Carbon Taxes and Financial Incentives for Greenhouse Gas Emissions Reductions in Alberta s Oil Sands

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1 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: ext Fax: 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 CO 2 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. Introduction 1 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 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.

2 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 CO 2. 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). 2

3 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 CO 2 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 Characteristics 3 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). 3

4 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 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 kilograms (kg) of CO 2, 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 kg of CO 2. 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 CO 2 emissions associated with in situ bitumen production are understated by approximately 10%. 4

5 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 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 average in nine of the twelve months of 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) 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 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. 5

6 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, 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. 6

7 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 modelgenerated 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 7

8 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 8

9 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 CO 2 emissions generated by SAGD operations. As noted earlier, the production of a barrel of bitumen through SAGD operations is assumed to generate kg of CO 2 emissions. At a peak daily production of 60,000 barrels per day, this represents total annual CO 2 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 CO 2 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 CO 2 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 CO 2 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 9

10 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 CO 2 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 perbarrel 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 10

11 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 CO 2 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 CO 2 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 CO 2 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 CO 2, 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 perbarrel 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 CO 2 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, 11

12 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 CO 2 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 CO 2 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 CO 2, 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 CO 2 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. 12

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 CO 2 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 CO 2 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 CO 2 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. 13

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 CO 2 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 productionrelated CO 2 emissions as a consequence of the introduction of a carbon tax. 14

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 CO 2 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 CO 2 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 CO 2 emissions linked to bitumen production. 15

16 References Alberta Finance (2012) Budget 2012 Investing in People. Fiscal Plan Economic Outlook. Minister of Finance, Edmonton, February. Alberta Royalty Review Panel (2007) Our Fair Share Report of the Alberta Royalty Review Panel: 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 ( ), Study No. 128, CERI, Calgary, March. Department of Finance, Government of Canada (2012) Jobs, Growth and Long-term Prosperity Economic Action Plan 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) ST : Alberta s Energy Reserves 2011 and Supply/Demand Outlook , ERCB, Calgary, June. Environment Canada (2011) Canada s Emissions Trends, Minister of the Environment, Ottawa, July. Government of Alberta (2007) The New Royalty Framework: 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 ( ), Study No. 118, CERI, Calgary, November. National Energy Board NEB (2011a) Short-term Canadian Natural Gas Deliverability 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): Plourde, A. (2010) On Properties of Royalty and Tax Regimes in Alberta s Oil Sands, Energy Policy 38(10): Timilsina, G.R., N. LeBlanc, T. Walden (2005) "Economic Impacts of Alberta s Oil Sands Volume I. Main Report, CERI, Calgary, August. 16

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$) ,

18 percent current Cdn $ per barrel Figure 1. Prices of WTI and Bitumen January 2000 to December 2011 WTI Bitumen Figure 2. Bitumen Price as Proportion of WTI Price January 2000 to December 2011 % bitumen/wti Average 18

19 40 Figure 3. WTI Price as a Multiple of the Alberta Price of Natural Gas January 2000 to December WTI / Natural Gas Average Figure 4. Alberta Wholesale Electricity Price as a Multiple of the Natural Gas Price January 2000 to December 2011 Electricity / Natural Gas Average 19

20 percent billions of end-2011 Cdn dollars Figure 5. Estimated Discounted Total Costs and NPVs, SAGD Total Costs NPV WTI price in real (2012) US dollars per barrel 60 Figure 6. Distribution of Estimated NPV, SAGD WTI price in real (2012) US dollars per barrel Producers Alberta Federal 20

21 percent real (2012) $(Cdn) per tonne of CO2 real, end-2011 $(Cdn) per barrel real (2012) $(Cdn) per tonne of CO2 Figure 7. Carbon Tax as Estimated Per-barrel Cost tax=50 tax=35 tax=20 tax= WTI price in real (2012) $(US) per barrel Figure 8. Carbon Tax as Share of Estimated Per-barrel Costs tax=20 tax=5 tax=50 tax= WTI price in real (2012) $(US) per barrel 21

22 percent real 2012 $(Cdn) per tonne of CO2 real, end-2011 $(Cdn) per barrel real (2012) $(Cdn) per tonne of CO2 Figure 9. Estimated Carbon Taxes Borne by SAGD Producer tax=50 tax= tax= tax= WTI price in real (2012) $(US) per barrel Figure 10. Estimated Share of Carbon Tax Borne by Producer tax=50 tax= tax=20 tax=5 WTI price in real (2012) $(US) per barrel 22