On October 20, 2014, British Columbia (B.C.) Environment Minister Mary Polak tabled the province’s first bill targeting industrial greenhouse gas (GHG) emissions, in keeping with B.C.’s political commitment to develop the liquefied natural gas (LNG) industry only if it can be done with safe development standards and satisfactory environmental protection protocols.

B.C. demonstrated its wish to control GHG emissions with the Greenhouse Gas Reduction Targets Act (British Columbia), in force since January 2008. This legislation targeted a reduction in provincial GHG emissions of at least 33% below 2007 levels by 2020, but it fell short of prescribing methods of achieving such reductions and did not impose any obligations on private sector organizations, including large industrial emitters such as LNG facilities.

The Greenhouse Gas Industrial Reporting and Control Act (Bill 2) goes much further than previous GHG emissions legislation in B.C. Taking direct aim at coal-based electricity generation facilities and LNG facilities, Bill 2 requires each of these newly regulated operations to report its GHG emissions and comply with its emissions limit.

The emissions limit for LNG facilities is 0.16 tonnes of GHG emissions for each 1 tonne of LNG produced by the operator. LNG operations are intended to include all GHG emissions from the point where gas enters a facility to the point when it is loaded onto a mode of transportation such as ship or rail car. This would appear to capture emissions from ancillary operations to the LNG plants, such as “inside the fence” natural gas-fired power generation. Arguably, the proposed legislation will set the most ambitious emissions targets in the world for LNG operations.

Entities whose operations exceed their emission limit can still comply with the proposed legislation by earning the necessary number of compliance units. Compliance units can be any combination of the following:

  • offset units, earned through the removal or reduction of GHG emissions by way of an approved emission offset project and verified by third-party verification procedures;
  • funded units, earned by payment of a prescribed amount (to be determined) to the minister per tonne of GHG emissions (which payments are intended to be applied to a technology fund used to find way to reduce GHG emissions in other economic sectors);
  • earned credits, earned by a reduction of GHG emissions lower than the emission limit in a previous compliance period and carried over into the period in which the earned credit is used; and
  • recognized units, which are units of another jurisdiction which are or are deemed to be equivalent to offset units under Bill 2. Presumably, the emission offsets generated under Alberta’s neighbouring emission offset projects will be accepted as recognized units in B.C.

Much of the proposed legislation’s mechanics are relegated to future regulations. As such, the application of Bill 2, including compliance and reporting procedures to emission offset project approval and use of the funded unit technology fund, remains to be seen.

While many of the mechanics are yet to be prescribed, Bill 2 closely mirrors Alberta’s Climate Change and Emissions Management Act (CCEMA). The CCEMA also provides an intensity-based limit on industrial GHG emissions by requiring certain industrial emitters to reduce their emissions intensity by 12% (and with an overall goal of reducing emissions to 50% of 1990 levels by 2020). The CCEMA also provides several mechanisms by which emitters can meet their targets, including:

  • emission offsets (equivalent to the offset units contemplated in Bill 2, and obtained through non-legally required approved reduction activities in Alberta);
  • fund credits (equivalent to funded units in Bill 2, and which can currently be purchased in Alberta for $15 per tonne of GHG emissions); and
  • emission performance credits (equivalent to earned credits under Bill 2).

Alberta’s emission offset projects must fit within one of numerous available emission offset project protocols, including those for biomass combustion projects and wind-powered electrical generation projects. Presumably the B.C. regulations will follow similar protocols and provide for similar third-party verification procedures. This will provide additional revenue opportunities for renewable energy generation projects in B.C., which can sell their offset units to LNG operations through a registry similar to the bilateral trading done in Alberta. The regulations yet to come are likely to track the CCEMA regulations, given that Bill 2 largely parallels the CCEMA.

However, there are several key differences between Bill 2 and the CCEMA, including the following:

  • Bill 2 will only apply to coal-fired generation and LNG operations, whereas the CCEMA applies to all facilities in Alberta which emit more than 100,000 tonnes of GHG emissions per year.
  • Bill 2 appears that it will apply to all regulated operation types immediately and going forward, whereas the CCEMA only applies to large industrial emitters after their GHG emissions exceed a certain threshold, with new facilities in that category (having less than eight years of commercial operation) enjoying a four-year graduated reduction in their emissions limits.
  • Bill 2 introduces the concept of recognized units of GHG emissions reduction earned in other jurisdictions which are equivalent to offset units generated in B.C., whereas the CCEMA does not recognize other jurisdictions and requires emissions offsets to be generated by an approved project located in Alberta.

The implications of Bill 2 are multifarious. Once passed, Bill 2 will impose GHG emissions restrictions on LNG facilities which can certainly increase the operating costs of such facilities, particularly if the funded unit price is set higher than Alberta’s $15 per tonne. However, the proposed new legislation may also temper the public’s concerns about the environmental impact of building out the LNG industry in B.C., and could contribute to political buy-in from key stakeholders concerned with the environment. Further, the recognized unit concept in Bill 2, which provides for the registration and trading of foreign offset units, may facilitate the growth of emission offset generating projects in neighbouring jurisdictions such as Alberta. Finally, Alberta’s leadership has vowed to update its GHG emissions strategies by the end of 2014 in order to facilitate stakeholder buy-in for the province’s oil sands and other large emissions projects, which may further align the Alberta and B.C. provincial approaches to emissions management.

The development of legislation in B.C. that parallels Alberta’s emissions regime may represent a unified approach by Western Canada to responsible development of natural resources and advance the West Coast’s LNG projects, which many perceive as lagging dangerously behind the competition in Australia and the United States.