November 1, 2023

Letter & Submission to Minister Guilbeault on the Draft Clean Electricity Regulations

November 1, 2023

Hon. Steven Guilbeault
Minister of Environment and Climate Change Canada

229 Wellington Street
Ottawa, Ontario, K1A 0A6

Dear Minister Guilbeault,

We are pleased to comment on the Ministry of Environment and Climate Change Canada’s (ECCC) draft Clean Electricity Regulations (CER). The Business Council of Alberta (BCA) welcomes the opportunity to discuss this policy’s overarching goal—namely, to achieve a low-carbon grid by 2035.

The BCA is a non-partisan, non-profit organization composed of the chief executives and leading entrepreneurs of Alberta’s largest enterprises. Our members represent the majority of Alberta’s private sector investment, job creation, exports, and research and development. We are dedicated to building a better and more prosperous Alberta within a strong Canada.

BCA and its membership recognize deep emissions reductions in the electricity sector are a critical step toward Canada achieving its 2050 net zero target, especially as more segments of the economy electrify and international capital increasingly flows toward carbon-competitive jurisdictions.

That said, we are concerned that the draft regulations will not strike the right balance between a clean grid on the one hand, and a reliable and affordable one on the other. Decarbonization efforts cannot, and should not, compromise affordability and reliability in the pursuit of a net zero grid. We are concerned that the regulation, as currently proposed, will do exactly that—especially in provinces like Alberta, Saskatchewan, and Nova Scotia.

Moreover, as we noted in a recent op-ed, the provinces are at different distances from the goal line when it comes to CER compliance. Provinces like Quebec, with an abundance of hydroelectricity, are already 99% non-emitting. By fate of geography, Alberta does not have the same hydro resources available to it. We are blessed with abundant wind and solar potential but have only natural gas available as dispatchable backup. As such, only 14% of Alberta’s grid is non-emitting. It is not practical or reasonable to expect some provinces to close such a large gap while others have so much less to do.

Alberta is committed to achieving a net zero electricity grid but cannot do so within the timelines set out by the CER. We urge the federal government to extend the compliance window to 2050 to allow all provinces the time they need to meet that objective.

In that context, we have appended to this letter our submission on the draft Clean Electricity Regulations. We highlight a series of concerns with the draft, some of which are broad and high-level, while others are more specific to the technical components of the CER itself.

Ultimately, we believe that the CER’s one-size-fits-all approach is incapable of preserving an affordable and reliable grid while pursuing clean power within the proposed timeline as currently designed. In that context, we offer in our submission several recommendations for improvement, while also noting that even if fully implemented, these would not completely assuage our concerns in their entirety.

Thank you for the opportunity to provide input on the draft regulations. We look forward to working collaboratively with the Ministry to craft policy that drives down emissions in Alberta’s electricity sector while preserving the province’s economic competitiveness.


Adam Legge

Cc: Hon. Jonathan Wilkinson, Minister of Energy and Natural Resources

        Jean-François Tremblay, Deputy Minister of Environment and Climate Change

        Michael Vandergrift, Deputy Minister of Natural Resources

        Paul Halucha, Deputy Secretary to the Cabinet (Clean Growth)

        Jamie Kippen, Chief of Staff, Environment and Climate Change

        Claire Seaborn, Chief of Staff, Energy and Natural Resources

        Kyle Harrietha, Deputy Chief of Staff, Energy and Natural Resources

Appendix: Official submission of the Business Council of Alberta in response to the proposed Clean Electricity Regulations in the Canada Gazette, Part I, Volume 157


For most of Canada’s history, two pillars have guided the electricity sector’s buildout across the provinces: affordability and reliability. These continue to be vital pillars for Canada’s electricity systems—all consumers, including businesses, rely on affordable, on-demand electricity. Historically, this two-pillar framework has meant that each province’s geographical, technological, and natural resource availability constraints have determined the characteristics of their grid.

In recent years, however, society has grown to expect a third major pillar alongside the other two: cleanliness. In large part, clean electricity is tied to having a low emissions profile. This relatively new, additional, pillar has been easier to incorporate in provinces already producing affordable and reliable low-emitting power. For provinces like Alberta without the same natural resource endowment and geographic advantages as provinces like British Columbia, Manitoba, and Quebec, the addition of the cleanliness pillar has necessitated, and will continue to necessitate, a major transformation to the basic infrastructure dominating the power production, transmission, and distribution landscape.

Without careful consideration and pacing, the addition of the cleanliness pillar can clash with the other pillars, creating unintended, damaging consequences. During the transition, getting the three-pillar balance right matters.

Elements of the draft CER suggest that ECCC is aware of, and has attempted to reflect, some of the differing regional impacts that would result from the addition of this third pillar. The regulations include several provisions that represent positive steps toward making compliance in Alberta possible. Among them are limited performance standard exemptions for peaking units and in emergency situations, and some flexibility for carbon capture and storage (CCS) technology development timeframes.

Despite this flexibility, we still have concerns that, on the proposed timeline, the CER will be cost-prohibitive for consumers and businesses; will jeopardize grid reliability; and will disproportionately harm economic competitiveness in provinces like Alberta, Saskatchewan, and Nova Scotia. A one-size-fits-all national policy for decarbonizing the electricity grid will have limited impacts on already-low-emitting provinces like BC, Quebec, and Manitoba. The same is not true in Alberta. As presently designed, the CER is not the best path forward for achieving deep emissions reductions while also preserving affordability and economic competitiveness in Alberta. To achieve the CER’s policy goals without creating large regional cost and competitiveness disparities, more flexibility within the regulation is needed; and additional supports are required to ensure that provinces currently relying on fossil fuel electricity generation are not placed at a competitive disadvantage relative to their peers across Canada.

11 Considerations when Finalizing the CER

The federal government will need to incorporate the 11 considerations below to draft a workable CER for Alberta. These are organized into two broad categories: (A) overarching considerations; and (B) specific considerations with the text of the draft regulations.

It cannot be overstated that action on our specific concerns within the text of the draft CER will not be enough to ensure an effective regulation that works for Alberta. We believe that a CER can work across Canada, but not without taking significant steps to address our broad, overarching concerns.  

(A) Overarching Considerations

1. The Regulatory Impact Assessment Statement assumptions are unrealistic; lack granularity and transparency; and underestimate the costs imposed on Alberta businesses and consumers

Designing a regulation that accomplishes its policy goals at the lowest cost to consumers is imperative, as is understanding the regional distribution of the costs of compliance. As it is currently drafted, several assumptions within the Regulatory Impact Analysis Statement (RIAS) and the cost-benefit analysis (CBA) raise questions about the modeling’s accuracy and whether the regulatory design is built on a realistic foundation. Consequently, these concerns impede our ability, as well as that of our members, to analyse and provide constructive comment on the policy’s design.

First, the CER’s regulatory impact cannot be studied in isolation from other recent policy action. The last several years have seen significant changes in the regulation of greenhouse gases. Since the introduction of a carbon market coinciding with the price on greenhouse gas emissions, the Clean Fuel Regulation has layered on an entirely separate carbon market; and several different investment tax credit and regulatory measures have also created other sets of technology-specific economic incentives for businesses to consider.

The policy environment is unstable, and regulatory uncertainty has not been improved by introducing the CER. There has been no indication from the federal government about how all these policies work together, nor how they will impact the economics of capital-intensive projects in the electricity sector. The modeling simplicity and certainty provided by the carbon price have been undermined by the layering of these additional policies. And in the absence of the government understanding for itself how the cumulative policy environment works, businesses are left without the clarity they will need to invest at the speed and scale the RIAS assumes they will.

Second, many of the modeling assumptions are based on unrealistically optimal conditions at a national level. System operators model grid reliability and affordability according to worst case scenarios because, when grid conditions inevitably deteriorate, they need a plan to keep power supply meeting demand at an affordable price. This system-level modeling must be conducted at the provincial grid level, not by using national averages—and definitely not by using the optimal conditions assumed in the RIAS. For example, the modeling assumes the perfect availability of biogas; completely funded and available carbon capture technologies; and a perfectly elastic supply of labour, among several other troubling optimal conditions. These unrealistic assumptions cannot form the foundation for the development of a sound policy design.

Third, and related to unrealistic optimal assumptions, the CBA utilizes a discount rate of 2%, which, according to the Treasury Board’s own guidelines, is below the lower bound discount rate for social discount rates, and is well below the standard 7% rate. This low rate ensures that the costs associated with the CER are severely understated.

Fourth, the modeling does not incorporate the buildout of the intra-provincial transmission and distribution systems that will be required. The CER’s CBA assumes that new generation will use existing intra-provincial transmission lines. However, intra-provincial transmission lines will need to be overbuilt in provinces like Alberta because of wind and solar power’s lower capacity factors and their distance from population centres. And, while they will need to be expanded as load forecasts grow regardless of the CER, the distribution network buildout required in the future will be an expensive endeavour—especially when considering demand tied to other federal policies like EV mandates and the proposed Green Buildings Strategy.

Fifth, the CER’s modelling assumes that provincial grid interconnectivity will be a key factor in reducing the disparity in compliance burdens across the country. However, vast differences between Alberta’s, BC’s, and Saskatchewan’s current electricity market designs have created barriers to achieving this goal. While limited interprovincial grid interconnectivity already exists, the flow of power remains below these interties’ rated capacity. While Alberta has acknowledged its strategic interest in getting these lines running at their rated capacity, there has been little movement to increase capacity beyond this amount despite federal efforts. And yet, CER modeling suggests Alberta will need an additional 2,400 MW of intertie capacity added at an anticipated capital cost of $1.65 billion dollars, and the province would need to import power at a $16.3 billion cost between 2024 and 2050.

Expanding interprovincial interties will take a lot more federal support to help overcome the market and institutional barriers standing in the way. As power demand forecasts have rapidly expanded—including in BC, where the province’s hydropower could theoretically support a renewable power buildout in Alberta—the two provinces have focused on meeting their own internal load growth through domestic generation buildout rather than with two-way power flow (imports and exports) from expanded interprovincial transmission in mind.

And finally, the modeling does not have the level of granularity required for Alberta’s electricity sector to comment on whether the policy is built off realistic assumptions, nor are the CBA’s net-present value calculations conducted on a province-by-province basis. Accordingly, our electricity sector members do not have the necessary regional-level information needed to analyze the regulations’ design and provide the constructive feedback that will make this policy work. They note that the modeling was not properly vetted by them before publication, and that the few details that have been made public do not inspire confidence in the real-world applicability of the modeling’s assumptions. More transparency is needed.

2. The CER is a one-size-fits-all policy in a country with regional compliance limitations

The CER will dramatically shift the economic competitiveness balance within Canada.  Provinces without the legacy nuclear or hydro capacity needed to support an emissions-free grid—Alberta, Saskatchewan, and Nova Scotia in particular—will face heavy compliance and abatement costs, while provinces like British Columbia, Manitoba, and Quebec will be relatively unaffected.

Alberta in particular will be hit hard. The province has, by far, the largest electricity sector emissions profile to decarbonize and no viable emissions-free dispatchable options—at least none that can be installed in time to meet CER timelines. Put simply, Alberta has no large rivers to dam and no existing nuclear facilities to expand; absent these, natural gas will need to continue to back up wind and solar expansion to ensure grid reliability. As such, the costs imposed by the CER to maintain grid reliability will disproportionately fall on Alberta consumers and businesses compared to elsewhere, thereby impacting affordability and competitiveness relative to other provinces.

This wide range in imposed costs across the provinces means federal financial and policy support for decarbonization should disproportionately flow to the areas most burdened by the regulations. As is, Canada’s policy supports remain inadequate to attract the capital investment needed to meet the CER’s goals. Many of the incentives available in the United States’s Inflation Reduction Act, for example, present a better business case to Alberta’s power suppliers than Canada’s supports, meaning the capital will flow to where it makes the most sense.

3. The CER treats variable power as a substitute for dispatchable power rather than as a complement

Alberta’s unique energy-only market has led to an explosion of renewable power investment in recent years. However, this explosion has only been possible because dispatchable power—predominantly natural gas—has provided the backup power necessary to smooth out the intermittency of renewables. In other words, it is in large part because of natural gas power that Alberta’s wind and solar resources are a good addition to a reliable grid. The two are complements, not substitutes.

Moreover, flexibility in the regulation is required because there is no commercially viable and technologically ready alternative to natural gas as a backup for wind and solar in Alberta by 2035. Hydro and nuclear power are not feasible. As noted above, the use and expansion of inter-provincial interties face barriers. And battery and other long-term storage technologies simply are not ready yet. Yes, more can be done to design the grid so that variable renewable power sources can be better integrated into a reliable grid design. But until the technology is ready and the regulatory changes are made, natural gas is the best and only large-scale option available in Alberta to enable the continued growth of wind and solar—especially since the penetration of renewables into the grid above a certain threshold will necessitate increased grid complexity and, in turn, will increase costs given the backup technologies available.

4. The buildout required to comply with the regulations is infeasible in the given timeframe

For Alberta to comply with the proposed regulations, the province will require an infrastructure buildout at a pace and scale never before seen. However, there are significant barriers that will prevent this from happening.

First, Canada’s regulatory review and permitting processes are long, costly, and unpredictable. The infrastructure that Alberta companies are being asked to build will require federal, provincial, and municipal approvals—sometimes from multiple jurisdictions. Simply put, it can’t take the better part of a decade for a project to clear regulatory hurdles. As processes stand, the volume of projects that Alberta must build to support the CER’s climate ambitions couldn’t get approved, let alone built, in time to meet the 2035 timeline. All levels of government will need to be committed to hastening and aligning review processes.

Second, businesses require years to make capital allocation decisions and develop project plans of the size and scale required to meet the CER’s goals. Many of the projects that must be developed—like pumped hydro, CCS, and small modular nuclear reactors—are expensive and must be carefully costed, designed, engineered, and executed. Moreover, procurement of many of the critical materials needed for building out the grid have been difficult to come by within a reasonable timeframe in recent years. Businesses must do their due diligence to ensure projects will be economical and that they represent the best avenue for capital deployment. And as the cost of capital rises and low carbon investment incentives in the US outcompete those in Canada, capital is not guaranteed to flow to Alberta without significant increases in power prices to support it.

Third, Alberta’s provincial regulatory framework will likely require changes in response to the requirements the CER will place on Alberta power providers. Regardless of the merits of these changes, they will take years to make—just as it has taken years to design, analyze, circulate, and receive feedback on the CER. Alberta companies will not be able to pursue the policy objectives of the CER until the provincial ground rules in response to this policy are in place, thereby limiting their timeframe on the necessary infrastructure buildout. These challenges do not exist to nearly the same degree in provinces with a crown corporation monopoly in place.

And finally, the sheer volume of projects that will be needed will require a sizeable skilled labour force ready to work. Businesses are struggling to find skilled trades workers and general labourers as is. A surge in project development will exacerbate this challenge, dramatically increase costs, and hold back the speed at which projects can be built. For instance, there were 10% fewer welders in Canada in 2021 than in 2016, and the ongoing wave of retirements will not be matched by the number of new apprentices entering the field.

5. CER compliance is contingent on the commercial viability and scalability of early-stage or unscalable technologies

Alberta geography and weather do not provide the province with the natural resource endowment needed to build affordable and reliable baseload power. As such, Alberta’s future grid will require large investments into technologies like battery storage, pumped storage hydropower, hydrogen conversion, small modular nuclear reactors, and (CCS) to help provide baseload power; and needed dispatchable power to smooth out intermittent renewable resources that Alberta does have in excess—wind and solar.

However, many of these technology options face enormous economical scalability and technological readiness challenges within the CER’s proposed timeframe. This creates significant uncertainty for grid reliability and power affordability, and ultimately risks capital misallocation for the sake of meeting premature regulatory requirements. Unless there are technological breakthroughs capable of delivering dispatchable options which can meet the CER requirement at an economically scalable level within just a few years; and until Canada has a supply of nuclear power project planners capable of developing novel technological solutions en masse, natural gas remains the best option in Alberta to support the scale up of renewables while protecting an affordable, reliable grid as lower carbon alternatives continue to develop.

(B) Specific Considerations

In addition to the general issues outlined above, BCA members have identified several specific concerns within the regulations as presently drafted. These include the following:

6. The performance standard for carbon capture is currently unachievable with abated natural gas combined cycle

Alberta will need to equip its existing and future baseload and peaking natural gas units with CCS technology in order to meet expanding electricity demand while also complying with the CER. However, existing CCS technology cannot meet the 95% capture rates required (30 t/GWh) by the CER in the near- to mid-term.

While industry welcomes the government’s effort to build-in a 40 t/GWh performance standard for a limited period, existing CCS technology is only capable of around an 80-85% capture rate for natural gas combined cycle units—still not enough to meet the more flexible standard. While 95% may be achievable in optimal testing conditions, real world conditions ensure this optimal level will not be met. To date, we have not seen a large scale combined cycle gas turbine plant operate with CCS that captures 95% of emissions. BCA members report that even the CCS manufacturers claiming these optimal capture rates will not sign a contract with a power provider guaranteeing this level of performance in the field.

Until the technology improves and is proven in the field, companies will not deploy hundreds of millions of dollars to install CCS that is not guaranteed to comply with federal regulations. And, by the time the technology has proven its ability to reach 95% capture rates, years’ worth of baseload and peaking investment will have been foregone and CER timelines missed—and grid reliability will likely be impacted in the process. As such, the performance standard needs to be made more flexible to reflect the real-world technological capabilities of CCS at the time a unit comes online. Until otherwise proven in the field, this means an emissions intensity performance standard closer to 80%—not 95%.

7. The draft regulations lack compliance flexibility options

Alberta’s power providers are eager to continue investing in the research, development, and eventual deployment of low-carbon baseload and storage solutions. Until these technologies are commercially viable and scalable, however, criminal liability under the Canadian Environmental Protection Act, 1999 poses too great of a risk for Alberta power companies to experiment with unproven technologies within the CER’s timeframe. Unlike in many other provinces, this liability will land on private companies rather than a provincial crown corporation. As drafted, the CER does not provide the compliance flexibility options needed to de-risk criminal liability and promote low-carbon tech experimentation and deployment while meeting the desired performance standard system-wide.

Furthermore, the draft regulations have lost the concept of ‘net’ emissions reductions and, in doing so, will disincentivize investment into emerging decarbonization technologies. For instance, direct air capture (DAC) technologies remove emissions from the atmosphere that can be sold as credits to offset power generation emissions on a one-to-one basis. By removing the concept of ‘net’ emissions reductions, the draft CER is, perhaps unintentionally, also removing incentive to invest in technologies like DAC.

These problems could be solved by returning the concept of ‘net’ emissions reductions to the policy and introducing compliance flexibility through verified carbon offset purchases or by allowing the aggregation of power generation units.

8. The treatment of cogeneration could lead to unintended environmental and affordability consequences

The scale of Alberta’s buildout challenge could be further compounded by unintended consequences of the CER on the supply of industrial “behind-the-fence” power to the grid, which is provided predominantly by cogeneration units. As a byproduct of on-site heat/steam generation, many industries in Alberta sell excess electricity into the grid. This “behind-the-fence” power currently provides 29% of Alberta’s internal load, and this share is rising as businesses in Alberta successfully scale up.

As currently drafted, the CER would apply to “behind-the-fence” industrial generation if those units are net exporters to the grid in a given year. This power provides grid stability and, as such, the CER needs to avoid creating incentives that may undermine this stability. Emissions from cogeneration are already captured under existing carbon pricing mechanisms. As such, existing cogeneration assets that are already in operation should be deemed as being compliant with the CER.

9. Exemptions for peaker units impact their commercial viability and undermine buildout of renewables

The cost of running a grid is not merely determined by the price of producing a marginal unit of power; rather, there are very real costs associated with purchasing and maintaining assets even if they are not producing power. While BCA’s members recognize the federal government’s effort to introduce flexibility for peaker units, the 450-hour cap together with the 150 kt/year emissions cap will be wholly insufficient to meet demand surges—especially during an extended Alberta cold snap.

Despite what many people may believe, Alberta’s existing natural gas combined cycle (NGCC) units simply cannot transition to function as peaker units as more renewables come online—this is not the way NGCC technology works. As such, new peaker unit investments will be required. But with the CER’s proposed annual hours and emissions caps, the economics of operating a peaker unit are challenging; it will be nearly impossible to secure investment for assets that are operating for such short periods of time without substantially driving up the price of power for businesses and everyday Albertans.

To these ends, we suggest that the CER align with elements of the United States Environmental Protection Agency’s (EPA) proposed rules for low-carbon electricity generation. In those rules, the EPA proposes establishing different tiers of emissions intensity performance standards for a new or reconstructed fossil fuel-fired generation unit depending on the frequency at which it is used—i.e., its capacity factor. Higher capacity factor units (i.e., those providing power with more regularity than peaker units do) have performance standard levels consistent with emissions abatement through CCS or fuel switching. But for units with a capacity factor of less than 20%, like peakers, the EPA’s proposed emissions performance standard aligns with the use of unabated natural gas. Instead of the CER’s proposed annual hours and emissions caps, a rule like the EPA’s better recognizes the economics of building and operating a new peaker unit, thereby better supporting the buildout of renewables and their continued penetration into the grid.

10. Emergency situation exemptions, as drafted, undermine the expertise of provincial balancing authorities and accepted North American standards

While we support the exemption of units from the emissions performance standard during valid emergency situations, requiring the federal minister’s permission does not respect the expertise of the provinces’ independent system operators. Operating the grid is ultimately a provincial responsibility; as such, each provincial grid’s balancing authority has the in-house expertise necessary to make decisions that ensure electricity supply is balanced with demand.

The North American Electric Reliability Corporation (NERC) already defines emergency system alert processes according to three Energy Emergency Alert (EEA) levels. Rather than requiring further federal oversight about what constitutes an emergency situation, the CER should recognize the validity of an emergency situation if a provincial balancing authority declares a NERC level 1, 2, or 3 EEA.

11. The end-of-prescribed-life provision is too short, and the commissioning deadline does not respect capital deployment schedules already underway

As currently drafted, the CER’s end-of-prescribed life (EOPL) provision is set at 20-years post-commissioning (if commissioned before 2025), or 2035—whichever comes later. However, the proposed 20-year provision is not long enough to amortize existing units; and does not make sense given the lifespan of the new natural gas facilities that are scheduled to come online prior to 2025.

Furthermore, the January 1, 2025 unit commissioning deadline does not respect capital deployment decisions that have already been made under the best available, and definitive, information at the time. Some of these investment decisions will result in projects commissioned slightly after the existing commissioning deadline. Under typical federal regulatory design best practices, government provides a reasonable duration of time between the enactment of the regulation and the in-force dates in order to respect proponents’ investment decisions prior to the regulation being announced.

As such, the economic impact of the EOPL provision on asset owners—and, ultimately, the consumers who will end up subsidizing an artificially constrained amortization period—should be considered. Rather than an end-of-prescribed-life provision, it should be an end-of-technical-life provision post-commissioning of a unit (or by 2050, whichever comes first). Furthermore, to respect capital outlays already underway, all units commissioned prior to December 31, 2026 should fall under the end-of-technical-life provision rather than the proposed date of January 1, 2025.


Ultimately, we believe that the CER’s one-size-fits-all approach is incapable of preserving an affordable and reliable grid while pursuing clean power within the proposed timeline as currently designed.

Several significant hurdles remain before our electricity members will feel comfortable with the CER’s policy design and its ability to achieve its goals while safeguarding affordability and grid reliability. These hurdles include:

  • a lack of confidence in the RIAS and many of the assumptions therein;
  • a “one-size-fits-all” policy approach that is geared toward functionality within already low-emitting provinces;
  • a lack of commercially available, scalable, and technologically feasible substitutes available for clean baseload and dispatchable power; and
  • a series of non-CER obstacles that will, if left unaddressed, make compliance impossible within the CER’s given timeframe.

Moreover, regional equity concerns need to be addressed in tandem with the regulation’s release. Alberta consumers and businesses will face disproportionately large cost increases relative to provinces like BC, Quebec, and Manitoba. This will impact business competitiveness and slow down the economic engine needed to fund a transition to a lower-carbon grid. As such, federal dollars should be allocated to provinces in proportion to the degree that they bear the burden of the CER’s costs. While several federal supports have been introduced, many are yet to be operationalized. And key gaps remain, like a federal ITC to help spur the buildout of transmission lines in provinces that will rely on less centralized, lower capacity factor renewable power sources.

However, we believe that addressing the following deficiencies can begin to provide the policy flexibility needed for Alberta to achieve a clean, reliable grid:

  • The end-of-life-provision needs to be extended into an end-of-technical-life provision (or 2050, whichever is earliest); and the commissioning date should be moved from January 1, 2025 to December 31, 2026.
  • The performance standard needs to be made more flexible to reflect the real-world technological capabilities of CCS at the time a unit comes online. Until otherwise proven in the field, the performance standard should be set at 80%, not 95%.
  • Existing cogeneration, which is already captured under carbon pricing mechanisms, should be exempt from capture under the CER.
  • Rather than the 450-hour and 150 kt/year emission caps for peaker units, the CER should align with the US EPA’s approach to new fossil fuel-fired, low-capacity factor units—namely, allowing them to operate at or below an emissions intensity performance standard equivalent to the use of unabated natural gas.
  • The CER should consider emergency situations as valid if a provincial balancing authority declares a NERC level 1, 2, or 3 EEA.
  • Compliance options, like carbon offset credit purchases and facility aggregation, should be introduced into the CER’s policy framework.
Concluding Remarks

BCA members agree with the federal government’s goal of achieving deep decarbonization in the electricity sector. However, we are concerned that the CER as currently drafted cannot be achieved within the proposed timeline without creating undue impacts on power affordability, economic competitiveness, and grid reliability. A one-size-fits-all CER without sufficient flexibility options for provinces like Alberta does not make sense in a country with provincial power grids historically reliant on locally available resources for affordable, reliable, and secure power. 

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