Love them or hate them, you still have to model them: Carbon taxes for an in-situ oil sands project

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Love them or hate them, you still have to model them: Carbon taxes for an in-situ oil sands project


With clients and their stakeholders relying upon our independent evaluations, it is important for us to ensure that the economic models we generate, including carbon tax projections, are both complete and valid. Oil sands facilities currently fall under the Specified Gas Emitters Regulation (SGER) with changes to the regulations anticipated for the end of 2017. While at any point in time our evaluations reflect current regulations as of the effective date of a given report, we note that sensitivities can be tremendously useful in assessing the potential impact of uncertainties and pending changes in regulation. For these reasons, we thought it timely to offer a review of the current and anticipated regulations and how they fit into a simple working economic model.

How Does It Currently Work?

Under the current rules, any new facility that falls under the SEGR, establishes a carbon equivalent baseline-intensity over the first three years of operation. Each year thereafter, the emissions allocation is set at the baseline-intensity, minus a required emission reduction, which, in turn, increases each year. Any emissions above the progressively adjusted baseline-intensity are subject to the carbon tax.

Imagine a hypothetical in-situ facility. For the first three years, the baseline-intensity was established at X tonnes CO2 equivalent per bbl of bitumen produced (CO2e/bbl). For the next year, the new adjusted baseline-intensity is set by the government at 0.97X representing the allowable emissions limit for that year, or in other words, the emissions that are not subject to carbon taxation. Note the actual adjustment is based upon the appropriate rate required by the SGER (The 3% reduction based on the 2017 requirement for a facility in the 4th year of operation). At this point, the owner of the facility has a number of options which can be undertaken individually or in combination with one another; namely, the owner can (i) reduce the emissions intensity at the facility, (ii) use carbon offset credits to cover the excess emissions or (iii) pay carbon tax on the excess emissions. 

01_intensity baseline.png

Offset credits can either come from qualifying projects, like co-generation, planting trees etc., or by beating your target in a prior year. For instance, if the owner in our example above reduced facility emissions below the limit of 0.97X, say to 0.90X of the original baseline-intensity, the facility would get a credit of the additional 0.07X that can be used as offsets in subsequent years. Credits can also be traded between facilities.

Output Based Allocation

Output based allocation (OBA) works essentially the same way but with one important difference. Instead of establishing facility specific baseline-intensities, industry will face a sector specific limit applicable to all facilities within the sector. Any facility with intensity below the sector baseline-intensity limit will receive a credit; any facility with intensity above the sector baseline-intensity limit will be subject to the carbon tax. 

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So, what is the OBA limit? For in situ oil sands projects, the OBA baseline-intensity limit is currently expected to be based upon top quartile performance; mining projects are expected to be benchmarked against the top decile. Pending formal changes to the SEGR or its potential new equivalent, the actual performance limit and how it will be calculated and temporally applied is currently unknown. This fact doesn’t, however, prevent us from modeling potential outcomes and we have accordingly devised a model with sufficient flexibility to allow for tuning adjustments once specific regulations are defined.

The move to an OBA approach standardizes the performance benchmark for the sector, resulting in added transparency when it comes to assessing carbon costs on a project-to-project basis. The approach is intended to incent carbon reduction as companies strive to achieve top quartile performance and the ideal outcome would have in situ sector progressively improving efficiency, continually decreasing the sector baseline-intensity limit. In this new paradigm, the economics of any technology that reduces SOR (infills, solvent assisted process, non-condensable gas injection, injection and flow control devices, advanced start-up strategies, etc.) will be incrementally improved given that such technology will serve to directly reduce carbon taxes or generate credits.   But even before we witness these improvements, the move to an OBA approach is clearly a victory for the companies that already have top quartile assets; these companies now compete against sector performance, instead of their own historical performance. 

Existing credits will carry over from the old system to the new OBA system but as of 2018 a company can only meet a maximum of 30% of their compliance obligation with credits.

Historical Emissions

If you know what to look for, it’s quite easy to estimate carbon intensity for in situ projects. As one might expect, most emissions come from generating steam. Plotting the historically reported emissions versus the publicly available yearly steam injection results in a linear correlation.  The outliers above the trend reflect a single project with an upgrader, whereas the outliers below the trend reflect projects with co-generation. The resulting trend fits with the theoretical natural gas requirements to generate steam.

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Bottom line – for thermal in situ oil sands projects applying SAGD and CSS technology, talking about steam oil ratio (SOR) is essentially the same as talking about CO2 emissions intensity.

What’s the Tax Rate?

The Alberta Government has officially imposed a $20/tonne price on carbon emissions for 2017, increasing to $30/tonne in 2018 and potentially thereafter increasing annually by inflation plus two percent, based on Alberta’s Climate Leadership Plan recommendations. The federal government has announced that it will impose on the provinces a minimum $10/tonne price in 2018, increasing to $50/tonne by 2022, with the requirement that provincial carbon policies achieve the equivalent of these minimums. The federal minimums for the output-based pricing systems aren’t planned to come in to effect until January 1, 2019, with the same minimum prices presented below. Presumably the federal carbon prices will also escalate or inflate over time, but if and how this may occur has not been confirmed. Both levels of governments have suggested that industry competitiveness may play a role in future carbon pricing. Here is a summary of what we know today about carbon pricing in real dollar terms:

04_Carbon Pricing_0.png

How Do We Model the Costs?

For a reserves evaluation, these are the steps to model the carbon costs:

Step 1:     Prepare a forecast for bitumen production and SOR.

Step 2:     Convert SOR directly to CO2 equivalent intensity.

Step 3:     Compare to the OBA baseline-intensity limit and calculate the credits or penalties in tonnes of CO2 equivalent

Step 4:     After application of credits, multiply the remaining emissions penalties by the carbon price.

If your facility incorporates co-generation or upgrading, the project economics are best modeled on an integrated basis with co-gen or upgrader costs handled in tandem with the in-situ facility costs.  


An Example

  • 10,000 bbl/day of bitumen
  • SOR of 3.0
  • OBA baseline-intensity limit SOR of 2.5
  • Carbon tax of $30/tonne

Using the chart of CO2 equivalent emissions versus steam injection, we can estimate approximately 0.0237 tonnes CO2 e/bbl steam.


To calculate the emissions penalty:

10,000bbl/day × 365days/year × (3.0-2.5) × 0.0237tonne/bbl × $30/tonne

= $1,297,575/year or $0.36/bbl bitumen


Additional Considerations

Over time it is expected that the OBA baseline-intensity limit will lower as industry improves technology and finds ways to reduce carbon intensity. This will be contrasted by the fact that oil sands development will eventually have to move from the thickest, best quality resource, to lower quality areas, which by their nature tend to have higher carbon intensities. Using the presented model, the evaluator may have the option of either forecasting the OBA baseline-intensity over time, or fixing the baseline-intensity at the most recent number.


In conclusion, we expect the carbon tax as outlined by the Alberta Government to be relatively easy to incorporate into any economic model by directly converting steam injection or steam oil ratio to CO2 equivalent emissions and intensity. Confirmation of future carbon pricing and the details as to how to calculate the OBA baseline-intensity limit, including how the limit will change over time, are presently anticipated to be released by the Alberta Government as an update to SEGR or new replacement regulation before the end of 2017. In the interim, there remains uncertainty as to future carbon pricing and future carbon taxation calculations. 

Please submit questions/comments to or give me a call at 403 266 9591 to discuss.  Plus, look for a future post once we have more clarity on the regulatory changes.