ARB regulators based three different allowance budget scenarios on the three different GHG trajectories for 2030. The first scenario is based on the current 40% GHG reduction target that was implemented in the 2017 Scoping Plan, and if implemented, it would entail an estimated 115 million allowances removed from the 2021-2030 allowance budgets. The second scenario is based on the 48% reduction in target introduced in the 2022 Scoping place and would entail a removal of 265 million allowances. Regulators also introduced an upper bound target of 55%, which would result in 390 million allowances being removed from the allowance budget.
Despite the varying levels of ambition, all three scenarios would have a 2021 starting point. The intention behind starting each budget scenario in 2021 is to incorporate the 13.7 MMTCO2e deficit in the 2017 Scoping Plan’s projection of 2020 emissions. Adjusting the 2030 allowance trajectory to match the actual, lower 2020 emissions level will, therefore, lead to a tighter allowance budget even if the original, least ambitious 40% GHG reduction target for 2030 is maintained. Upon implementing the readjusted 2020 emissions data, regulators would then correct the 2025-2030 allowance budgets to realign with the new trajectories.
Where these allowances will be removed from is still under consideration. In the presentation, ARB regulators outlined four different pools where potential cuts could happen. The pool of 77.7 million V13-20 allowances in the Price Ceiling is one area in which reductions may take place. The 156.3 million V13-30 allowances in the Auction Price Containment Reserve (APCR) offer another potential source for allowance cuts. Finally, the 1.37 billion V25-30 allowances for auctions and free allocation are also under consideration.
Under the current cap-and-trade regulation, investor-owned power utilities must consign 100% of their freely allocated allowance towards auctions and use the proceeds to protect ratepayers from increased rates resulting from the costs of compliance. Natural gas utilities face similar regulations but consign only a portion of their allowances to auctions. The consignment percentage for 2023 is set at 65%, with a 5% annual increase. Currently, regulators are evaluating consignment thresholds and rules surrounding the use of proceeds in order to better protect and benefit ratepayers – particularly low-income households. Incorporating mandated consignment thresholds for publicly-owned utilities (which currently face no consignment obligations) is also being considered.
California’s ARB is also contemplating updating its allocation structure so that it would directly allocate allowances for industrial entities to incorporate the carbon price associated with the electricity they have purchased. It is further examining the framework to incorporate drop-in biogenic fuel production and the benchmarks for different activities associated with production.
Other topics on the agenda included the efficacy of continuing the Voluntary Renewable Electricity Program, which allocates allowances from the cap each year to incentivize voluntary renewable energy purchases by compliance entities. Regulators also highlighted the necessity of including removals and carbon capture and storage (CCS) technologies in ensuring the feasibility of the decarbonization targets for compliance entities. The presentation further emphasized the ability and interest of ARB regulators in extending the program beyond 2030, particularly to contribute to California’s 85% GHG reduction target for 2045.
The announcement and conclusion of the second meeting had a significant bullish impact on CCA prices. Since the release of the notice for the ARB presentation on 12 July, the CCA benchmark contract has increased 14% (USD 4.60), settling at USD 37.49/t on 31 July – the highest settlement price for a benchmark contract in the program’s history. The bullish pressure on contract prices stems from the greater-than-anticipated allowance budget scenarios. Anticipation of sizable cuts in allowance budgets and higher CCA prices increased call option buying by market participants, creating a gamma squeeze in the market. Over the past week, however, activity has started to ease as those shorting the market have begun hedging their positions. The benchmark contract settled at USD 36.37/t on 4 August – still trading at levels well above those prior to the 12 July meeting notice.
Feedback on the meeting and the questions outlined in the presentation is due to ARB regulators on 17 August. ARB officials have not announced a date for any next steps in the regulatory process but are likely to finalize the rulemaking process by the end of the year with implementation by 2025. Quebec regulators have not had a second regulatory meeting since the joint webinar with California on 14 June, but plan to have any program updates finalized by this winter and implemented by the summer of 2024. Regulatory factors have been the predominant factor driving CCA prices in the past several weeks, therefore any further bullish pressure on contract prices is contingent upon market participants gaining further clarity on what the program changes will look like.
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