioning
costs related to nuclear power projects, the future costs of restoring the oil sands areas of
Alberta (after production ends), and the extent to which partial restoration will be socially
acceptable, need to be given careful consideration when evaluating oil sands projects.
Impacts on Caribou and Other Fauna
The negative impact of oil sands on faunal biodiversity has drawn significant media and
public attention. The plight of the woodland caribou, in particular, has received a great deal of
attention (Hervieux et al. 2013).
21
Alberta is home to 15 herds of woodland caribou, and the caribou is listed as a threatened
species under the Canadian Species at Risk Act. This regulation requires both the
21
Two studies have used stated preference methods to estimate the value of the existence of caribou
(Adamowicz et al. 1998;Harper 2012). The estimated willingness to pay for an increase in the number
of herds is approximately Can$184 (to increase from two to three herds) or Can$268 (to increase from two
to seven herds).
252 A. Heyes et al.
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identification of key threats and the development of an intervention plan (Environment
Canada 2012). Oil sands operations have been identified as factors in the decline of wood-
land caribou, but the magnitude of this influence is disputed. Hrudey et al. (2010) highlight
the role of habitat fragmentation. Roads—many developed or used primarily for oil sands
business—act as semipermeable barriers to caribou movement and pipeline rights-of-way
allow predator movement into caribou territory (Dyer et al. 2002;Jordaan, Keith, and
Stelfox 2009). Boutin et al. (2012) suggest a multistage process in which human disturbance
in the oil sands region has led to habitat fragmentation and to increases in the deer pop-
ulation, which in turn has led to an increase in wolf populations. Latham et al. (2011a,
2011b) find that wolves’ use of road and pipeline rights-of-way for movement has changed
the predator–prey balance in a way that puts caribou at a disadvantage.
In June 2016, the government of Alberta introduced its Caribou Action Plan, which
includes several proposed actions to ensure caribou recovery (Government of Alberta
2016). The current policy includes the expansion of protected areas as well as predator con-
trol, specifically through the culling of wolves. Schneider, Hauer, and Adamowicz (2010)
recommend a three-pronged approach to management: habitat protection, restoration of
disturbed areas, and predator control. Boutin et al. (2012) argue that although unpopular, the
wolf culls are necessary because the other two approaches will not eliminate the causes of
population decline in time to preserve viable herds.
Policies aimed at protecting caribou also affect the economics of oil sands. Boskovic and
Nostbakken (2016a) find that, on average, regulations designed to protect caribou decrease
the value of oil sands lands by 24 percent on average, or Can$192 per hectare, leading to a
Can$1.15 billion reduction in government leases and royalties. Boskovic and Nostbakken
(2016b) examine the impact on lands likely to see future regulation, finding that the value of
leases in currently unregulated areas decreases by an average of 16 percent relative to geo-
logically similar leases further from protected caribou areas. For areas within 5 kilometers of a
currently regulated area, the value of the lease decreases by 22 percent.
In summary, oil sand operations may have important impacts on both the health of caribou
populations and other fauna in Alberta. However, we found little or no economic analysis
that allowed for these impacts to be included in a benefit–cost framework.
Positive and Negative Macroeconomic Impacts
Next we examine the impacts of Alberta’s oil sands sector on the wider economy. The
channels for positive macroeconomic impacts are clear: employment, government reve-
nues, and real wages in Alberta all increased well above national averages from the early
2000s through mid-2014, and wages, productivity, and employment in Alberta were still
well above national averages in 2017. However, there is substantial literature that suggests
that large resource endowments may have negative macroeconomic impacts on a jurisdic-
tion and actually lower its well-being; some of these negative impacts have been studied in
Alberta. Two concepts that have often been discussed in this regard are the resource curse
and Dutch disease.
The Economics of Canadian Oil Sands 253
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The Resource Curse
Potentially the most pervasive of these macroeconomic impacts, the “resource curse”
describes a deleterious effect of increased resource wealth on governance, educational attain-
ment, and other socioeconomic impacts. Sachs and Warner (1995,2001) and others have
identified several channels through which the resource curse can occur. For example, the lure
of significant wealth associated with the resource bounty induces rent-seeking behavior, often
on the part of political actors; this effect is likely to be particularly pronounced when there are
weak legal institutions (Brunnschweiler and Bulte 2008). Some have argued that such an
effect has occurred in Alberta, pointing in particular to successive governments’ decisions to
spend resource revenue for current consumption rather than saving it to a sovereign fund, as
has been done in Norway (Parlee 2015).
22
Dutch Disease
Another possible negative macroeconomic effect of a large resource endowment is “Dutch
disease,” whereby the presence of significant potential rents pulls resources away from other
sectors. In particularly dramatic cases, the other sectors wither (Economist 1977). Sachs and
Warner (1995) find that Dutch disease can be a source of anemic growth, “if there is some-
thing special about the sources of growth in manufacturing.” Here the market failure would
be sector-level returns to scale that are not accounted for in individual decisions. Two
questions remain unanswered in the debate over the potential rise of Dutch disease in
Canada: first, did an additional decline in manufacturing occur as a result of the rise in
resources and, second, does this substitution of economic activity away from manufacturing
matter?
There is fairly compelling evidence indicating an accelerated decline in traditional
manufacturing in Canada as the resource boom pulled resources into oil sands, causing an
increase in prices of key related inputs and wages. There is also evidence that the appreciation
of the Canadian dollar, in part due to the commodity boom, accelerated this transition. For
example, Beine, Bos, and Coulombe (2012) estimate that 42 percent of the substantial ap-
preciation in the Canadian dollar between 2002 and 2008 was due to the increased value of
resource exports, especially, but not uniquely, oil sands. They also find that 31 percent (ap-
proximately 100,000 jobs) of all manufacturing job losses during the same period can be
attributed to the rise in the exchange rate driven by Canadian economic activity. Krzepkowski
and Mintz (2013) argue that the declines observed in the manufacturing sector are the con-
tinuing result of factors other than the resource boom and suggest that with or without the oil
sands industry, the high-wage manufacturing jobs that had been the mainstay of central
Canada’s economy for decades were unlikely to return.
Boadway, Coulombe, and Tremblay (2013) take a different approach, examining whether
Canada’s institutions of fiscal redistribution have the capacity to deal with resource booms.
They recommend changes to the system through which resource rents are collected and
22
There is some evidence that educational attainment and the accumulation of human capital are adversely
affected by resource booms (Parlee 2015). However, Emery, Ferrer, and Green (2012) found that although
the oil boom in Alberta between 1973 and 1981 changed the timing of schooling, it did not affect total
human capital accumulation over the long term.
254 A. Heyes et al.
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redistributed within the country and through increased infrastructure spending in other
regions to offset the economic pull of resource-rich regions; they also encourage more saving
of resource rents in sovereign wealth funds.
Thus the literature consistently finds significant macroeconomic impacts of the oil sands
boom, and more generally finds an increase in the overall standard of living, which is pro-
vided by the increase in natural resource wealth and activity due to the oil sands boom, at least
since the early 2000s. However, the literature also finds significant transition and volatility
costs, institutional failure, and a potential long-term impact of lost educational attainment
due to the resource boom. It is important to further estimate the value of these impacts, but
some values will only become clear in the longer term.
Summary and Conclusions
This article has discussed key issues in the economics of Canadian oil sands. We find that
production from Canadian oil sands requires that the WTI oil price exceed $58 per barrel.
While the oil price was markedly lower for a period of time, it has recently risen above $60,
suggesting the potential for substantial increases in oil sands production. We also find sig-
nificant uncertainty due to potential transportation constraints. If currently proposed pipe-
line projects do not proceed, for example, because of legal hurdles and local regulatory
processes, the required price to trigger investment in new oil sands projects is approximately
$9 per barrel higher than would otherwise be the case. Regarding the nonmarket costs asso-
ciated with oil sands, there has been insufficient economic analysis concerning air quality,
water quality, wildlife, and other environmental impacts. This gap in the literature presents a
substantial challenge to conducting a thorough benefit–cost analysis of Canadian oil sands.
Due to space limitations, we have not discussed water quality and quantity policies
(Schindler and Donahue 2006;Allen 2008), issues concerning airborne pollution deposition
on land and water (Kelly et al. 2010), and the contribution of oil sands to particulate matter
and acid rain–causing pollution (Hrudey et al. 2010). We have also omitted discussion of the
complex relationship between Canada’s First Nations and oil sands development. Many First
Nations and Metis communities in the oil sands area have important commercial relation-
ships with oil sands companies, and many First Nations communities have been supportive of
proposed pipeline projects. However, there are also multiple legal actions by First Nations
communities against oil sands operations, against the provincial governments for violations
of historic treaty rights, and against pipeline projects currently under development.
If global oil prices continue to recover, oil sands production may be poised to play an
increasing role in global markets. However, any expansion of oil sands is likely to lead to a host
of external effects, including climate impacts, adverse impacts on local flora and fauna, and
externalities associated with transportation.
23
On the other hand, increased production will
add to the consumer surplus in downstream petroleum markets, and the associated expan-
sion is likely to generate benefits to local economies. A full and careful comparison of these
23
If pipeline capacity does not expand to keep pace with production, the increased production will most
likely be shipped via rail; in turn, this increase in rail traffic is likely to yield external costs related to safety
(Mason 2018) and local air pollution (Clay et al. 2017).
The Economics of Canadian Oil Sands 255
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costs and benefits would be both timely and important. Our hope is that the discussions in
this article will encourage such an analysis.
Appendix
Appendix Figure 1 Mined and in situ bitumen production from 1967 through 2017 and projections from
2018 through 2027.
Source:Alberta Energy Regulator (2018).
256 A. Heyes et al.
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Appendix Table 1 Key model parameters, project cost, and fiscal policy assumptions
Project parameters In situ Mine Time trends In situ Mine
Capacity (barrels per day) 40000 180000 Inflation 2%
Build time (yrs) 3 4 Long term bond rate (for royalty
calculation)
2%
Total years of production 30 50 Fuel use (diesel, natural gas)
improvement per barrel
1%
Cumulative production
(million barrels)
385 3180 Emissions intensity improvement
(ex fuel)
1%
Costs ($CAD 2018) Tax pool allocations for capital
expenditure
Construction Costs
(millions)
1350 16200 Capital Cost Allowance (Class 41,
25% of declining balance
deductible each year)
85% 95%
Maintenance Costs
($ per barrel)
53
Operating Costs
($ per barrel)
10 16 Canadian Oil and Gas Development
Expense (30% of declining bal-
ance deductible each year)
15% 5%
Recurring Capital Costs
($ per barrel)
96
Deemed expenses for future
reclamation ($ per barrel)
0.25
Ta x e s
GHG Emissions (Carbon
Dioxide Equivalent)
Combined Corporate Tax Rate 27%
Production emissions
intensity (tonnes/barrel)
0.058 0.038
Life cycle emissions
(grams/bbl)
575 535
Royalties Gross Net
Light oil life cycle emissions
(grams/bbl)
500 Minimum Royalty Rate 1% 25%
Maximum Royalty Rate 9% 40%
Greenhouse Gas Policies Lower limit, formula - C$/bbl 55
Carbon price ($/tonne real) 30 Upper limit, formula - C$/bbl 120
Output-based allocation
rate (where applicable,
t/bbl)
0.055 0.035
Carbon price escalation
(annual increase in real
price)
2%
Decrease in annual output-
based allocation
2%
The Economics of Canadian Oil Sands 257
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Appendix Table 2 Estimates of oil sands supply costs
Oil sands
supply
costs and
financial
metrics
Projects under
current prices
and policies
Projects
under
EIA (2018)
Reference
Case
Prices,
Current
Policies
Projects
under EIA
(2018) High
Oil Price
Case,
Current
Policies
Projects
under EIA
(2018)
Low Oil
Price Case,
Current
Policies
Projects
under EIA (2018)
Reference Case,
Current Policies,
High Differential
In-situ Bitumen
Mine
In-situ Bitumen
Mine
In-situ Bitumen
Mine
In-situ Bitumen
Mine
In-situ Bitumen
Mine
Project Financial Indicators
Internal Rate of Return
(%)
8.79% N/A 16.93% 7.96% 33.48% 18.78% 5.08% N/A 12.71% 5.56%
Supply Cost (WTI
equivalent $/bbl)
58.06 84.62 67.70 109.13 68.47 109.54 52.94 84.37 77.59 119.40
Supply Cost (plant gate
bitumen $/bbl)
35.85 61.61 41.24 81.43 41.99 81.84 32.03 62.51 41.68 82.24
Revenues and Costs ($CAD 2018 per bbl bitumen)
Total Revenue 41.00 40.95 74.02 83.66 190.90 219.54 25.92 31.56 60.88 70.52
Capital and Debt Costs 12.99 10.24 12.76 11.34 12.76 11.34 12.76 11.34 12.76 11.34
Operating Costs 15.34 32.96 16.69 35.60 17.94 42.51 17.41 33.58 16.69 35.60
GHG Compliance Costs 0.20 0.41 0.20 0.41 0.20 0.41 0.20 0.41 – –
Royalties 4.84 3.08 17.83 15.33 64.31 66.61 0.97 2.06 0.20 0.41
Taxes 2.56 7.66 6.09 26.31 26.99 – – 12.82 10.53
Free Cash Flow 5.06 5.74 18.89 14.88 69.37 71.69 5.41 15.83 5.47 3.96
(continued)
258 A. Heyes et al.
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Appendix Table 2 Estimates of oil sands supply costs (continued)
Oil sands
supply
costs and
financial
metrics
Projects under
current prices
and policies
Projects
under
EIA (2018)
Reference
Case
Prices,
Current
Policies
Projects
under EIA
(2018) High
Oil Price
Case,
Current
Policies
Projects
under EIA
(2018)
Low Oil
Price Case,
Current
Policies
Projects
under EIA (2018)
Reference Case,
Current Policies,
High Differential
In-situ Bitumen
Mine
In-situ Bitumen
Mine
In-situ Bitumen
Mine
In-situ Bitumen
Mine
In-situ Bitumen
Mine
Key Commodity Price Assumptions ($2018)
WTI Crude Oil at
Cushing ($/bbl)
55.96 102.27 231.21 41.81 102.27
Natural Gas at AECO/
NIT ($/MMBtu)
2.50 4.46 5.81 3.98 4.46
Diluted Bitumen at
Hardisty ($/bbl)
43.10 89.50 218.44 31.70 80.52
Bitumen value at plant
gate ($/bbl)
33.81 78.45 203.52 24.12 65.62
Diluted bitumen discount
to WTI ($/bbl)
12.86 12.77 12.77 10.11 21.75
$CAD/$US 1.22 1.03 1.03 1.3 1.03
Notes: The current prices and policies scenarios rely on WTI and Henry Hub natural gas 60-month forward curves as well as the 60-month forward curve for the Canadian dollar exchange rate as of March
22, 2018. The reference, high oil, and low oil price cases are from Energy Information Administration (2018). All commodity prices are in U.S. dollars. Henry Hub natural gas prices are converted to Alberta
Energy Company/Nova Energy Transfer (AECO/NIT) hub prices using a $0.50 per gigajoule discount. Beyond 2023, forward curve prices for oil and natural gas are treated as constant in real terms and
exchange rates are treated as constant.
The Economics of Canadian Oil Sands 259
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