A hard push to the left: Alberta’s proposed Carbon Competitiveness Regulation

Alberta’s Climate Change Advisory Panel has provided a Climate Leadership Report to the Minister recommending, among other things, that Alberta introduce a complicated Carbon Competitiveness Regulation that will cover an estimated 78 to 90% of the province’s carbon emissions with carbon pricing at $30 per tonne of carbon dioxide equivalent (tCO2e). Changes to regulation of the oil and gas, oilsands, refining, electrical generation, transportation and heating fuels sectors are at the heart of the recommendations.

Although a draft of the proposed Carbon Competitiveness Regulation has not yet been released, the Climate Leadership Report to the Minister (Report) recommends, among other things, rewarding the top quartile of large emitters and penalizing the remaining 75%, accelerating the phase out of coal power, subsidizing renewable power and reducing methane emissions.

The recommendations also largely address the elephant in the room under existing policy, namely that consumers will be required for the first time to pay a carbon levy of $30 tCO2e for the gasoline and diesel burned in their cars and for the natural gas that heats their homes and businesses. Part of the money raised will be redistributed to the poor.

The province has largely accepted the recommendations and added a legislated cap on absolute emissions from the oilsands of 100 mega tonnes (MT) per year.

The Alberta Climate Change Panel (Panel) was tasked with advising the Government of Alberta to inform the development of a comprehensive provincial climate change strategy.

Where we were

Alberta’s existing carbon pricing system only covers large emitters, which make up nearly half of Alberta’s total emissions. Specifically, the Specified Gas Emitters Regulation (SGER) is a hybrid carbon pricing system based on rewarding emissions intensity reductions. It has elements similar to both a carbon tax and a cap-and-trade system.

The SGER currently requires facilities that emit 100,000 tonnes of CO2e or more per year to reduce their emissions intensity by 12% below a historical baseline. This reduction requirement will increase under policy previously announced in June 2015 to 15% in 2016 and to 20% in 2017.

Facilities unable to meet their annual intensity target may comply by retiring emission performance credits (EPCs) purchased from other firms who have met and exceeded their emission reduction targets or which have been banked from previous years, purchasing emissions offsets, paying a carbon levy into a government-run technology fund, or by combining these three compliance mechanisms.

The price per tonne emitted above this baseline will increase under previously announced policy from $15 per tCO2e in 2015 to $20 in 2016 and to $30 in 2017.

Where we are going

Carbon Pricing of Fuels

Central to the Panel’s recommendations is creating a broad-based carbon price of $30 per tCO2e. Specifically, the proposed Carbon Competitiveness Regulation will require distributors of transportation and heating fuels to acquire and retire EPCs or offsets or make payments into a technology fund at a rate of $30 per tCO2e in recognition that emissions are created when their fuel products are combusted by their customers. On-site combustion of fuels in oil and gas operations, such as the use of fuel gas at a battery, will be subject to the same requirements as transportation and heating fuels starting January 1, 2023.

To give one a sense of this change, the Panel expects Albertans will pay an additional 7¢ per litre of gasoline and $1.68 per GJ for natural gas, comparable to current prices in BC. The Panel presented no evidence that increasing the price of fuels will dampen demand in Alberta or that actual emissions will fall due to the price increase. Emissions from flaring at oil and gas wells and facilities and emissions from landfills will also be required to acquire EPCs or offsets or to make technology fund payments at the same $30 tCO2e rate.

In June 2015 the province announced that the technology fund compliance option will rise to $30 tCO2e by 2018, and therefore $30 tCO2e will effectively be the market ceiling price for EPCs and offsets. Transportation and heating fuel distributors will undoubtedly collect these costs from their customers. The proposed treatment of emissions from transportation and heating fuels, with emission requirements imposed at the distribution level, is similar to the systems in Quebec and California and the system proposed for Ontario. 

Carbon pricing for such fuels is to be phased in starting at $20 tCO2e in 2016 and 2017 and is to reach $30 tCO2e by 2018. The Panel also recommends that the pricing increase over time in real terms and has suggested annual increases equal to the rate of inflation plus 2% as long as Alberta’s carbon price does not significantly exceed prices in comparable and competitive jurisdictions or exceed any future national carbon pricing standard.

Under the present SGER, annual payments to the technology fund averaged about $77 million over the last seven years. At a price of $30 tCO2e, the new expected revenue could exceed $3 billion per year by 2018 and $5 billion by 2030. The Panel proposes that $30 million be used to subsidize renewable energy and the balance used for energy-efficiency projects, municipal low-carbon initiatives such as public transit, new research and development and for general revenues. Rebates would also be provided to low-income consumers who spend a disproportionate share of their income on energy compared to wealthier Albertans.

Large Emitters

The Climate Change Advisory Panel has proposed that all facilities emitting more than 100,000 tCO2e per year will be allocated new emission permits in proportion to the facility’s current or historical output. The emission permits will allow a facility to emit CO2 but on the basis that each permit is equivalent to the emissions intensity from the best 25% of emitters in that industry.

For instance, an oilsands plant that produces 150,000 barrels a day will be given permits allowing it to emit CO2 for up to what the best 25% of all the 250,000 barrel-a-day oilsands facilities emit. If the oilsands plant is not in the best 25% in terms of emissions, it will have more emissions than it will have permits. In such a situation, the facility will have to either reduce its actual emissions or acquire EPCs or Alberta-generated offsets or pay into a technology fund much like it presently does under the SGER.

The top-quartile facilities may have EPCs for sale, so this new program rewards the most efficient producers, but by definition 75% of the large emitters will face a new net compliance cost if they do not change their processes or relocate to other less regulated jurisdictions.

It is also proposed that over time the allocation of permits will be reduced 1 to 2% per year to reflect energy efficiency improvements.

Large final emitters will not be covered twice, meaning they will be able to exempt emissions from transportation and heating fuels for which a carbon price has already been applied at the point of distribution from the calculation of required EPCs or offsets or technology fund payments.

Finally, it is proposed that the Carbon Competiveness Regulation will allow facilities that emit less than 100,000 tCO2e/yr to opt into the large final emitter program if they find it more advantageous to do so than paying the $30 per-tonne cost for consuming fuel.

Coal Phase Out; Renewable Phase In

The recommendations include phasing out coal-fired power production in Alberta by 2030 and replacing at least 50 to 75% of the lost power capacity with renewables. The timing will be flexible and there will be consultation with the Alberta Electric System Operator to prevent unnecessary risks to the reliability of the grid.

Presently, federal coal regulations and Alberta air quality regulations are expected to lead to the shutdown of all but six coal-fired power plants in Alberta by 2030. The Panel recommends that an output-based allocation system be put in place for all power plants based on a good-as-best-gas standard.

This standard will require power plants, including coal power plants, to meet net emission performance standards equal to the emission performance of the best gas-fired plants. Those power plants that have emissions greater than the best gas-fired plants will have to meet these limits by the retirement of EPCs or offsets or payments to the technology fund.

These costs will erode the operating margins of coal plants and cause them to produce less throughout the year. If this, together with subsidizing renewables to make them competitive, air quality regulations and federal end-of-life performance standards, does not cause operators to close their coal-fired plants or convert them to gas, then the Panel recommends that any plants still operating in 2030 be closed by regulation even if it is before the end of their useful lives.

In addition to pursuing a regulated phase-out of coal power and replace the lost capacity, the Panel recommends a clean power call whereby the government will subsidize the renewables industry by making payments to renewable power projects to achieve an increase in renewable energy capacity in the province.

A clean power call is an open, competitive request for proposals from renewable power proponents for government financial support through the government acquiring renewable energy credits (RECs) from projects under long-term contracts. An annual procurement process would allow proponents to bid for such contracts with the government awarding contracts to the projects with the lowest levels of incremental support.

It is expected the subsidy will be in the order of $25 to $35 per megawatt initially, with no guarantee it will drop. To put this in context, the current price for power in the wholesale market as of November 24, 2015, is around $12 to $20 per MW. Projects supported through such REC purchases will not be eligible for incremental revenue from the sale of offset credits or the sale of RECs in other jurisdictions.

The Report predicts that by 2030 renewables will replace between 50 and 75% of the coal generation capacity lost and will increase the overall share of renewables in Alberta’s generation mix to 30%. However, in addition to the subsidies taken from consumers at the gas pump, electricity prices due to the province’s carbon plan could increase 20% by 2030.

Other than renewables, the balance of the power lost due to shutting down coal-fired generation will have to come from natural gas-fired power plants, which makes sense given Alberta’s huge natural gas reserves and the fact that natural gas is the cleanest-burning fossil fuel. Given these attributes and the current shrinkage of Alberta’s oil and gas industry, it is unfortunate that natural gas has not been given a larger role in Alberta’s carbon plans.

A carbon price based on a good-as-best-gas standard is expected to have only a limited effect on new or existing gas plants. However, facilities that have higher heat rates or are otherwise not as efficient as the best gas plants will incur higher marginal costs.

Cogeneration

Presently, cogeneration is provided credits that approximate the emissions saved through enhanced efficiency, by comparing actual emissions from a facility with cogeneration with a calculated hypothetical level of emissions that would have occurred had heat and power been generated separately using natural gas. This will no longer be the case. The Panel recommends that facilities with cogeneration be treated the same as facilities without cogeneration. If the application of cogeneration leads to lower total emissions, then the facility obtains that benefit.

Methane Management

Methane emission reduction in the oil and gas industry is also a key to Alberta’s new carbon plan. The Panel has made two recommendations in this regard. First, new design specifications would be put in place for facilities as well as standards for key equipment and operational best practices. Fugitive emission standards would also be included in the regulations and would require raising current standards for performance, monitoring, measurement and reporting.

Second, it is recommended that regulators, industry, independent experts and environmental groups collaborate to develop and oversee a multi-year plan for updating or retrofitting equipment in existing facilities before the end of the equipment’s useful life. The plan’s specifics have obviously not yet been worked out, but the work would be aimed at creating an offset trading system whereby operators who take early action can be rewarded.

The Panel recommends that at the end of five years, or longer if there is evidence of cost effectiveness, the government should mandate the replacement of such equipment at facilities that have not participated in the offset program before the end of the equipment’s life. The alternative to such equipment replacement will be to prematurely shut in and abandon the well or facility.

Absolute Cap on Oilsands Emissions

The oilsands industry will be subject to the same proposed output-based allocations process as other large final emitters and as such oilsands industry compliance costs will double by 2018.

Curiously, the Climate Change Advisory Panel’s recommendations did not suggest an absolute cap on emissions from the oilsands industry. However, the Alberta government has announced it will create a legislative cap on oilsands emissions of 100 MT per year. Presently, the oilsands sector emits about 70 MT per year.

The 100 MT cap is a significant change that will undoubtedly negatively affect future oilsands investment decisions. Given that some approved projects are not yet operating, it is not clear how tight to the 100 MT limit the oilsands sector will be in the future or how long it may take to reach the cap. It is also not clear what the penalty will be if the 100 MW cap is exceeded or if and how it will be distributed among oilsands operators. 

No details on the analysis of how a 100 MT limit was decided upon have been released.