Canada: BC Greenhouse Gas Industrial Reporting And Control Act Passes Second Reading

On October 20, 2014, the Greenhouse Gas Industrial Reporting and Control Act (Bill 2) (hereinafter the Bill) was introduced, and on October 29, 2014, the Bill passed second reading in the British Columbia Legislative Assembly. The Bill, if enacted, would repeal the Greenhouse Gas Reduction (Cap and Trade) Act in its entirety as well as various elements of British Columbia's other GHG specific legislation such that all GHG compliance obligations for liquefied natural gas (LNG) facilities and coal-fired electricity generation would fall within the regime contemplated by the Bill and any resulting regulations promulgated thereunder.


The regime contemplated by the Bill is structured in a manner similar in many respects to that of Alberta's Specified Gas Emitter Regulation (SGER), in that it is an emissions intensity based system measured in annual compliance periods (although the threshold for compliance is 100,000 tonnes of carbon dioxide equivalent (CO2e) per annum under the SGER and it is anticipated to be 25,000 tonnes per annum under the Bill). GHG emissions requirements under the Bill are currently focused on only two industries, LNG production and coal-fired electricity generation, with emission intensity requirements set at 0.16 tonnes of CO2e per tonne of produced LNG for the former, and zero tonnes of CO2e for the latter, in contrast to the SGER which spans all industries and imposes an obligation to reduce emissions intensity by 12 percent of an established facility-specific baseline. As with the SGER, in addition to meeting such requirements through physical emissions abatement, the Bill's GHG emission intensity requirements can be satisfied through the application of various types of compliance units, with non-compliance potentially attracting per tonne fines and administrative penalties.

Key Elements of Compliance


The Bill contemplates a facility-specific approach to its GHG emissions intensity requirements with applicable facilities including all buildings, structures and equipment that are located on a single site, contiguous sites or adjacent sites that function as a single integrated site which is under common control of the same person. It is anticipated that operators of LNG facilities emitting over 10,000 tonnes of CO2e will be subject to reporting requirements, and such facilities emitting in excess of 25,000 tonnes of CO2e (regulated facilities) will be required to have their annual reports verified (note, this is not provided for in the Bill, but it is expected to be included in the regulations promulgated thereunder). Operators will be required to measure and retain documentation even if they are below the reporting threshold.

GHG emissions from LNG operations include all GHG emissions from the intake of gas at the facility to the point where gas departs the facility for transport. GHG emissions that are captured and stored will not be subject to a regulated facility's compliance obligations.

Compliance Units

Aside from physical abatement of GHG emissions, compliance with the Bill's GHG emissions intensity requirements can be achieved through the application of various types of compliance units, which include:

  • Funded Units – these units can be purchased by an operator of a regulated facility from the Minister by paying the prescribed amount (proposed to be $25.00/tonne of CO2e) in exchange for one unit per one tonne of CO2e (similar to technology fund credits under Alberta's SGER). It is expected that through regulations, a technology fund will be designated through which the funds received from operators from purchasing these units will be used to invest in innovative technology to reduce GHG emissions;
  • Offset Units – these units are created by the verified reduction of one tonne CO2e of GHG emissions or removal of one tonne of CO2e from the atmosphere in accordance with yet to be established government-approved protocols for emissions offset projects (similar to emissions offsets under Alberta's SGER). However, as part of the transition process, if a proponent of a project that is authorized to be approved under the Greenhouse Gas Reduction Targets Act, has, prior to the Bill coming into force, agreed to sell to the government emission offsets generated by the project, or delivered verified emission offsets to the government for 2012 or later, such the project will be accepted as if it were an emission project under the Bill;
  • Earned Credits – for each tonne of verified GHG emissions below the emissions limit, one credit will be issued to the holding account of the operator of the regulated facility (similar to emission performance credits under Alberta's SGER). An operator may use such earned credits for future use or sell them; and
  • Recognized Units – these are units that are created in a jurisdiction other than British Columbia that, pursuant to the regulations to be promulgated under the Bill, may be treated in a similar manner as an Offset Unit under the Bill.

A registry, which may or may not be administered by a government agency, will be responsible for administering unique identifiers to, and tracking, compliance units. Each operator will maintain a holding account and when the operator earns or purchases compliance units, the holding account will be credited. When compliance units are used to reduce a regulated facility's emissions limits, such compliance units will be removed from an operator's holding account and placed into a retirement account.


Enforcement of the Bill will be undertaken by conservation officers who are granted the right to inspect regulated facilities and issue monetary penalties. It is anticipated that administrative penalties for non-compliance will be twice the prescribed rate to purchase Funded Credits (i.e., $50.00 per tonne of CO2e above the emissions limit). Administrative penalties will not relieve an operator from its compliance obligation. Operators are still required to bring their emissions intensity to the prescribed limit.

Contravening the compliance obligation is also an offence under the Bill. Operators can be liable for a maximum fine of $1.5 million and/or imprisonment for a term of two years or less. Directors and officers have the potential for liability for both administrative penalties and offences under the Bill.

Issues to Consider Going Forward

While the Bill serves to illustrate a general framework for how British Columbia intends to regulate GHG emissions, much of the details will depend on the specific regulations that will follow, if the Bill is ultimately enacted. Given the similarities between the regime contemplated by the Bill and Alberta's SGER, many of the same criticisms that have been levied against the SGER may well be directed at British Columbia's GHG regime. Some of the issues that such regulations will likely address and we anticipate being of interest to stakeholders include:

  • Restrictions on Compliance Units Generally – one of the criticisms levied against Alberta's SGER is the ability for emitters to satisfy their emission intensity obligations entirely through the purchase of technology fund credits. It remains to be seen what restrictions, if any, the British Columbia regulations will impose on compliance units being used to satisfy emission intensity requirements and whether or not restrictions will be placed on the use of Funded Units in particular.
  • Recognized Units – while the Bill contemplates the prospect of emission offsets created from jurisdictions outside of British Columbia being used to meet emissions reduction requirements, the criteria for such Recognized Units and what restrictions, if any, will be placed on their use remains unknown. The fact that Recognized Units are contemplated serves as a contrast to Alberta's SGER regime, which currently does not allow any emission offsets created outside Alberta to be used in satisfying the SGER emissions intensity obligations. The extent to which Recognized Units will be allowed will have implications for emitters looking to develop a compliance strategy and may be of interest to existing and prospective emission offset project owners/developers as well as existing holders of emission offsets created in other jurisdictions as this may encourage further emission offset project development and may influence the value of such emission offsets. To the extent Recognized Units become a factor in British Columbia's GHG regime it will be interesting to see if this will have implications for inter-jurisdictional cooperation among GHG reduction regimes both across Canada and with American GHG regimes enacted at the state level.
  • LNG Incentive Program – following the introduction of the Bill, British Columbia's Ministry of Environment has issued press releases, and conducted technical information sessions that indicate an intention to introduce and administer an LNG incentive program. The program is expected to target LNG facilities that invest in technology to lower their GHG emissions between 0.23 and 0.16 tonnes of CO2e per tonne of LNG produced. Such facilities that are able to reduce their emissions to lower than 0.23 and above 0.16 tonnes of CO2e would receive a pro-rated incentive based on their actual compliance costs. The Ministry of Environment has not specified what the incentive will be or what will qualify as a "compliance cost", although it is anticipated to be a rebate or reimbursement for costs incurred by operators for the use of clean technologies that result in a reduction of GHG emissions of regulated facilities.

The Bill is not expected to come into force until late 2014 at the earliest and more likely in early 2015, and any regulations promulgated thereunder will be subject to a consultation process with First Nations and interested stakeholders which is set to commence in December 2014.

The content of this article is intended to provide a general guide to the subject matter. Specialist advice should be sought about your specific circumstances.

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Gray E, Taylor
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