Carbon Taxes and Financial Incentives for Greenhouse Gas Emissions Reductions in Alberta’s Oil Sands André Plourde Department of Economics and Faculty of Public Affairs Carleton University Ottawa ON K1S 5B6 Canada Phone: 613-520-2600 ext. 1858 Fax: 613-520-3742 e-mail: andre_plourde@carleton.ca Abstract It is widely considered that the continued development and production of Alberta’s oil sands deposits is on track to be the fastest growing source of greenhouse gas (GHG) emissions in Canada over the next few decades. As recent developments suggest, failure to address the issue of GHG emissions growth might jeopardize the potential for sustained expansion of oil sands operations in Alberta. With this in mind, a computer simulation model of a steam-assisted gravity drainage (SAGD) oil sands production facility is used to investigate the financial incentives provided by the introduction of a per-unit levy on CO2 emissions – a carbon tax – to SAGD producers to reduce production-related GHG emissions. Results are obtained for a range of carbon tax rates and crude oil prices. Special attention is paid to the interactions between the carbon tax and the provisions of the royalty and tax regime applicable to oil sands development and production activities in Alberta. Keywords: oil sands; greenhouse gas emissions; carbon tax; fiscal systems

1. Introduction1

Sustained increases in bitumen production from Alberta’s oil sands deposits are widely

expected to occur over the next few decades. A recent projection released by the Canadian

Association for Petroleum Producers (CAPP; 2011), for example, suggests a tripling of Alberta

bitumen production between 2010 and 2025. A similar picture of robust growth in oil sands

production can also be found in recent projections by Alberta’s Energy Resources Conservation

Board (ERCB; 2012) and Canada’s National Energy Board (NEB; 2011b), among others.

1 I wish to thank the Alberta Departments of Energy and of Finance for granting me permission to use some of the

information on which the analysis contained in this paper is based. I am also grateful to the Canadian Energy Research Institute for providing access to studies published by the Institute. All errors and omissions are my responsibility. An earlier version of this paper was presented at the “Boom and Bust Again: The Sequel” conference, sponsored by the Institute for Public Economics, University of Alberta. Comments of participants at that conference were most helpful in revision.

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It is also recognized, however, that current oil sands production technologies, processes,

and practices are such that this projected growth in production volumes will generate equally

pronounced increases in emissions of greenhouse gases (GHGs), mainly CO2. Indeed, as is

evident in Environment Canada (2011, Tables 5 and A1.2), the continued development of

Alberta’s oil sands deposits is expected to be a major source of growth in Canada’s GHG

emissions over the next decade. As recent developments such as the events around the

proposed construction of the Keystone XL pipeline to transport bitumen from Alberta to the Gulf

of Mexico coast suggest, failure to address the issue of GHG emissions growth might jeopardize

the potential for sustained expansion of oil sands operations in Alberta.

In light of these concerns, the object of this paper is to explore the potential for a specific

policy instrument, namely a carbon tax, to provide financial incentives for oil sands producers to

reduce GHG emissions associated with the extraction of bitumen. Since the analytical approach

adopted does not allow the derivation of endogenous behavioural responses on the part of oil

sands producers to the introduction of a carbon tax, the focus of the analysis is on documenting

the kinds of financial “incentives” that varying rates of such a tax would offer producers to act to

reduce production-related GHG emissions. How much would the introduction of a carbon tax at

a specified rate increase the per-barrel bitumen development and production costs borne by an

oil sands producer, assuming that the producer does not respond to the introduction of the

carbon tax by changing the production process, the input mix, etc.? This kind of information

stands to be a key input in the decisions by bitumen producers to act to reduce GHG emissions,

or simply pay the tax.

Since more than 80% of remaining reserves of bitumen in Alberta are only producible

with the use of in situ technologies and since such technologies – of which steam-assisted

gravity drainage (SAGD) is a prime example – tend to generate more GHG emissions per barrel

of bitumen produced than do surface mining operations, the focus of the paper is on an

assessment of the incentives for emissions reductions that a carbon tax could provide to SAGD

producers.2 The analysis will be undertaken for a range of assumed carbon tax rates and crude

oil prices. In addition, special attention will be paid to the interactions between the carbon tax

and the provisions of the royalty and tax regime applicable to oil sands production and

development activities in Alberta. Much of this work will rely on the use of a revised version of a

computer simulation model developed in the course of earlier research activities relating to oil

sands royalties and taxes (Plourde 2009; 2010).

2 For a recent description of the extent and characteristics of Alberta’s oil sands deposits, see ERCB (2012, section

3). A discussion of GHG emissions in the context of oil sands operations can be found in Droitsch et al. (2010).

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The remainder of the paper proceeds as follows. Section 2 provides a description of the

simulation model used in the analysis. Key assumptions incorporated in the model and

embodied in the simulations are also outlined. Section 3 establishes baseline results for a range

of assumed crude oil prices. Results of simulations that exclude the provisions of the royalty and

tax regime currently applicable to oil sands development and production in Alberta are first

reported. The royalty and tax provisions are then taken into consideration in subsequent

simulation exercises and the results obtained from these are outlined. In Section 4, the

simulation model is modified to include a carbon tax, or more precisely a tax on CO2 emissions.

Estimates of the share of this tax borne by producers are obtained under a variety of

assumptions about tax rates, crude oil prices, and the treatment carbon tax payments within the

royalty and tax regime applicable to oil sands operations in Alberta. Section 5 concludes.

2. Simulation Model: Design, Key Assumptions and Characteristics3

The simulation model used in this paper is one of two generic models of oil sands

production developed over the last five years, one for each of in situ production and surface

mining operations. Since the focus of this paper is on in situ production, only the model of a

60,000-barrel-per day SAGD facility, assumed to be located in Alberta’s Cold Lake region, is

used in this paper. The current version thus builds upon those described and used in Plourde

(2009; 2010).

Key assumptions relating to the development and production aspects of SAGD

operations embodied in the model are summarized in Table 1. Information about the levels of

initial and annual sustaining capital expenditures are taken from a recent publication by the

Canadian Energy Research Institute (CERI; 2012, chapter 3). Since the SAGD project

examined in that publication consists of a 30,000-barrel-per-day facility, the estimates contained

therein have simply been doubled for the purposes of this paper. I recognize that this likely

results in an overestimation of the underlying capital expenditure structure of the larger facility

represented in the simulation model. The annual distribution of initial capital expenditures over

the period of construction is taken from the work of the Alberta Royalty Review Panel (2007), as

is the profile of annual bitumen production.

The estimate of non-energy operating expenditures associated with the production of

each barrel of bitumen is also taken from CERI (2012, Table 3.1) and assumed to apply to the

3 This sections draws heavily from the corresponding parts of Plourde (2010).

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larger SAGD facility modelled here.4 Estimates of energy-related operating expenditures

incorporate information from McColl and Slagorsky (2008, p.29). It is thus assumed that the

production of each barrel of bitumen by the stylized SAGD facility requires the use of 10

kilowatt-hours (kWh) of purchased electricity and of 1.0655 gigajoules (GJ) of natural gas. As

one might expect, this assumed use of natural gas is of critical importance for this paper since it

is the only source of greenhouse gas emissions included in the analysis. Each GJ of natural gas

used in the production of bitumen is assumed to generate 51.36 kilograms (kg) of CO2, as is the

case in McColl and Slagorsky (2008, p.28). The production of a barrel of bitumen through SAGD

operations is thus considered to result in the emission of 54.72 kg of CO2.5

Overall, the set of assumptions outlined above yields estimates of per-barrel capital and

operating expenditures that are higher than those obtained in Plourde (2009; 2010) at all crude

oil prices considered.

The construction and operations of SAGD facilities typically requires both domestically

produced and imported inputs. Assumptions about the share of imported inputs are taken from

Timilsina et al. (2005); for simplicity, all imported inputs are assumed to be priced in US dollars.

The assumed share of imports associated with capital expenditures is thus 11% (as noted in

Table 1), while that applicable to non-energy operating expenditures is 20%. Throughout the

time period under consideration, it is assumed that the Canadian dollar trades at a slight

premium over its US counterpart. Specifically, the exchange rate used is $(Cdn) 1 = $(US)

1.007, which is the forecast value to be found in the federal budget of March 2012 (Department

of Finance, Government of Canada 2012, Table 2.1).

As in Plourde (2010), the prices of crude oil (including that for bitumen), electricity, and

natural gas are not assumed to be determined independently. Indeed, for the purposes of this

paper, simple rules of thumb based on prices observed during the most recent five years for

which complete data were available at the time of writing (namely, January 2007 to December

2011) are assumed to represent what are undoubtedly much more complex cross-price

linkages. The US-dollar spot price of West Texas Intermediate (WTI) crude oil delivered at

4 Estimates of capital and non-energy operating expenditures in CERI (2012) are expressed in units of Canadian

currency, at 2010 prices. These are transformed into values expressed in Canadian dollars, at 2012 prices, by applying the Alberta-specific GDP deflator taken from the relevant February 2012 Alberta budget document (Alberta Finance 2012, p.66). 5 An obvious shortcoming of the analysis is the exclusion of the GHG emissions associated with the generation of

the purchased electricity. A number of different approaches to including these emissions were considered and all found to have significant shortcomings of their own. As a result, I opted to exclude these emissions from the analysis. Under the assumption that the purchased electricity is the product of gas-fired generation plants, this decision implies that CO2 emissions associated with in situ bitumen production are understated by approximately 10%.

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Cushing (OK) is the key underlying price in the simulation model: it drives the assumed prices of

all other energy commodities considered.

Figure 1 shows the spot price of WTI delivered at Cushing and the bitumen price,

measured at Cold Lake for the period January 2000 to December 2011. Both are current-dollar

prices expressed in units of Canadian currency.6 The quality-related price differential

commanded by WTI is quite clear, as is its variability over time. Figure 2 provides a

representation of the bitumen price as a proportion of that for WTI. Over the course of the

twelve-year period covered by Figure 2, bitumen prices (at Cold Lake) have, on average,

equaled 58.75% of WTI prices (at Cushing). More recently, bitumen prices have risen relative to

WTI prices, such that between January 2007 and December 2011 this proportion reached

67.33%. As Figure 2 suggests, this increase in the relative price of bitumen continued to be

experienced toward the end of this five-year period. For example, the price of bitumen relative to

that of WTI exceeded its 2007-2011 average in nine of the twelve months of 2011. For the

purposes of this paper, however, the price of bitumen at Cold Lake is assumed to equal 67.33%

of the Canadian-dollar price of WTI at Cushing. This implies that at an assumed 2012 WTI price

of $(US) 90 per barrel – comparable to levels observed at the time of writing – the

corresponding bitumen price at Cold Lake would be $(Cdn) 60.18 per barrel, about 20% lower

than the bitumen price of $79.65 realized in December 2011 (when the price of WTI reached

$(US) 98.56).

A similar approach is used to link natural gas prices in Alberta to the price of WTI. Here,

a standard approach in the industry is to express crude oil prices and natural gas prices as

multiples of one another. With this in mind, Figure 3 shows the WTI price at Cushing (in current

Canadian dollars per barrel, as above) expressed as a multiple of the spot price of natural gas

in Alberta (in current Canadian dollars per GJ).7 As Figure 3 makes clear, there has been a

sustained trend in the relationship between crude oil and natural gas prices over the course of

the period extending from 2000 to 2011: the price of natural gas has fallen sharply relative to

that for crude oil. In 2000, for example, the average multiple was 10.22, while the corresponding

value for 2011 was 26.75. In the last dozen years or so, much has been said and written about

the evolution of the North American natural gas market and on the factors – including the

technology-driven development of shale gas deposits – that have led to a period of sustained

6 The source for the spot price of WTI is the US Energy Information Administration. This price series is converted

into units of Canadian currency using monthly averages of the noon spot exchange rate, available from Statistics Canada. Bitumen prices are taken from various issues of ST-3: Alberta Energy Resources Industries Monthly Statistics, published by Alberta’s ERCB. The issues of ST-3 for 2012 do not include a price for bitumen. 7 Natural Resources Canada is the source for these natural gas prices.

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low natural gas prices in North America.8 For the purposes of this paper, however, the key

element that is taken into consideration is simply the fact that, on average, between January

2007 and December 2011, the Canadian-dollar spot price of WTI at Cushing has been 18.6

times that of natural gas in Alberta. This implies that in the simulation work reported below, each

increase of $(Cdn) 1 in the price of WTI leads to an increase of 5.4 cents(Cdn) in the assumed

price of natural gas in Alberta. Overall, this translates a 2012 WTI price of $(US) 90 into an

assumed spot price of natural gas in Alberta of $4.81 per GJ, well above the prices observed at

the end of 2011 and at the time of writing.

A final relationship among prices of energy sources that is reflected in the simulation

model concerns that between natural gas and electricity. In Alberta’s restructured electricity

market, the wholesale price of electricity is most often set by the bid price of gas-fired

generation, which implies that electricity prices are generally tied to natural gas prices. Figure 4

shows the wholesale price of electricity in Alberta (in dollars per megawatt-hour, MWh) as a

multiple of the spot price of natural gas (in dollars per GJ) in the province.9 Although the

relationship between these two prices seems quite volatile, it has exhibited a slight upward trend

toward the end of the period under consideration. Between January 2000 and December 2006,

for example, wholesale electricity prices were, on average, 12.94 times those for natural gas. In

the five subsequent years, that multiple rose to 14.43, which is the value used in the simulation

model to obtain estimates of electricity prices for given natural gas prices in Alberta. Once all

relevant linkages are made, this means that a (2012) WTI price of $(US) 90 would yield an

assumed Alberta wholesale price of electricity of $69.19 per MWh, well above the wholesale

price of $53.20 observed, on average, in December 2011 (and also well in excess of the

average price of $49.95 realized in the first six months of 2012).

Overall, for given prices of WTI and when compared to the situation prevailing at the end

of 2011 and at the time of writing, the rules-of-thumb outlined above and used in this paper to

link the prices of different energy commodities would thus appear to yield underestimates of the

revenues generated by bitumen production, and overestimates of the per-barrel energy-related

operating expenditures associated with this production.

The simulation model also includes a detailed representation of the royalty and tax

regime applicable to oil sands development and production in Alberta. The regime currently in

effect includes five revenue-collecting instruments, four of which are under the authority of the

Government of Alberta (namely, bonus bids, rentals, royalties, and the provincial corporate

8 See NEB (2011a) for a recent discussion of some key salient factors.

9 Wholesale electricity prices are taken from Alberta Electric System Operator.

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income tax) and one – the federal corporate income tax – under the control of the Government

of Canada.

Bonus bids are one-time payments made by developers as a result of first-price lease

auctions to allocate production rights to the province’s oil sands deposits. The same approach

as that described in Plourde (2010, p.4655) is used to obtain estimates of the bonus bid for the

stylized SAGD operation modelled in this paper. Although estimated payments are positively

linked to bitumen prices, these payments remain small relative to the net revenues generated by

oil sands production, as with the actual experience in Alberta. For example, the model-

generated estimate of the bonus bid associated with the stylized SAGD project is about $14.8

million (at a 2012 WTI price of $(US) 90 per barrel), slightly more than 1% of the gross

production revenues realized in a single year of peak production.

In Alberta, rentals are land-related annual payments of negligible size. For example,

current provisions are such that rentals associated with the SAGD project modelled would reach

approximately $20,000 per year, at 2012 prices.

In 2007, the Government of Alberta announced and subsequently enacted a series of

changes in the royalty framework applicable to oil and gas operations in the province, including

oil sands (Government of Alberta, 2007). For the purposes of this paper, suffice it to note that

the base royalty is levied against gross bitumen production revenues until such a time as the

project developer has recovered all eligible expenditures (including capital and operating

expenditures, base royalty payments, rentals, and an interest/return allowance calculated at the

long-term government bond rate), or – in the language that has developed around the oil sands

royalty system – until project “payout” is achieved. Thereafter, a net revenue royalty is collected

on revenues from bitumen production, net of eligible operating and capital expenditures.

Technically, the greater of the base royalty and the net revenue royalty is payable once all

eligible expenditures have been recovered (i.e., once payout has been achieved). In the

situations examined in this paper, however, it is always the case that, after payout, calculated

net revenue royalty payments exceed the estimated corresponding base royalty. This also

corresponds to the experience of oil sands development projects currently operating in Alberta:

the net revenue royalty is paid once project payout has been achieved.

Statutory rates for both types of royalties vary with WTI prices, expressed in Canadian

dollars. In the case of the base royalty, a minimum rate of 1% is applied when WTI prices are

less than or equal to $55 per barrel. A maximum rate of 9% applies when WTI prices are greater

than $120. Royalty rates at prices in between these two bounds are determined by linear

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interpolation. The same approach is used to determine net revenue royalty rates, with the key

difference that here rates vary between 25% and 40%.

The federal and provincial corporate income tax (CIT) provisions incorporated in the

simulation model are of general application in Canada and Alberta, while reflecting the specific

treatment extended to oil sands operations. For example, the federal and provincial tax rates

used are respectively 15% and 10%, as would be the case for most for-profit companies

operating in Alberta. As per existing CIT provisions, royalty payments are considered to be fully

deductible in the calculation in taxable income. Capital cost allowances generated by most

expenditures on physical capital are assumed to be calculated according to a 25% declining

balance rule, with some delay in the ability to claim these allowances prior to the project

initiating production.

Finally, as is the case in Helliwell et al. (1989), among others, a real discount rate of 7%

was used in the calculation of all present values. The general rate of price inflation is assumed

to be 2.1%, equal to the forecast rate of change of the GDP deflator included in the March 2012

federal budget (Department of Finance, Government of Canada 2012, Table 2.1). The long-term

government bond rate is assumed to be 3.5%, and is taken from the same source.

3. Model Outcomes: SAGD Operations at Different Price Levels

The first task to be undertaken is to establish a baseline of simulation results that can

then be used to assess the possible consequences of introducing a carbon tax. With this in

mind, model simulations were completed for different values of the real (2012) US-dollar price of

WTI. In each case, the specified price was assumed to stay constant – in real terms – for the

entire simulation period. Figure 5 shows estimated real, discounted total costs and net present

values (NPVs) for the stylized SAGD plant described in the previous section. As the real WTI

price grows, assumed electricity and natural gas prices rise in consort, thus resulting in

increased per-barrel energy-related operating expenditures. We can see, however, that this

effect is relatively weak since total real discounted costs increase by only about 40% when WTI

prices rise from $(US) 25 to $(US) 150, or 500%. SAGD operations of the type considered here

emerge as no better than marginal commercial ventures at real WTI prices of less than $(US)

40 or so, even in the absence of any royalties and taxes.

Figure 6 provides representations of the distribution of the estimated real NPVs

generated by the simulated operation of the type of SAGD plant modelled, once the provisions

of the royalty and tax regime currently applicable to oil sands development and production are

taken into consideration. At all prices considered, the Government of Alberta is estimated to

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receive the largest share of the net revenues generated by the stylized SAGD plant. As agent of

the owners of the resource (all Albertans) and as fiscal authority, the provincial government is

estimated to capture between 47% and 50% of project NPVs under all prices considered. The

next largest share of the estimated net revenues accrues to producers, who stand to secure

somewhere between 36% and 43% of the resulting NPVs – closer to the lower bound when

assumed WTI prices are at the bottom end of the range considered, rising slowly as real WTI

prices increase. Finally, the federal government is seen to capture a much smaller fraction of

the estimated net revenues generated by simulated SAGD operations. At lower WTI prices, the

federal share exceeds 10% (and reaches 14% at $(US) 50), but settles at values in the 9%

range at real WTI prices of $(US) 90 and above.

At lower WTI prices, a key factor affecting the distribution of net revenues from SAGD

operations is the interplay between up-front capital expenditures and the treatment extended to

such expenditures by the federal and provincial CIT provisions. This is perhaps best illustrated

by the fact that, over some range of prices, the NPV share estimated to accrue to the federal

government falls as real WTI prices rise. After all, the CIT is the only source of federal

government revenues from oil sands operations included in the model.

4. Model Outcomes: The Effects of Introducing a Carbon Tax

The simulation model described in Section 2 was then modified to allow for the

introduction of a tax on CO2 emissions generated by SAGD operations. As noted earlier, the

production of a barrel of bitumen through SAGD operations is assumed to generate 54.72 kg of

CO2 emissions. At a peak daily production of 60,000 barrels per day, this represents total

annual CO2 emissions of 1.2 megatonnes (Mt). In a manner consistent with regulations issued

under Alberta’s Climate Change and Emissions Management Act, it is assumed that the first

100,000 tonnes of CO2 emitted by the SAGD facility in every year of operation are exempted

from any carbon tax.

A carbon tax is here modelled as a payment by the SAGD producer to governments for

each tonne of CO2 emitted, in excess of the first 100,000 emitted in each year of operations.

Since the purpose of this paper is to assess the financial incentives for CO2 emissions

reductions that such a tax extends to producers, it is immaterial as to which of the federal or

provincial government receives the tax payment. What matters, however, is the treatment

extended to this tax payment within the overall royalty and tax regime. Initially, it will be

assumed that the carbon tax is a source of eligible expenditures for both royalty and CIT

purposes. All else held equal, the introduction of a carbon tax would thus lengthen the period

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during which the base royalty is collected (and thus delay the onset of the net revenue royalty)

since it would increase the amount of eligible expenditures that the producer would be allowed

to recover before starting to pay the net revenue royalty. On its own, a carbon tax would also act

to reduce net revenue royalty payments since it would result in an increase in eligible

expenditures for each barrel of bitumen produced. Finally, the introduction of a carbon tax would

also act to reduce CIT payments by lowering taxable income. Producers would thus not fully

bear the consequences of a carbon tax since such tax payments would be partly offset by lower

royalty and CIT payments, all else held equal. The implications of not allowing carbon tax

payments to be considered as eligible expenditures for the purposes of one or another of these

revenue-sharing instruments (i.e., royalties or CIT) will also be considered.

Consequences of the introduction of a carbon tax at rates ranging from $5 to $50 (by

increments of $5) per tonne of CO2 emitted were simulated over the same range of WTI prices

as that used in Section 3. Tax rates were specified in real terms (i.e., Canadian dollars at 2012

prices) and assumed to remain constant over the entire production life of the stylized SAGD

plant. Figure 7 shows the estimated implications of the introduction of a carbon tax on the real,

discounted (i.e., measured in end-2011 dollars) per-barrel costs of SAGD production. As one

would expect given the assumed structure of the tax, the resulting estimated per-barrel cost

increases are not sensitive to assumptions about crude oil prices, but vary proportionately with

the carbon tax rate. These results suggest that an estimated increase in real, discounted per-

barrel costs of about 24.5 cents follows from each increase of $5 in the carbon tax rate.

Figure 8 shows the carbon tax as a share of the estimated total capital and operating

expenditures per barrel of bitumen produced. Over the range of carbon tax rates and WTI prices

considered, the introduction of a carbon tax represents estimated increases of slightly less than

1% in per-barrel costs of bitumen production when prices and rates are at the lower end of the

ranges considered, and of about 10% at the upper end of the same ranges. As noted earlier, an

implication of the assumed linkages among energy prices is that electricity and natural gas

prices – and thus SAGD operating costs – increase as WTI prices rise. By extension, this

means that a carbon tax of any given rate will give rise to proportionately smaller increases in

per-barrel costs of bitumen production as WTI prices are assumed to rise from $(US) 50 to

$(US) 150, as is evident from Figure 8.

Among the cases considered, the most pronounced effect identified occurred at a WTI

price of $(US) 50, where per-barrel costs were estimated to rise by slightly less than 10% when

the carbon tax rate was assumed to be equal to $50. At an assumed WTI price of $(US) 90, the

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estimated increase in per-barrel costs varies from 0.9% to 9% as the carbon tax rate goes from

$5 to $50 per tonne of CO2 emitted.

Given the structure and properties of the applicable royalty and tax regime, how much of

these per-barrel cost increases are estimated to be borne by the SAGD producer? Figure 9

provides a representation of the simulation results aimed at shedding light on this question. As

carbon tax rates rise, the estimated per-barrel cost to producers of the resulting tax payments

also rises, thus providing increasingly stronger incentives for producers to act to reduce CO2

emissions for all WTI prices considered. On a similar note, for any given carbon tax rate,

estimated increases in producer-borne costs tend to be higher at lower WTI prices, at least until

these prices reach about $(US) 95 per barrel. These results also suggest that, all else held

equal, financial incentives for SAGD producers to reduce CO2 emissions associated with the

introduction of a carbon tax are likely to be stronger at lower WTI prices.

The key element of the royalty and tax regime responsible for bringing about this inverse

relationship between WTI prices and the share of a carbon tax of any rate estimated to be borne

by producers is the price-sensitive nature of both base and net revenue royalty rates. As noted

in Section 2 above, these royalty rates rise progressively as (nominal) WTI prices (expressed in

units of Canadian currency) rise from $55 to $120 per barrel and remain at these maximum

values for higher WTI prices. Given some of the assumptions embedded in the model (such as

those for the exchange rate, the rate of general price inflation, and the bitumen production start

date), most of the effects of the “progressive” characteristics of these royalty rates have been

felt once real pre-barrel WTI prices have reached assumed levels of about $95, in units of US

currency at 2012 prices.

Model results suggest that, over the range of carbon tax rates and WTI prices

considered, estimated per-barrel producer cost increases reach a maximum of about $1.37

(end-2011 dollars) at a tax rate of $50 and a WTI price of $(US) 50, or about $25 (end-2011

dollars) per emitted tonne of CO2, once the provisions of the royalty and tax regime are taken

into account. At an assumed WTI price of $(US) 90 per barrel, increases in discounted per-

barrel costs borne by SAGD producers are estimated to range between $0.12 and $1.17 (or,

alternatively, between $2.25 and $21.50 per tonne of CO2 emitted), as carbon tax rates vary

between $5 and $50.

Although not evident from Figures 7 and 9, the resulting increases in per-barrel costs of

bitumen production are never sufficiently large to yield negative estimated NPVs either for the

project as a whole or for the NPV shares accruing to the producer. Indeed, these remain solidly

positive for all carbon tax rates and WTI prices considered. In almost all cases considered,

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estimated real internal rates of return (IRR) to the SAGD producer widely exceed 10%. Indeed,

only when the carbon tax rate reaches $30 per tonne of CO2 emitted at an assumed WTI price

of $(US) 50 does estimated real producer IRR fall below 10%. For additional context, at an

assumed WTI price of $(US) 90 per barrel, the estimated real producer IRR ranges from 19.3%

to 18.5% as the carbon tax rate goes from $5 to $50.

Figure 10 presents the results summarized in Figures 7 and 9 from a different

perspective. The information presented in Figure 10 is the ratio of all “data” points underlying

Figure 9 to the corresponding entries in the information set presented in Figure 7. The estimated

proportion of the increased per-barrel bitumen production costs associated with the introduction

of a carbon tax that is borne by the SAGD producer is thus shown in Figure 10. Doing so

arguably makes more evident the pattern of producer incentives for CO2 emissions reductions

provided by the oil sands royalty and tax regime as assumed carbon tax rates and WTI prices

vary. It also makes even more evident the implications of the price-sensitive nature of Alberta’s

royalty system: for some range of prices, the share of a carbon tax of any rate borne by

producers is expected to fall as crude oil prices rise. Indeed, the estimated share of the carbon

tax borne by the SAGD producer approaches 56% for oil prices at the lower end of the range

considered and settles at around 46% for all carbon tax rates between $5 and $50 per emitted

tonne of CO2, at WTI prices of $(US) 95 and above. As long as WTI prices are at least $(US) 75

per barrel, then the estimated producer-borne share of such a tax is less than 50% in all cases

considered. For example, at a WTI price of $(US) 90 – similar to that prevailing at the time of

writing – the producer-borne share of a carbon tax is estimated to be about 47.5% for all tax

rates considered. Once again showing that, for any given tax rate, financial incentives for

producers to reduce CO2 from SAGD production tend to fall as WTI prices rise, at least until

prices of about $(US) 95 are reached.

The sudden “dip” observed in Figure 10 at a WTI price of $(US) 95 and carbon tax rates

of $15 and $20 illustrates a property of Alberta’s oil sands royalty framework that was described

in Plourde (2010, section 5.2) and discussed briefly in Section 2 above.10 To the extent that

carbon tax payments are considered eligible expenditures for purposes of calculating royalty

payments, the provisions of the royalty and tax regime applicable to Alberta’s oil sands are such

that the introduction of a carbon tax of the type considered in this paper would trigger an

endogenous change in the length of the time period before project payout is achieved, when

compared to the situation prevailing in the absence of any such tax. The introduction of a

carbon tax would yield, all else held equal, a longer payout period for the stylized SAGD plant,

10

A few other such “dips” are observable in Figure 10, but this one is the most clearly visible.

13

thus delaying the onset of the net revenue royalty, thereby reducing the effective royalty rate

paid by the producer. As a result of the longer payout period, the share of the carbon tax borne

by the producer is smaller and the financial incentives provided to SAGD producers to reduce

production-related CO2 emissions are (slightly) weakened. While the “dip” observable in Figure

10 is due to the interaction between this effect and specific assumptions about discounting

embodied in the simulation model, the generic effect described above applies for all

combinations of carbon tax rates and crude oil prices.

At the beginning of this section, the notion of assessing the implications of assuming that

carbon tax payments are not considered eligible expenses for either royalties or CIT was raised.

Model simulations were undertaken to shed some light on this issue. The most straightforward

case occurs when carbon tax payments are deemed eligible expenditures for CIT purposes, but

considered to be ineligible payments within the royalty framework. In that case, SAGD

producers are estimated to bear 75% (that is, 1 – federal CIT rate – provincial CIT rate) of all

increases in per-barrel costs due to the introduction of a carbon tax. As one would expect, this

result holds for all carbon tax rates and across all WTI prices considered. Higher carbon tax

rates would thus yield commensurately greater producer incentives for CO2 emissions

reductions if carbon tax payments were not considered eligible expenditures for royalty

purposes, and would do so at all WTI prices. From the producer’s perspective, the estimated

effects on the per-barrel costs of bitumen production can thus be represented by a downward,

parallel shift of the plane represented in Figure 7: all of the “data” points forming that plane

would simply be 75% of those underlying the results in Figure 7.

A slightly more complicated case emerges when the carbon tax payments are

considered eligible expenditures within Alberta’s royalty framework, but cannot be deducted in

the calculation of taxable income for federal and provincial CIT purposes. The results of model

simulations embodying these assumptions can be represented as an upward shift by 25

percentage points (the sum of federal and provincial CIT rates) of the plane depicted in Figure

10. The pattern of producer incentives for reducing CO2 emissions is thus quite similar in this

case to that described when carbon tax payments are considered eligible expenditures for both

royalty and CIT purposes. The stronger financial incentives provided at lower WTI prices

remain, but the parallel shift of the results plane implies that these are slightly muted in

comparison to those extended at WTI prices of $(US) 95 and above.

14

5. Summary and Conclusion

GHG emissions represent a critical risk to the continued development of Alberta’s oil

sands deposits. We need to look no further than the recent events surrounding the proposed

construction of the Keystone XL pipeline and the ongoing questions raised about the proposed

Northern Gateway pipeline project to appreciate the seriousness of the challenge posed by the

public reaction – in Canada and internationally – to the environmental issues associated with oil

sands development. Chief among these concerns is the growth in GHG emissions linked to

projected expansions in bitumen production.

For Alberta, the stakes are high. Sustained economic prosperity arguably rests in no

small way on the ability to develop and extract the huge bitumen reserves contained in the

province’s oil sands deposits. Yet, this ability now appears to be challenged in ways not

previously experienced. From a policy perspective, it would thus appear desirable to address

these challenges head on by devising and implementing elements of a climate policy that would

be widely perceived as credible and effective. This paper assesses potential implications of the

introduction of what could well be an integral component of such a policy, namely a carbon tax.

A computer simulation model of a stylized SAGD production facility is used to explore

aspects of the possible consequences of levying a carbon tax on the CO2 emissions associated

with bitumen extraction using this relatively emissions-intensive (compared to surface mining

operations) production technology. Simulation results were obtained for a range of carbon tax

rates and crude oil prices. Special attention was paid to the consequences of the interactions

between the carbon tax and the provisions of the royalty and tax system applicable to oil sands

development and production in Alberta.

As noted in previous sections, the model used in the analysis does not allow for

behavioural responses by the SAGD producer to the introduction of a carbon tax of any rate.

The results obtained can thus provide no insight into producer-initiated changes in extraction

technology, production processes, input use, etc. that might be induced by the introduction of

such a tax. All else held equal, these results will thus overestimate the increases in the cost

structure for oil sands development and production activities likely to be observed in the advent

of the introduction of a carbon tax at rates equivalent to those considered in the analysis. In

response to the introduction of a carbon tax, producers could always act to reduce (per-barrel)

emissions and thus dampen the net effect of any such tax on the overall cost structure of

bitumen production if it were in their best (financial) interests to do so. The results, however, can

provide indications of the financial incentives extended to producers to act to reduce production-

related CO2 emissions as a consequence of the introduction of a carbon tax.

15

With the above caveat in mind, the simulation results suggest that the overall effects on

the costs of SAGD development and production of introducing a carbon tax at rates varying

from $5 to $50 per tonne of CO2 emitted are estimated to be relatively modest. Indeed, these

results suggest that the introduction of such a tax could potentially bring about increases in

(real, discounted) per-barrel costs of development and production that would be at most in the

order of 1% to 10%. It is also shown that once the provisions of the royalty and tax regime

applicable to Alberta’s oil sands are taken into consideration, the share of these cost increases

potentially borne by producers is estimated never to exceed 56% in all cases considered and to

be less than 50% for a wide range of conditions, including the kinds of market conditions

prevailing at the time of writing. The remaining portion of the carbon tax would be borne by the

public (mostly Albertans) in the form of reduced royalty and CIT revenues. The results also

indicate that the properties of the royalty system are such that, for all tax rates included in the

analysis, a greater proportion of the financial implications of the introduction of a carbon tax are

estimated to be borne by SAGD producers at lower crude oil prices, at least until assumed real

WTI prices reach about $(US) 95 per barrel.

Instead of interpreting these results as projections of actual cost increases likely to be

observed were a carbon tax to be introduced, the approach adopted in this paper is one where

the estimated cost increases are seen as indicative of the kinds of financial incentives offered to

SAGD producers to reduce the CO2 emissions associated with bitumen extraction. As noted

earlier, producers always have the option (granted, not one that is explicitly reflected in the

analysis) of acting to reduce emissions (for any given level of production) and thus forego the

obligation to make the tax payments associated with the eliminated emissions if it were more

advantageous for them to do so. The results obtained clearly show that the pattern of financial

incentives extended to SAGD producers through the introduction of a carbon tax is shaped by

the tax and – especially – the royalty provisions applicable to oil sands development and

production activities in Alberta.

This paper represents a modest contribution to the continued development of an

information set concerning the possible implications and the overall effectiveness of carbon

taxes as a climate policy instrument in the context of oil sands operations. The question

remains, however, as to whether and by how much the kinds of financial incentives estimated to

be extended to oil sands producers by a carbon tax at the rates considered would be sufficient

to induce these producers to act to reduce CO2 emissions linked to bitumen production.

16

References Alberta Finance (2012) Budget 2012 – Investing in People. Fiscal Plan 2012-2015. Economic Outlook. Minister of Finance, Edmonton, February. Alberta Royalty Review Panel (2007) Our Fair Share – Report of the Alberta Royalty Review Panel: www.albertaroyaltyreview.ca/panel/final_report.pdf Canadian Association of Petroleum Producers – CAPP (2011) “Canadian Crude Oil Forecast and Market Outlook”, CAPP, Calgary, June. Canadian Energy Research Institute – CERI (2012) “Canadian Oil Sands Supply Costs and Development Projects (2011-2045)”, Study No. 128, CERI, Calgary, March. Department of Finance, Government of Canada (2012) Jobs, Growth and Long-term Prosperity – Economic Action Plan 2012. Public Works and Government Services Canada, Ottawa, March. Droitsch, D., M. Huot, P.J. Partington (2010) “Canadian Oil Sands and Greenhouse Gas Emissions – The Facts in Perspective”, Pembina Institute Briefing Note, August. Energy Resources Conservation Board – ERCB (2012) “ST98-2012: Alberta’s Energy Reserves 2011 and Supply/Demand Outlook 2012-2021”, ERCB, Calgary, June. Environment Canada (2011) “Canada’s Emissions Trends”, Minister of the Environment, Ottawa, July. Government of Alberta (2007) The New Royalty Framework: www.energy.gov.ab.ca/Org/pdfs/royalty_Oct25.pdf Helliwell, J.F., M.E. MacGregor, R.N. McRae, A. Plourde (1989) Oil and Gas in Canada: The Effects of Domestic Policies and World Events. Canadian Tax Foundation, Toronto. McColl, D., M. Slagorsky (2008) “Canadian Oil Sands Supply Costs and Development Projects (2008-2030)”, Study No. 118, CERI, Calgary, November. National Energy Board – NEB (2011a) “Short-term Canadian Natural Gas Deliverability 2011-2013. An Energy Market Assessment”, NEB, Calgary, May. National Energy Board – NEB (2011b) “Canada’s Energy Future: Energy Supply and Demand Projections to 2035”, NEB, Calgary, November. Plourde, A. (2009) “Oil Sands Royalties and Taxes in Alberta: An Assessment of Key Developments since the Mid-1990s”, The Energy Journal 30(1): 111-139. Plourde, A. (2010) “On Properties of Royalty and Tax Regimes in Alberta’s Oil Sands”, Energy Policy 38(10): 4562-4662. Timilsina, G.R., N. LeBlanc, T. Walden (2005) "Economic Impacts of Alberta’s Oil Sands – Volume I. Main Report”, CERI, Calgary, August.

17

Table 1 Stylized SAGD Bitumen-production Facility: Key Assumptions

Beginning of construction

End of construction

First year of production First year of peak production

Last year of production Peak production (barrels per day)

Total production over life of project (millions of barrels)

Total capital expenditures (billions of 2012$) Import content for capital expenditures (percent)

Capital expenditures per barrel of daily peak production (thousands of 2012$) Capital expenditures per barrel produced (2012$)

at a real (2012) WTI price of $(US) 90 per barrel

Bitumen price (per barrel, 2012$) Total operating expenditures (billions of 2012$)

Operating expenditures per barrel produced (2012$) Total capital and operating expenditures per barrel produced (2012$)

2013 2018

2016 2021 2045

60,000 569

3.1 11

51.2 5.40

60.18 9.0

15.80 21.20

18

0

20

40

60

80

100

120

140

curr

en

t C

dn

$ p

er

bar

rel

Figure 1. Prices of WTI and Bitumen January 2000 to December 2011

WTI Bitumen

0

20

40

60

80

100

pe

rce

nt

Figure 2. Bitumen Price as Proportion of WTI Price January 2000 to December 2011

% bitumen/WTI 2007-11 Average

19

0

10

20

30

40

Figure 3. WTI Price as a Multiple of the Alberta Price of Natural Gas

January 2000 to December 2011

WTI / Natural Gas 2007-11 Average

0

10

20

30

40

50

Figure 4. Alberta Wholesale Electricity Price as a Multiple of the Natural Gas Price

January 2000 to December 2011

Electricity / Natural Gas 2007-11 Average

20

-2000

0

2000

4000

6000

8000

10000

12000

20 30 40 50 60 70 80 90 100 110 120 130 140 150bill

ion

s o

f e

nd

-20

11

Cd

n d

olla

rs

WTI price in real (2012) US dollars per barrel

Figure 5. Estimated Discounted Total Costs and NPVs, SAGD

Total Costs

NPV

0

10

20

30

40

50

60

pe

rce

nt

WTI price in real (2012) US dollars per barrel

Figure 6. Distribution of Estimated NPV, SAGD

Producers Alberta Federal

21

tax=5

tax=20

tax=35

tax=500

0.5

1

1.5

2

2.5

real

(2

01

2)

$(C

dn

) p

er

ton

ne

of

CO

2

real

, en

d-2

01

1 $

(Cd

n)

pe

r b

arre

l

WTI price in real (2012) $(US) per barrel

Figure 7. Carbon Tax as Estimated Per-barrel Cost

2-2.5

1.5-2

1-1.5

0.5-1

0-0.5

tax=5

tax=20

tax=35

tax=500

2

4

6

8

10

real

(2

01

2)

$(C

dn

) p

er

ton

ne

of

CO

2

pe

rce

nt

WTI price in real (2012) $(US) per barrel

Figure 8. Carbon Tax as Share of Estimated Per-barrel Costs

8-10

6-8

4-6

2-4

0-2

22

tax=5

tax=20

tax=35

tax=500

0.2

0.4

0.6

0.8

1

1.2

1.4

50 60 70 80 90 100 110 120 130 140 150

real

(2

01

2)

$(C

dn

) p

er

ton

ne

of

CO

2

real

, en

d-2

01

1 $

(Cd

n)

pe

r b

arre

l

WTI price in real (2012) $(US) per barrel

Figure 9. Estimated Carbon Taxes Borne by SAGD Producer

1.2-1.4

1-1.2

0.8-1

0.6-0.8

0.4-0.6

0.2-0.4

0-0.2

tax=5

tax=20

tax=35

tax=5045

47

49

51

53

55

57re

al 2

01

2 $

(Cd

n)

pe

r to

nn

e o

f C

O2

pe

rce

nt

WTI price in real (2012) $(US) per barrel

Figure 10. Estimated Share of Carbon Tax Borne by Producer

55-57

53-55

51-53

49-51

47-49

45-47