What Canada’s budget and Emissions Reduction Plan mean for Alberta’s Oil Sands: A preliminary view – with plots!

With the recent release of Canada's federal government’s budget and Emissions Reduction Plan (ERP), I thought to pull together a preliminary view of the implications for Alberta’s oil sands, piecing together the many moving parts and sketching what present policy could mean for GHG emissions and output. This is intended to complement my op-ed in this past Monday's Globe & Mail.

Four main takeaways:

1. The substantial scale of the required reductions in oil sands emissions over the next decade should not be understated – even if output grows at the slower pace projected in the ERP forecasts, emissions reductions in the ERP exceed plans presently announced by oil sands producers;
2. Reducing emissions while expanding production will require a 40% reduction in emission intensity across all current facilities and any new production to achieve an emission intensity of roughly 20 kg CO2e per barrel – well below that of any current oil sands facility;
3. Carbon capture, use and storage (CCUS) projects with an aggregate of more than 60 MT per year sequestration capacity are presently proposed in Alberta, and the various incentives (the budget’s Investment Tax Credit in addition to the carbon price and substantial credit value under the upcoming Clean Fuel Standard) provide a large push for CCUS build-out; and
4. Present projections indicate that available takeaway capacity (i.e., pipelines and rail) will be sufficient for oil production from Western Canada.

ERP's Implications for Oil Sands Emissions and Output

In the ERP (as well as a complementary set of projections published days later), Environment and Climate Change Canada (ECCC) helpfully details many of the assumptions and industry/subsector-level projections underlying its forecasts for Canada’s emissions out to 2030 (some of us had been pushing for this since the government released its December 2020 “Healthy Environment/Economy” plan). 

The ERP's “bottom-up” scenario explains how the federal government plans to bring GHGs down to its 2030 target and features particular detail on the oil sands – including, for the first time, the federal assumptions about future oil production.

In the ERP's bottom-up scenario, oil sands annual emissions would fall from 84 megatonnes (MT) in 2019 (based on ECCC’s most recent GHG Inventory[1]) to 55 MT by 2030 (see Table 6.7 on page 220 of the ERP). However, this scenario also has oil sands production rising by 21% from 2020 to 2030 – by approximately 640 thousand barrels per day (kbpd) from 2,984 kbpd in 2020 to 3,623 kbpd in 2030 (see Table 6.9 on page 221 in the ERP).

Figure 1 below illustrates what this reduction entails, including the break-down of the 29 MT reduction projected in the ERP relative to present emissions across mining, in-situ and upgrading in the oil sands.

Figure 1: Oil Sands GHGs under ERP and Oil Sands Pathways to Net Zero

It’s worthwhile noting that, as depicted as "Counterfactual emissions from added production" in Figure 1, if the new output by 2030 assumed in the ERP was to enter production at the oil sands’ present average emission intensity (EI), oil sands production would be emitting another 17 MT annually by 2030 – and exceeding the 100 MT mark. Indeed, even if new output from the oil sands entered production at the respectively lowest present EI for mining (Muskeg & Jackpine, which, as further detailed below, I estimate as 34 kg/barrel in 2019) and for in-situ (Cenovus’ Christina Lake, estimated at 48 kg/barrel) roughly 11 MT would be added to oil sands annual GHGs.

Figure 1 also shows the plans announced in November 2021 by the Oil Sands Pathways to Net Zero (OSP), a consortium of producers responsible for the majority of oil sands production. The OSP plans for 22 MT of reductions relative to these producers’ 2020 emissions in the first phase from 2020 to 2030 (see page 9 of “The Pathways Vision” deck) – split between 8.5 MT through CCUS and 13.5 of other improvements (e.g., improved processes, electrification and fuel substitution, energy efficiency).

As shown in Figure 2 (along with the 2019 emissions of each facility from ECCC’s Greenhouse Gas Reporting Program and the total for each OSP member), the OSP plan is for further phases of reductions over the subsequent two decades to achieve net zero by 2050.

Figure 2: OSP's "Pathways Vision" and 2019 emissions of oil sands facilities

ERP's Implications for Oil Sands Emission Intensity

Looking out to 2030, it’s worthwhile to consider what these reductions will mean in emission intensity for the oil sands overall and for each facility.

As illustrated in Figure 3, emission intensity (i.e., GHGs per barrel of oil produced) is not uniform across facilities – differing by extraction/processing technology and subsurface geology.  Figure 3 shows the estimated emission intensity (EI) in 2019 of each oil sands facility, calculated based on the emissions reported to ECCC’s Greenhouse Gas Reporting Program (GHGRP) and the bitumen output published by the Alberta Energy Regulator (AER) in its ST-39 and ST-53 reports.

Note that, since associated cogeneration units are often aggregated with the respective extraction facility in the facility’s reporting, the estimated EI for any facility does not adjust for emissions from cogeneration or for imported/exported power.  These estimates also do not separate upgrading emissions from facilities where these are reported together with extraction emissions.

Figure 3: 2019 emission intensity across oil sands facilities and 2030 target

Figure 3 also shows the emission intensity implications of the ERP for the oil sands overall: oil sands EI must fall from 74 kg/barrel to 42 kg/barrel to achieve the ERP's projected 55 MT emissions for the oil sands at the additional production.  Notably, as shown in Figure 3, I estimate that only a few facilities – and less than 20% of present oil sands production – would presently achieve this EI.

Therefore, Figure 4 shows the reductions in EI that would need to occur across the oil sands to reduce emissions while also increasing production by 640 kbpd. I calculate that this would require a roughly 40% reduction in emissions across existing facilities and the new 640 kbpd production would need to achieve an EI of roughly 20 kg/barrel.

Figure 4: EI implications from 2030 ERP across oil sands facilities

Outlook for Alberta's CCUS Build-out

A key question is how much of a role can CCUS play in oil sands decarbonization – as well as more widely for Alberta’s emissions reduction.

The Alberta government has recently released the results of its first request for full project proposal (RFPP) for open-access CCUS hubs in Alberta’s industrial heartland.

Combined with existing CCUS capacity (which I estimate at storage of roughly 2.9 MT/year), I estimate the planned CCUS capacity stated by the project components could yield CCUS capacity to store 60 MT/year. This based on details compiled from Alberta’s Major Projects Inventory as well as from various company websites/press releases – for example, the Alberta Carbon Grid and the Origins Project to expand the existing Alberta Carbon Trunk Line (ACTL).  

Figure 5 below shows the add-up of the potential capacity from these projects with the latest stated in-service date or each CCUS project. The following map (Figure 6) shows the location of existing and proposed CCUS projects (including CO2 pipelines), as well as 2019 GHG emissions from oil sands facilities operated by members of the Oil Sands Pathways for Net-Zero consortium and other facilities in Alberta that emitted over 50 kT CO2e in 2019. 

Note that the 60 MT/year estimate for CCUS in Alberta does not include the 8.5 MT/year CCUS capacity planned for 2030 by the Oil Sands Pathways for Net-Zero (noted above), the Meadowbrook Hub Project (for which the proponent does not appear to provide estimated storage capacity or an in-service date) or the planned 6 MT/year Rockpoint/Inter Pipeline Carbon Sequestration Hub (for which no in-service date is stated in its entry on Alberta’s Major Projects Inventory).

Figure 5: Estimated current and planned Alberta CCUS capacity

Figure 6: Alberta's large GHG emitters and CCUS projects

Incentives for CCUS Build-out

Towards accelerating this CCUS build-out, the federal government detailed its refundable Investment Tax Credit (ITC) for CCUS in its recent budget.  This proposes to provide an ITC against taxable income equal to 50% of the capital expense for investment in CCUS equipment to capture for post-combustion/process emissions (a 60% ITC applies to direct air capture projects) and 37.5% for investment in equipment for transportation, storage and use.

Based on the federal government’s estimated $8.2 billion fiscal cost for the CCUS ITC in its budget (i.e., a cumulative $2.6 billion over the next five years to 2026-27 and $1.5 billion per year thereafter to December 31, 2030 – including ¾ of the 2030-31 fiscal year), this would translate to at least $17 billion in capital spending on CCUS from now to 2030. (As brief explanation: assuming a CCUS project involves 80% of its CAPEX on capture and 20% on transport and storage, the weighted ITC inclusion would be roughly 48%; then dividing the $8.2 billion fiscal cost by the ITC’s share of capital spending should yield the government’s total expected investment by CCUS project developers.) 

As well, the ERP hints how much work ECCC expects CCUS to do: it indicates the Investment Tax Credit (ITC) for CCUS would reduce overall GHGs by 15 MT annually (see page 217 of the ERP). Note that, while the concentrated GHGs from the oil sands would likely account for a sizeable chunk of CCUS build-out, the ITC applies to CCUS from other industries and Canada-wide.

As well, if this $8.2 billion fiscal cost yields 15 MT per year in reductions by 2030 (and assuming a smooth ramp-up to those run-rate emissions reductions), the average cost of emissions reductions over the next nine years subsidized by the ITC would be around $120/tonne (i.e., the $8.2 billion fiscal cost from 2022-2030 divided by roughly 67 MT of emissions reduced from 2022-2030).  A caution is that this estimate may ignore "inframarginal" CCUS investment (i.e., that would have occurred without the subsidy) but note that the estimate also omits ongoing emissions reductions from CCUS after 2030.

As far as the federal government has so-far stated, the ITC would apply atop incentives from the carbon price under the federal “backstop” output-based pricing system (OBPS) or an accepted provincial regime – as under Alberta’s Technology Innovation and Emissions Reduction (TIER) Regulation – as well as credit-generating opportunities for CCUS under the upcoming federal Clean Fuel Standard (CFS).

Therefore, Figure 7 sketches the incentives for CCUS projects from combining the TIER carbon price, the potential value of CFS credits and the CCUS ITC. 

As an illustrative example, Figure 7 assumes a hypothetical (and relatively expensive and operating cost intensive) CCUS project with a pre-ITC cost of $200/tonne per sequestered CO2 tonne, comprised of $80/tonne in amortized CAPEX on capture, $40/tonne CAPEX on storage and $80/tonne OPEX. (Various detailed estimates of CCUS costs have been published – for example, by the International Energy Agency, the Global CCS Institute and the European Union - and these generally point to a lower cost per sequestered CO2 tonne.)

Figure 7: Combined incentives for CCUS from Alberta TIER, CFS and ITC

CCUS Incentives from TIER (and TIER Oversupply Risks)

Importantly, Alberta’s TIER and the federal OBPS involve free allocations of credits to emitters based on an EI benchmark for a given product or, as in Alberta’s TIER, the historical EI of a given facility. Therefore industrial emitters therefore only ultimately pay a portion of the "headline" carbon price. Nonetheless, output-based carbon pricing does not diminish the marginal incentive from carbon pricing for reducing a facility’s emission intensity – for example, by CCUS. 

That is, any facility operator or CCUS proponent should consider the headline carbon price (i.e., $50/tonne in 2022 and $170/tonne by 2030) as the benefit from any investment. (For interest, I explain this in a 2019 submission on Alberta’s TIER program and detail the math in Appendix A of a 2019 paper about carbon pricing for electricity under the federal OBPS, both published by the C.D. Howe Institute.)

A caveat for this incentive from carbon pricing under TIER is that there be no oversupply of TIER credits. However, with the facility-specific design of TIER, I note a significant risk of credit oversupply in the coming years, resulting from increased CCUS, the accelerated phase-out of coal power, and heightened penetration of renewables (see my earlier note on the emissions outlook for Alberta electricity).

In my 2019 submission on Alberta’s TIER program (see Appendix A from page 17 onwards), I explained how an oversupply of credits could result from the TIER applying a facility-specific benchmark for emission intensity (i.e., rather than product-specific benchmarks). 

To briefly elaborate, for all products except electricity, TIER involves a benchmark set at an annually tightening percentage of a given facility’s historical emission intensity (this is detailed in Section 8.2 of the TIER Standard for Developing Benchmarks). Facilities can also opt into a “High Performance Benchmark” (HPB) for a given product (specified in Schedule 2 to the TIER regulations).

For example, Figure 8 shows the estimated facility-specific benchmarks across oil sands facilities for 2022 (based on 2019 facility emission intensities and an 18% target emission intensity reduction for 2022 – see page of 34 of the TIER Standard), as well as the HPBs for oil sands mining and in-situ, respectively. Notably, TIER was a change from the earlier Carbon Competitiveness Incentive Regulation (CCIR) under which all facilities were subject to a product-specific benchmark.

Figure 8: EI across oil sands facilities and TIER benchmarks

Importantly, under TIER, power generation facilities still remained subject to a product-specific (i.e., rather than facility-specific) benchmark set at the “best gas” emission intensity of 370 kg CO2e per MWh.  As well, instead of this benchmark, new renewable generation facilities are assigned credits at a preferable 530 kg CO2e per MWh.

The phase-out of Alberta’s coal generation means a lower emission intensity for Alberta power, reducing power producers’ demand for TIER credits. TIER credits from greater renewable generation and increased CCUS means a sizeable increase in the overall supply of credits in coming years – and the risk of oversupply for TIER credits overall.

CCUS Incentives from CFS (and Possible CFS Revisions)

In addition to the TIER carbon pricing incentives, under the draft CFS regulations (released in December 2020 and with final regulations to be finally released this spring), CCUS projects are eligible to generate compliance credits that apply against fuel supplier and importers’ obligation for annually tightening reductions in life-cycle carbon intensity of different fuels.

Many discussions about incentives for CCUS investment ignore the likely significant incentive from the CFS, which involves credit prices up to an inflation-adjusted $300 per CO2e tonne.

ECCC’s earlier modelling in its Regulatory Impact Analysis Statement (RIAS) indicates that CFS credit prices would hit that $300/tonne cap – although that modelling involved much less CCUS than presently proposed just in Alberta.

The two panels in Figure 9 below show figures from ECCC’s RIAS for the CFS: Figure 1 from the RIAS (left panel) shows the projected year-by-year credit balance out to 2040, and Figure 5 from the RIAS shows the add-up of the estimates of credits by compliance category. Note that CCUS falls within “Actions along the lifecycle”, which ECCC estimates would contribute 7.2 million credits (equivalent to 7.2 MT) in 2030.

Figure 9: Estimates for CFS credit supply/demand in Dec. 2020 RIAS

Notably, the 7.2 MT estimate for CFS credits in 2030 from the “actions along the lifecycle” compliance category (which includes also other activities like methane reduction and refinery improvements) in the RIAS is significantly less than the 60 MT capacity of planned CCUS projects in Alberta (see Figure 5) and the recent federal estimate of Canada-wide CCUS capacity of 15 MT per year by 2030 (see page 217 of the ERP).

Nonetheless, at least from its earlier modelling, ECCC’s estimates imply that prices for CFS credits would be at the inflation-adjusted $300/tonne price-cap for its Compliance Credit Clearance Mechanism.  This is implied because ECCC anticipates that significant credits for fuel suppliers to comply with the CFS will come from the Compliance Fund, from which credits would cost an inflation-adjusted $350/tonne. That is, a fuel supplier or importer wouldn’t resort to the more expensive Fund if other CFS credits were available.

Figure 10 depicts these supply/demand economics, and the following table provides ECCC’s estimates of CFS credits in 2030 from the December 2020 RIAS.

An admitted open question – and source of uncertainty for CCUS investment – is whether ECCC may somehow tweak the final CFS regulations (likely to be published in the coming months) in consideration of various CCUS projects being planned – and supported by the ITC.

Figure 10: Illustration of supply/demand equilibrium for CFS credits

ERP Implications for Sufficiency of WCSB Takeaway

Finally, what will the federal Emissions Reduction Plan (ERP) mean for the sufficiency of takeaway capacity from the Western Canadian Sedimentary Basin (WCSB)? 

Based on an earlier graph for the C.D. Howe Institute, Figure 11 provides an updated view of how the federal government’s projection for oil production in the ERP (noting this is a Canada-wide estimate and excludes C5 and Condensates) compares with the prospective takeaway capacity for WCSB oil production. 

Figure 11: Historical and projected WCSB oil production and takeaway

For reference, I also include the latest forecasts for Canadian oil production by the International Energy Agency (IEA) and the Canadian Energy Regulator (CER). 

For the CER, this shows both its “Current Policy” and “Evolving Policy” scenarios from the latest 2021 Canada Energy Futures report. For the IEA, this shows its projection for Canadian oil production under each of the “Stated Policies Scenario” and the “Announced Policy Scenario” in the IEA’s latest World Energy Outlook (WEO) report, published in October 2021. Note that, although the IEA’s 2021 WEO includes a “Sustainable Development Scenario” (SDS) and a Net-Zero Emissions (NZE) scenario, neither of these scenarios is detailed at the country-level (the SDS is only regional).

Many commentators have pressed for the Keystone XL (KXL) project to provide market access and optionality between markets for WCSB supply (and I recently argued that the Biden administration should reconsider the project in the face of energy security challenges for Western democracies). 

Nonetheless, even without KXL’s takeaway capacity, the outlook indicates sufficient overall takeaway capacity for WCSB oil production under the ERP forecast, as well as under the IEA’s scenarios or the CER’s “Evolving Policy” outlook.

[1] Throughout this note, the analysis refers to data for the 2019 year from ECCC's GHG Inventory and GHG Reporting Program (for large emitting facilities). ECCC published an update to these datasets last Thursday (April 14, 2022) which includes data for the 2020 year. However, although noting that Alberta's government curtailed oil production during 2019, I nonetheless use the 2019 data for consistency with the ERP and given the impact of the COVID-19 pandemic on production during 2020.