4. OTHER PROPOSED CHANGES

4.1. Offsets: Allowing companies to purchase offset credits to meet a portion of their emissions requirements

The basic operation of an offset credit is that a company is allowed to emit one tonne of GHGs by paying someone else to reduce their emissions by one tonne of GHGs, or to sequester one tonne of GHGs to prevent it from being released into the atmosphere. Examples of projects currently selling offset credits include those focused on reforestation and conservation, renewable energy, energy efficiency, waste and landfill management, and carbon capture and storage (CCS).^[106]

Offsets are used in GHG regulating systems around the world, including California’s Cap-and-Trade Program and the European Union’s Emissions Trading System. In Canada, offsets are a feature of the federal Output-Based Pricing System (i.e., carbon “tax”) and are proposed to be part of the new cap-and-trade system for GHG emissions from oil and gas production.

The Draft CERs published in August 2023 did not include an option for owners of fossil-fuel-fired electricity generating units to use offset credits to meet a portion of their obligations under the CERs. Operators of units that could not meet the emissions intensity standard of 30t/GWh would have to stop operating that unit (but not until 2035 when the CERs would take effect).

However, many electricity system operators and some provincial governments argued they needed more flexibility to maintain affordability and the reliability of the grid Canada transitions to a fossil fuel-free economy.

… if the electricity system bears too great a cost burden or is unable to meet growing demand reliably, it will be hindered in its ability to support economy-wide net-zero emissions by 2050. The Council … is concerned that [the Draft CER] does not provide sufficient flexibility to utilities, system operators and market participants to achieve that desired balance. … [and] calls on the federal government to consider providing substantially greater flexibility to covered entities, recognizing that such flexibility could render the CER more practicable, more affordable and more likely to enable electricity to decarbonize other sectors of the economy in the long run.^[107]

This view was echoed in the joint submission by Clean Energy Canada and the Canadian Climate Institute:

The CER is intended to incentivize the deployment of non-emitting technologies for energy generation, including abatement technologies like carbon capture. As currently drafted, however, the proposed regulations could have the opposite effect. For instance, under the current proposed regulations, a unit operator acting in good faith could make the significant investment to equip their units with carbon capture technology, only to find it falls short of the required performance standard by less than 1% (a risk which would be mitigated, but not eliminated, by changing the level of the performance standard as we discussed above). As currently drafted, the regulations would require the unit to eventually cease operation — removing the possibility of recovering the costs of the carbon capture investment. Such a risk may lead operators to forgo investment in carbon capture altogether.^[108] (emphasis added)

Clean Energy Canada and the Canadian Climate Institute went on to specifically recommend offsets:

To address this concern, the government should establish a “soft-landing” pathway, where units are required to achieve the vast majority of the performance standard through direct emission reductions but may use offsets — such as negative emissions offsets — for the remaining reductions required.^[109]

While there are some limited situations where offset credits are a good idea, the effectiveness of offsets has been discredited and the process is extremely vulnerable to abuse. Carbon offsets have been linked to human rights abuses such as Indigenous people being displaced from their lands (e.g., for reforestation and conservation projects).^[110] [111] They also facilitate “greenwashing” by allowing Canadian oil and gas companies to claim to be more climate-friendly than they actually are.^[112] 

Most importantly, carbon offset credits are extremely ineffective at actually reducing GHG emissions and the quantity of GHGs in our atmosphere. A recent academic study that is currently in the pre-publishment phase (meaning it is awaiting the completion of peer review) found that only 12% of existing carbon offset credit systems worldwide create real, permanent emissions reductions.^[113]

A paper by Cullenward, Badgley, and Chay explains why, in practice, carbon offsets rarely deliver the promised emissions reductions. Most offset projects are over-credited, non-additional, or non-permanent.^[114]

• Over-credited – The amount of the reduction of GHGs attributed to an offset project can be over-estimated through good faith errors or abuse of the system, particularly in systems without sufficient independent verification. An investigation found that more than 90% of rainforest offsets– among the most commonly used by companies – sold by the world’s leading voluntary offsets market, are “worthless phantom credits” and do not represent genuine carbon reductions.^[115] Even the most robust carbon offsets can be double-counted, particularly when the seller and purchaser are in different countries. Absent an internationally-agreed rule, both parties can and sometimes do claim the same emissions reductions.^[116]

• Non-additional – Most credited carbon offset projects take the approach of preventing new GHG emissions, rather than removing GHGs that have already been emitted from the atmosphere. These projects can only be a true offset if they prevent emissions that would have occurred if the carbon offset project did not exist. For example, not logging a forest where logging is not economically viable and probably would never occur does not decrease the amount of GHGs emitted. Similarly, offset credits should not be given for emissions reductions required by law (e.g. the forthcoming cap on emissions from oil and gas production) because these emissions reductions would have happened anyway.

• Non-permanent – For offsets that capture and store emissions, the carbon storage must be durable (i.e. permanent) or the warming effects will still occur in the future when the carbon is eventually released. However, nearly all credited carbon storage is temporary. For example, a reforestation project does not store any carbon if that forest later burns in a wildfire. CCS, if it could be shown to work at scale, has significant challenges finding geologic sites that can permanently store carbon. Liquids and gasses, “migrate through the microscopic holes and fractures that are found in even the most solid of rocks,” finding their way back to the surface and, from there, the atmosphere.^[117]

Almost every action that an emitter could pay someone else to do to reduce or sequester emissions elsewhere could be better accomplished by directly reducing emissions via a government statute or regulation, even by an extension of the carbon “tax”. There is no way around the fact that we must stop burning fossil fuels.

That said, it is understandable that electrical operators objected to the all-or-nothing approach of the Draft CERs where an electricity-generating unit would have to shut down if it exceeded the emissions intensity limit by even 1%. It could certainly have an undesired chilling effect on investment in abatement technologies if the penalty for missing the mark even slightly is so high.

Their concerns would be better addressed by changes to the regulatory design rather than introducing a complex and unreliable system of offset credits. The change already proposed to use a unit-specific emissions limit rather than an emissions intensity limit (see #1 above) should sufficiently address the issue on its own. This change would allow units that exceed the limit to continue operating at a lower capacity rather than shutting down altogether. There is no need to introduce an ineffective carbon offset credit system that would be complex to administer, vulnerable to abuse, and ineffective at actually reducing GHG emissions and the quantity of GHGs in our atmosphere.

Clean Energy Canada and the Canadian Climate Institute, who recommended including an offset mechanism, noted the potential problems such a system could entail. They stated, “If offsets are used as the compliance mechanism, the government must ensure that offsets represent real, independently verified, quantifiable, permanent, and additional negative emissions.”^[118] Each one of these terms is critical. Real. Independently verified. Quantifiable. Permanent. Additional. We agree with each of them and would also add “transparent”, as transparency in the form of public reporting will be necessary for Canadians to have confidence that the offsets system is actually delivering the promised emissions reductions.

4.1.1  Suggestions for your submissions on offsets

• Carbon offsets have been largely discredited. System operators’ concerns are better addressed by the proposed change to a unit-specific emissions limit rather than an emissions intensity limit, as this would allow units that exceed the limit to continue operating at a lower capacity rather than shutting down altogether. There is no need to introduce an offset credit system that would be complex to administer, vulnerable to abuse, and ineffective at actually reducing GHG emissions and the quantity of GHGs in our atmosphere.
• If offsets are included in the CERs, the government must develop a credible system to confirm with certainty that offset projects represent real, independently verified, quantifiable, permanent, and additional negative emissions. The percentage of a unit’s emissions limit that could be covered by offset credits should be set low, and should decrease over time to zero by 2040. For transparency, the use of offsets and the specific projects for which offset credits are purchased should be publicly reported.

4.2. Cogeneration: treat emissions from existing cogeneration units differently than emissions from other units, without explaining what that treatment would be

Under the Draft CERs published in August 2023, any electricity-generating unit with net exports to the grid (i.e. they supply more electricity to the grid than they demand from it) would have to meet the emissions intensity standard at the end of its planned life (EoPL). Cogenerating units, which produce both electricity and heat for industrial use, would be treated the same. This would mean:

• In a year when a cogeneration unit IS a net exporter to the grid, ALL of the GHG emissions from that unit would be subject to the CERs.^[119]

• In a year when a cogeneration unit IS NOT a net exporter to the grid, NONE of the GHG emissions from that unit would be subject to the CERs. However, the emissions are covered by the Output-Based Pricing System Regulations (OBPSR) or the applicable provincial or territorial carbon pricing system (i.e. the carbon “tax”).^[120]

The Public Update reported that several stakeholders noted that the “all-or-nothing” approach of the Draft CERs could create a perverse (unintended) incentive causing cogeneration facilities to stop selling electricity to the grid:

Stakeholders from multiple industries, as well as officials from Alberta and Saskatchewan, observed that the performance requirements in the proposed regulations could be difficult for most existing cogen facilities to meet. They expressed concern that these facilities might decide to stop exporting electricity to the grid in order to avoid being subject to those requirements. This would affect Alberta and Saskatchewan in particular, which depend on cogeneration for a significant portion of their generation.^[121]

Therefore, the Public Update proposes that “behind the fence” emissions from existing cogeneration facilities could be treated differently for a time-limited period, while any new cogeneration units would continue to be treated the same as other new units. “Behind the fence” is defined in the Regulatory Impact Analysis Statement accompanying the Draft CERs as, “a unit whose electricity generation capacity is suited for the industrial facility at which it is located, thus resulting in the majority of its electricity being consumed, most of the time, by the industrial facility.”^[122]

The Public Update states:

In keeping with the draft regulations, all cogeneration units would only be subject to the emissions requirements in the years they have net exports to the grid.

Under the emissions limit approach described above, it is possible to distinguish the emissions from “behind the fence” electricity from the emissions associated with electricity provided to the grid. For existing units, consideration is being given to differentiating the treatment of emissions from electricity exported to the grid from “behind the fence” generation for a time-limited period.

Consideration is also being given to treating new cogeneration units the same as all other new units.^[123]

In other words, when an existing fossil-fuel-fired unit generates electricity the majority of which is used at an industrial facility (rather than being exported to the grid) most of the time, ALL of the GHG emissions from that unit could be treated differently than emissions from other units. Since the Public Update does not explain what that differential treatment would be, it is impossible to assess the impacts of this change.

We can hazard a guess, because proposing to differentiate between “behind the fence” emissions and emissions from electricity sold to the grid provides a clue. It seems possible that for existing cogeneration units that are net exporters to the grid, the federal government is considering applying the CERs only to the portion of the emissions related to the electricity sold to the grid. That would differ from the treatment of other electricity-generating units that are net exporters, where ALL of the unit’s emissions are subject to the CERs.

If this is the case, it would be a step backward because fewer GHG emissions would be covered by the final CERs than under the proposed Draft CERs. Companies using fossil-fuel-fired units to generate electricity for industrial processes (rather than being sold to the grid) would be subject to the OBPS (i.e. carbon “tax”) but would have no incentive beyond that to invest in abatement technologies or cleaner generating units. The policy could even create a perverse incentive for companies to repurpose some dirtier units that would otherwise be forced to decommission under the CERs to a cogeneration function so they could continue to operate.

Of course we don’t know if this is what the government intends to do. We agree with Evan Pivnik of Clean Electricity Canada, who, in response to the proposal for cogeneration facilities, stated, “Flexibility is key in ensuring an effective and durable regulation. But flexibility should be balanced with the necessary stringency, and more details on the new proposal are needed to determine if the former compromises the latter.”^[124] We would go further and state that if cogeneration units are treated differently, that different treatment should be no less stringent than the treatment of other units.

However, we also question whether a change in the treatment of cogeneration facilities is needed at all.

With respect to the concern that existing cogeneration facilities might decide to stop exporting electricity to the grid in order to avoid being subject to the CERs, making the CERs less stringent (in other words, allowing more GHG emissions) is not the only possible response. There are so many other levers to incentivize cogeneration facilities to continue selling electricity to the grid while also complying with the CERs. One approach would be to make the CERs apply to all electricity generation, whether the units are net exporters to the grid or not. If there is no way to “avoid” the CERs, cogeneration facilities will continue selling electricity to the grid if it makes economic sense to do so. Provinces that rely heavily on cogeneration (i.e. Alberta, Saskatchewan) could encourage those facilities to keep providing power to the grid by increasing the price they pay for it. If they don’t wish to do so, they could instead invest in renewable sources of electricity. Or provinces could pass laws mandating cogeneration facilities to sell a portion of their electricity to the grid as a condition of being licensed to operate.

These are the kinds of choices and decisions the CERs are designed to provoke. As we get closer to 2050 and a net-zero economy, the decision cannot always be to pollute more. Transitioning away from fossil fuels means decoupling the interests of the oil and gas industry from our need for a reliable and affordable grid. The profitability of fossil fuel companies can no longer be an overriding policy consideration.

4.2.1  Suggestions for your submissions on cogeneration units

• ECCC should explain what “differential treatment” is being considered for existing cogeneration facilities and give stakeholders an opportunity to respond. Stakeholders have not been adequately consulted on this potential change to the Draft CERs.
• To ensure the CERs achieve their objective of reducing emissions from electricity generation, emissions from cogeneration units should not be treated less stringently than other units. The government should use other mechanisms to incentivize cogeneration facilities to continue selling electricity to the grid while also complying with the CERs. The government should pair those incentives with policies that support development of renewable electricity generation to facilitate the transition away from fossil fuels.

4.3. Pooling:  Allowing companies to combine the emissions limits of individual existing electricity-generating units into a pooled emissions limit

Under the Draft CERs published in August 2023, each individual electricity-generating unit would be subject to an emissions intensity limit of 30 t/GWh. No individual unit could exceed this emissions intensity, unless an exception applied (e.g. emergency).

In addition to replacing the emissions intensity limit with a unit-specific emissions limit (i.e., a maximum amount of GHG emissions per unit – see #3.3 above), the Public Update proposes that the emissions limits of individual units could be combined. This might be done for all the units owned by a given company, or for all the units across an entire jurisdiction, such as a province.

The Public Update states:

Consideration is being given to allowing responsible parties (e.g. utility, crown corporation) owning multiple existing units in the same jurisdiction to combine the emissions limits of individual existing units into a pooled emissions limit. This would enable them to operate their more efficient units above each individual unit’s (emissions) limit, compensated by less operation of less efficient units. In addition to enhancing flexibility, this may avoid the need to prescribe a time limit for peaker units, given that all emitting units would have an emission limit.

Consideration is also being given to whether and how to enable individual units to pool with other units owned or operated by different entities in the same jurisdiction.^[125]

Presumably this change is being proposed in response to calls from electricity system operators and some provincial governments for more flexibility.^[126] Clean Energy Canada and the Canadian Climate Institute also recommended more flexibility in their joint submission to the consultation on the Draft CER, although they did not recommend pooling specifically.^[127] 

Pooling emissions limits would allow operators to maintain the reliability and affordability of the grid if some electricity-generating units are offline (e.g. for maintenance), because they would be able to increase the output from other functioning units without exceeding the regulated emissions limit.

The pooling of emissions limits has some similarities to a cap-and-trade system, particularly if pooling occurs at the jurisdiction level rather than just within companies. One example of pooling across companies is the European Union’s CO₂ emission performance standards for cars and vans which came into force in 2020. “Manufacturers can group together and act jointly to meet their emissions target.”^[128] For example, the Fiat Chrysler Automobile group paid €1.8bn to buy emissions credits from Tesla in order to meet its emissions quota.^[129]

We do not object to the pooling of individual units’ emissions limits in principle because it would not increase the overall GHG emissions released into the atmosphere. Pooling would support the reliability of the electrical grid during the transition to a net-zero grid. It also makes sense given that electricity-generating units operate as a connected network (i.e. a grid) and not in isolation.

That said, we are unsure that pooling would work as described, enabling operators to, “operate their more efficient units above each individual unit’s (emissions) limit.”^[130] The emissions limit for each unit would be based on the unit running at full capacity 100% of the time (see the formula in section 3.3). It is not possible to operate a unit beyond its capacity or more than 100% of the time, regardless of whether emissions limits are pooled. For this reason, we feel the pooling of emissions limits is unnecessary, even though it is unobjectionable on a theoretical level.

In addition, the pooling system will need to be thoughtfully designed and implemented to ensure the overall emissions limits are not exceeded. Rigorous reporting and verification mechanisms would be required. To ensure the integrity of the system, this function should be done by the federal government rather than third parties who may have a vested interest (e.g. auditors who are hired by the energy companies).

If the government decides to allow pooling at the jurisdiction level, rules would have to be established for the purchase or trading of unused emissions “credits”. As with any cap-and-trade system, the risk that the total emissions limits could be exceeded increases with the complexity of the system.

Finally, given the stated objective to, “reduce GHG (i.e. CO2) emissions from emitting electricity generation beginning in 2035”, it will be important to ensure that the pooling of emissions limits is not expanded to also allow banking of unused emissions limits over time. …. For example, if a company or jurisdiction has a “good” year in which they emit fewer GHGs than their pooled emissions limit, they may be tempted to argue that the un-emitted amount should be carried forward to the next year or several years in case it is needed later (e.g., to respond to an emergency). However, the CERs already have provisions to deal with emergencies (see 4.5).

4.3.1  Suggestions for your submissions on the pooling of units

• The pooling of individual units’ emissions limits is unobjectionable because it would support reliability during the transition to a net-zero grid while not increasing the overall GHG emissions released into the atmosphere.
• To ensure that emissions limits are not exceeded, the pooling of emissions limits must be well-designed and -implemented, and subject to a robust reporting and verification system. The federal government should take on this role to ensure the integrity of the system.
• To ensure the objective to reduce GHG emissions from electricity generation is met, the pooling of emissions limits must not be expanded to also allow banking of unused emissions limits over time.