The Energy Action Framework and BC’s carbon crossroads revisited

Since first starting down the pathway of climate action in 2007, the BC government has both developed policies to reduce carbon emissions domestically while simultaneously promoting a growing oil and gas export industry. These contradictions are evident in the March 2023 announcement of a new Energy Action Framework, which tries to balance the interests of the oil and gas industry with the urgent need to get the world off fossil fuels.

The Energy Action Framework (the framework) has thus far been limited to a short news release that provides little detail, but the key components are: requiring liquified natural gas (LNG) facilities in the Environmental Assessment (EA) process to pass an emissions test and have a plan to be net zero by 2030; a regulatory emissions cap for the oil and gas industry; and accelerated electrification of the economy through BC Hydro. This post fills in the details, with a look at the potentials and perils of the framework.

Key findings:

• The BC government has painted itself into a corner by promising significant emissions reductions while enabling and encouraging LNG development. The oil and gas industry is lobbying heavily to undermine the impact of the framework.
• Environmental assessment requirements for LNG are likely to use the template of the recent Cedar LNG project approval. That includes a narrow focus on achieving low emissions intensity at the LNG terminal through electrification (called “clean LNG”). However, this ignores upstream emissions from fracking and processing and downstream emissions from eventual combustion.
• New demand for BC Hydro electricity to support (and likely subsidize) the production of “clean LNG” would compete with electrification needed to reduce emissions everywhere else in the BC economy.
• A BC oil and gas emissions cap holds promise, but BC instead appears to be concentrating on achieving the cap through a new carbon pricing system for large emitters starting in 2024. If so, BC would lose the certainty associated with an actual cap and would need to continually revise the parameters to keep emissions on the right trajectory.

Emissions limits for new LNG facilities

Approved and planned LNG projects, in particular, are inconsistent with BC’s emissions target for the oil and gas sector of a 33-38% reduction in emissions relative to 2007 by 2030.

A recent report by the Pembina institute found that the two approved projects, LNG Canada Phase One and Woodfibre LNG, imply total oil and gas sector emissions in 2030 that are double the sectoral emissions target. Emissions in 2030 would be triple the target if four other projects (LNG Canada Phase Two, Fortis Tilbury Phase Two, Cedar LNG and Ksi Lisims) are approved and operational by that date. 

As noted, the framework would require individual LNG facilities, as part of the EA process, to pass an emissions test and have a credible plan to be net zero by 2030. Projects that have already passed the EA process are exempt from this requirement, including LNG Canada Phase Two, which if it goes ahead would double the 14 MT of LNG per year capacity of Phase One and use gas to power its processing (unless the BC government provides capacity and incentives to substitute electricity for gas at some future point). 

For new projects in environmental assessment, the Cedar LNG approval, released the same day as the framework, points to a formula that would pass the test. By plugging into the BC Hydro grid, the Cedar LNG facility would be (if built) among the lowest in the world in GHG intensity, adding only a relatively modest 0.25 million tonnes (Mt) of carbon dioxide (CO₂) emissions per year. The project has also committed to reaching net zero by 2050 through the purchase of carbon offsets. 

However, this is just the LNG facility itself. The environmental assessment report flags (then dismisses as out of scope) almost 1 Mt CO₂ in additional emissions from upstream fracking and processing. Even at face value, this “gold star” LNG project would yield combined upstream and LNG facility emissions, which would add about 2% to BC’s GHG inventory (totalling 59.4 million tonnes of CO₂ in 2021). Leakages of methane, a more potent greenhouse gas, have also been widely underreported and if properly counted, total upstream emissions could be even higher.

Moreover, the Cedar LNG environmental assessment is silent on the lion’s share of emissions that would enter the atmosphere after BC gas is exported. Based on standard emission factors, the planned 3 MT of LNG exported per year is equivalent to downstream emissions of 8 Mt of CO₂ per year. These emissions are ignored because, even though they come out of the ground in BC, combustion emissions would be counted in the importing country’s GHG inventory. [Note further that BC would not get any carbon credits for exporting LNG even if LNG did displace coal in the importing country; that is not how the international system works although Alberta’s premier has been making such claims.]

Even if limited to the LNG facility, a major issue is what’s in the “net” of net zero. First, the extent to which the net zero requirements permit carbon capture and storage (CCS), an expensive fantasy that will need to be subsidized by governments if it is to happen at all. Second is whether other forms of natural or technological carbon removals, i.e., offsets, will be allowed and on what terms. Finally, compliance and enforcement issues need to be clarified. If the framework says yes to a new LNG plant, but once built the  facility fails to meet its promised emission target, what kind of penalties would be put in place? For example, the penalty for emitting more than promised could simply be that a carbon price is paid on the excess. 

A BC emissions cap that is not a cap

The discussion of a BC emissions cap mirrors a concurrent federal process to develop an emissions cap for the oil and gas sector. Draft regulations for a federal “emissions cap” are under development and anticipated later this year. How these parallel developments interact in a fair and effective manner is a key question mark, as the federal government, similar to BC, has also sought to have it both ways: reducing domestic emissions while expanding fossil fuel exports.

My previous research reviewed two stylized options for an emissions cap based on a federal discussion paper released in Summer 2022: a cap-and-trade system and a sector-specific carbon price that would need to be regularly adjusted to ensure emission targets were met. For either approach, what matters is the stringency of the resulting regulatory regime, including loopholes provided to industry that could undermine meeting established targets. Note, however, that the second option is not actually a cap. 

As a provincial government (and unlike the federal government), the BC government could set limits on total production and phase out the industry in a controlled manner. The BC government, however, does not appear to be interested in capping either production or emissions. Instead, efforts will focus on a new industrial carbon pricing system. The 2023 BC Budget announced that as of April 1, 2024 large emitters will no longer have to pay the carbon tax but shift to a “made-in-B.C. output-based pricing system (OBPS), under which they will pay for emissions that exceed performance-based emissions limits.” 

Details are still to be finalized, but based on a July 2023 consultation document a BC-based facility with average emissions intensity would pay the full carbon price on only half of its emissions and could also purchase offsets (see above) for up to 30% of its bill. Offset projects would likely cost much less than the full carbon price so the effective carbon price paid by industry would be well under 50%. The OBPS will be applied differently to the oil and gas industry from the OBPS for large emitters, but both will feature increasing stringency over time resulting from a 2% per year “tightening rate” on emissions intensity.

Carbon offset markets have been plagued by fraudulent claims of emissions reductions, and as recent wildfires have demonstrated forest carbon offset projects can burn up at any time. The bar for carbon offsets has often been set too low as governments, industry and third-party companies all have strong incentives to get deals done, whether or not they actually reduce emissions.

The OBPS will be a better deal for industry as the federal carbon price backstop rises to $80 per tonne in 2024, up from $65 this year. Since 2018, BC has rebated the carbon tax paid above $30 per tonne for facilities that met a benchmark, while recycling carbon tax revenues paid by industry back into a fund for industry projects that reduce GHG emissions. In 2022, these recycled amounts were $109 million and $90 million respectively. 

Of note, LNG Canada has an agreement with the BC government that caps its carbon tax at $30 per tonne. As the national carbon price rises to $170 per tonne by 2030, this represents a growing annual subsidy to LNG Canada. 

All of this illustrates the bewildering complexity of carbon pricing and climate policies in 2023. As originally conceived, carbon prices were supposed to apply to almost all GHG emissions. This was the case when BC brought in its carbon tax in 2008 but as carbon pricing was implemented nationwide in 2018, concerns about the “competitiveness” of trade-exposed industries came to the forefront. 

At a time of climate emergency the competitiveness of the industry that is causing warming and extreme weather should not be top of mind. Nonetheless, it is not clear if new additional regulations for an emissions cap would be developed alongside the new OBPS. If BC chooses to implement the “emissions cap” solely through the OBPS, the province would lose the certainty associated with an actual cap (although there can also be major loopholes in cap-and-trade systems). The government would need to continually reassess if emissions were on the right trajectory and compensate with regular changes in the parameters of the OBPS. This risks BC missing its emission reduction targets. 

Competing demands for clean electricity 

Under the framework, a task force has been created for BC Hydro to accelerate the electrification of BC’s economy. The context for BC Hydro is its 2021 Integrated Resources Plan (IRP), which is still under review by the BC Utilities Commission (BCUC). All potential new demand for clean electricity coming from future LNG approvals would have significant impacts on BC Hydro.

BC is in an envious position relative to most North American jurisdictions due to its large base of hydropower. Hydro dams cause methane emissions during construction and initial flooding, and have had major relocation impacts on Indigenous people and settlers alike. Nonetheless, these legacy dams provide substantial generation capacity and act as batteries by storing water to run through their turbines as needed. The controversial and massively-over-budget $16-billion Site C dam, once operational, will add to BC’s future electricity production and generation capacity.

The IRP’s reference case scenario for planning purposes was updated in June 2023 in a filing with the BCUC. While the original IRP estimated an energy surplus in the medium term, the update finds that BC Hydro will need to explore various options for deeper levels of conservation (called demand side management or DSM) up to 2040. It also has an array of alternative supply options, including upgrades to the existing generation and transmission system and a $140 million call for power to support Indigenous-led projects. Another supply option is the renewal of independent power producer (IPP) contracts, a costly legacy of the Gordon Campbell Liberal government, which prohibited BC Hydro from developing new clean energy resources itself. 

This new capacity will be needed to serve anticipated demand from LNG and mining, and to a lesser extent from light industrial and commercial businesses whereas residential demand projections are unchanged. Industry has also been given priority through discounted rate structures for industrial customers and BC Hydro’s September 2021 Electrification Plan included $105 million in incentives for industry. 

This Figure shows BC Hydro’s estimates for power generation from existing hydro dams and committed supply purchases (blue bars) set against a reference case of moderately growing demand (orange line) and a high demand case of accelerated electrification of the economy and larger demand from LNG and mining (burgundy line). The green bars represent new supply needed to meet the high demand scenario, some of which would be needed to meet the reference case. Red bars potential renewal of independent power projects and purple bars the impact of conservation/demand-side management programs.

The IRP considers additional demand scenarios from the accelerated electrification of the province in order to meet BC’s 2030, 2040 and 2050 GHG targets, and another of stronger demand on the North Coast due to LNG and mining would stretch total demand even further. If BC Hydro tried to accommodate both the accelerated electrification and stronger demand from LNG and mining scenarios (the gap in the Figure between the blue bars and the burgundy line at the top), the result would be a 24% increase in supply needed by 2030 and a 50% increase by the late 2030s. 

Even these BC Hydro projections may underestimate the potential future electricity demand from “clean LNG.” As estimated by the Pembina Institute, adding four new LNG mega-projects (LNG Canada Phase Two, Tilbury Phase Two, Cedar LNG and Ksi Lisims) to existing facilities would yield a total 40,000 GWh (gigawatt hours) of demand just from the oil and gas industry by 2030, whereas BC Hydro currently generates about 60,000 GWh. 

While BC Hydro does have a range of conservation and new supply options to accommodate new demand, they are not free. Given the high costs of developing that supply and the low prices being paid by LNG plants, BC Hydro would likely end up subsidizing new LNG plants for every MWh (megawatt hour) sold. In addition are other non-carbon environmental impacts (land disturbances and impacts on endangered species, for example) associated with new electricity supply. 

Thus, it is essential that accelerating electrification of the rest of the economy should be the top priority over additional demand from LNG and the oil and gas industry. 

Not discussed in the IRP is the possibility of a wind down scenario that would phase out the oil and gas industry and thus its demand on the grid. Accounting for 5% of current demand, this power to the oil and gas industry could be available for other uses from transportation to clean manufacturing. However, the reality is that BC has aimed to get more of the oil and gas industry to use electricity to lower domestic emissions even as full life cycle emissions (largely embodied in growing exports) rise substantially.

Conclusion

At the heart of climate and energy policy, the BC government has pursued modest carbon emission reductions for the domestic economy while simultaneously seeking to expand the production and export of fracked gas as LNG. On the domestic front, BC is not even close to being on a pathway to meeting its 2030 target (40% below 2007 levels), nor does it have any plans for meeting its 2040 and 2050 targets (60% and 80% below 2007, respectively, with promises for net zero by 2050). For exports, it appears governments would rather wait for demand outside our borders to dry up (as other countries meet their Paris Agreement obligations) rather than lead a process of driving down production.

As Canada burns from coast to coast—and less than two years since BC was last ravaged by wildfires followed by massive flooding—it’s abundantly clear that we need to say no to new fossil fuel projects. Rather than just saying no, the framework aims to set the rules for agreeing to yes. By trying to accommodate LNG development, other sectors of the economy would need to pick up this emissions slack thereby making BC’s emission reduction targets even harder to achieve. 

Topics: Climate change & energy policy, Fracking & LNG