Emissions trading systems are well suited to accelerate the clean energy transition in the power sector. Electricity and heat generation account for over 40% of global energy-related CO₂ emissions, with 30% of energy-related CO₂ emissions coming from coal-fired power plants.1 The power sector is already decarbonising worldwide, due to falling low-carbon technology costs and low competitiveness risks, but not quickly enough to meet the Paris Agreement goals. The power sector is particularly well-suited to be covered by an emissions trading system. First, it is a large emitting sector with proven, low-GHG technologies that are commercially available. Second, data availability for electricity generation is on average strong across jurisdictions, which is needed to determine allocation benchmarks. Moreover, several jurisdictions already have experience in implementing power sector mitigation activities with the support of carbon pricing, for instance through crediting mechanisms such as the Clean Development Mechanism. The power sector is included in almost all operating emissions trading systems around the world, as well as in jurisdictions that are developing or considering developing an emissions trading system.

This section describes how different power market structures can affect the effectiveness of an emissions trading system and how different systems have adapted their design to local power market conditions.

Power producers generally treat the allowance cost in an emissions trading system as a marginal cost in operations decisions, and as a commodity that needs to be reflected in investment appraisals. For power consumers, the result of the application of carbon price is that carbon-intensive goods become more expensive. This effect encourages a switch to low-carbon alternatives or a change in consumption patterns.

In theoretically perfect carbon and power markets, the reflection of emissions trading system allowance costs in the power sector creates at least three levels of incentives to reduce emissions:

• Investment incentives for less carbon-intensive power supply. In theory, carbon pricing encourages investment in less carbon-intensive technologies, making high-emitting power plants less profitable. In practice, these investment incentives are sometimes limited by fossil fuel subsidies, by the lack of long-term emissions trading system policy certainty or by the lack of stability of allowance prices within the system.
• Reduction in electricity demand. In competitive power markets, fossil fuel power generators reflect the carbon price through the increased marginal cost of the fuel used. Increased carbon costs are passed on to consumers in power retail price increases. Higher electricity prices create incentives for end-use energy efficiency and conservation.
• Changes in the merit order of electricity dispatch. Carbon pricing increases the short-run variable cost of fossil fuels based on their carbon content. Less efficient, high-emitting fossil fuel power plants (such as coal-fired plants) lose positions in the merit order and their annual operating hours are reduced in an economic dispatch model. This results in lower emissions and in a reduction of the profitability of high-emitting power plants.

In practice, however, carbon pricing is not always able to completely deliver these incentives within power markets. Power markets are often fully or partially regulated, meaning producers can be constrained when it comes to decisions on investment or generation, and can face regulated wholesale and retail electric prices.

Some market structures can weaken the carbon price signal, reducing the emissions trading system’s effectiveness. If retail electricity prices are highly regulated, for example, the carbon price signal will not be visible to electricity consumers. This effect limits or removes the incentive for electricity consumers to save electricity or to choose low-carbon electricity suppliers. Similarly, in market structures where wholesale prices and dispatch decisions are regulated, a carbon price would have limited impact on shifting the merit order towards low-carbon power sources.

The design of the emissions trading system should be tailored to the power market circumstances. In markets where co-generation (electricity and heat) plants are widely used, the emissions trading system should be tailored to both power and heat market structures, because if the electricity prices are liberalised but the heat prices are regulated, the pass-through of carbon pricing could be distorted. Several methods can be used to better reflect the emissions trading system carbon price signal while taking into consideration existing power market regulations:

• Coverage of indirect emissions. To reflect the carbon price in regulated electricity prices, large electricity consumers could be required to surrender emissions trading system allowances for their indirect emissions associated with electricity consumption. This creates a carbon pricing signal reflected in increased final end-use consumer prices, and encourages energy savings and energy efficiency. However, competitiveness and double counting issues could arise, since allowances are required from both electricity generation and consumption.
• Consumption charge. A consumption charge could facilitate downstream emissions reductions when regulations prohibit explicit retail or wholesale carbon price pass-through. Final and intermediate consumers may experience a consumption charge at the discretion of the government even under an unchanged electricity price. The consumption charge does not create double counting or competitiveness issues.
• Climate-oriented dispatch. The climate-oriented dispatch is a broader regulatory framework for the power sector under an emissions trading system. When the production of electricity is regulated, an “administrative” electricity dispatch could be implemented to deliver the effect on dispatch that an emissions trading system is designed to deliver. For instance, emission levels and fuel efficiency can be used as prioritisation criteria for the “administrative” electricity dispatch.
• Carbon investment board. Within a regulated investment environment, governments could mandate the planning body to integrate predefined carbon prices (also called “shadow prices”) when making investment decisions. When an emissions trading system co-exists with regulated investments, the resulting allowance price could be used to infer the level of the shadow price.
• Pricing committee. When the market has either a regulated wholesale price or a regulated retail price, a pricing committee can help set and review the rules for determining how the wholesale or retail prices could reflect carbon pricing and emissions trading system allowance price fluctuations. The committee could allow the impact of a carbon price on the utility’s cost of electricity production to be passed through into wholesale or retail tariffs.2

Placing additional costs on power plant operations or raising consumer electricity prices to reflect the price of carbon can be politically challenging. Policy makers often struggle to find a balance among competing objectives, such as reducing emissions while ensuring electricity security and affordability. One way of managing this challenge is to build revenue streams into an emissions trading system, such as through auctioning mechanisms, to compensate electricity consumers for price increases. An example of this is California’s Cap-and-Trade System, included below among other examples of how various systems have adapted their design to the structure of the local power market.

Managing regulated dispatch and retail prices in Korea’s emissions trading system

The power sector is the highest-emitting sector in Korea, responsible for over 54% of the country’s CO₂ emissions in 2018. Coal-fired power plants emit about 80% of the CO₂ emissions of the sector. Korea’s emissions trading system operates in an open wholesale electricity market with regulated retail prices, where additional carbon costs are not reflected in wholesale dispatch bid prices or in retail prices.

Korea has a cost-based wholesale electricity market based on day-ahead settling. All dispatchable plants submit their available power generation to the Korea Power Exchange a day in advance and the power exchange plans power generation based on the generators’ variable fuel costs. The emissions trading system carbon price does not influence dispatch of different power plants, since this is not incorporated in the assessment of direct fuel costs for the power generation plan.3

In the first phase of Korea’s emissions trading system (2015-17), electricity generators found themselves short of allowance units, as free allocations based on historical baselines did not account for increased coal power generation. Power generation companies had to purchase additional allowance units, but the cost of these was covered by the electricity retailer, Korea Electric Power Corporation, meaning the extra cost was not paid by the power generators.

At the retail level, regulated prices limit the level to which the emissions trading system carbon price is reflected in end-user electricity prices. For instance, retail electricity prices remained constant from 2013 to June 2016, even though Korea’s emissions trading system started operating in 2015. Historically, Korea Electric Power Corporation has experienced cases of surplus and deficit allowance units, because of its inability to pass wholesale cost fluctuations onto consumers. This has led to the development of a separate mechanism to tackle electricity consumption in Korea’s emissions trading system, extending its coverage to indirect emissions associated with electricity and heat consumption by large industrial users by increasing their allowance allocation.

Overall, the implementation of Korea’s emissions trading system has not managed to reflect a significant price signal for both electricity consumers and power generators so far. The Korean government is trying to address some of these challenges by studying options to reflect the emissions trading system carbon pricing in the power generation plan in the wholesale electricity market, including a framework for a shadow price for environmental dispatch.

Balancing the carbon price signal: California’s cap-and-trade

California’s cap-and-trade experience shows that it is possible to achieve two seemingly conflicting objectives: reflecting carbon pricing in final consumer prices in a regulated retail market and addressing political concerns of the cost impacts for final consumers. The return of the allowance value to consumers ensures consumer protection from electricity price increases due to carbon pricing in an efficient way that enhances environmental effectiveness. California has a competitive wholesale electricity market, while the retail electricity is operated as a monopoly, with regulated prices for most electricity consumers. Over 75% of power is generated by private investor-owned utilities (IOUs) regulated by the California Public Utilities Commission, with the remaining electricity share produced by public-owned utilities and non-profit agencies, which are often run by the government and not regulated by the commission.

In 2010, the California Air Resources Board suggested including a carbon price reflecting marginal greenhouse gas abatement costs in the electricity retail price while protecting ratepayers from electricity price rises. To obtain this effect, the California Public Utilities Commission and the California Air Resources Board created a mechanism based on two steps. First, in 2014 the commission approved a mechanism to incorporate carbon pricing into the retail electricity prices, as a response to the increased carbon costs of various climate policies, including California’s cap-and-trade. This resulted in an increase of the final retail electricity price.

Second, the California Air Resources Board devised an economic compensation mechanism through which IOUs use the revenues generated by the consignment auctioning under the cap-and-trade system to mitigate the final price increase for electricity consumers. The consignment auctioning mechanism requires IOUs to sell (consign) 100% of their freely allocated allowances at quarterly auctions and to subsequently repurchase them to meet their compliance obligations. Around 70% of the revenues raised through consignment auctions are used to keep retail electricity prices stable, as the IOUs return these to customers twice a year via a lump sum called Climate Credit, equalling about USD 30 to USD 40 per household. As a result, although retail prices go up, overall electricity expenditures remain stable.

China emissions trading system pilots: Including indirect emissions

All of China’s regional emissions trading system pilots include indirect emissions associated with electricity and heat consumption. This design is mainly driven by two considerations. First, as the dispatch and retail prices for electricity and heat are highly regulated, there is only a weak price signal to consumers to drive demand-side conservation. Inclusion of indirect emissions aims to provide incentives for major consumers to limit their electricity consumption, and ensure that trading system participants must take action to reduce emissions from electricity and heat use, rather than lowering emissions by switching from direct fossil fuel use to electricity and heat.

Second, as the emissions trading system pilots are applied only to certain provinces and municipalities, coverage of indirect emissions ensures that emissions associated with electricity and heat that are consumed locally but imported from other regions are equally considered in the emissions trading system. The scale of imports can be significant, with potentially up to 80% of emissions associated with products consumed in coastal areas being generated elsewhere. The inclusion of indirect emissions thus helps to mitigate the carbon leakage concern. The Chinese national emissions trading system is considering covering indirect emissions from purchased electricity to manage regulated electricity and gas markets.

In practice, the effect of indirect emissions coverage is difficult to assess. Allowances have been generally abundant under the regional pilot output-based schemes, and most pilots have adopted grandfathering for allowance allocation in non-power sectors which cover indirect emissions from electricity and heat consumption.4

Including indirect emissions could lead to double counting of emissions reductions. Double counting could be mitigated by adopting consistent standards for the allowance allocation design systems and the manner in which emissions reductions are counted. Including indirect emissions also raises concerns over the accuracy of the emission factors used, which may increase the risk of over- or under-allocation and hence distort the carbon price. The Chinese emissions trading system pilots have been using the regional grid average emission factors for indirect electricity emissions, while recent reporting guidelines for the upcoming national emissions trading system have used national grid average emission factors for non-power sectors, which could be less representative than the regional factors. In case of deviation, an adjusted emission factor needs to be applied to minimise the gap between the actual emissions from electricity consumption and the estimated indirect emissions.

Tokyo’s emissions trading system: Accounting for the high electricity consumption of commercial buildings

The Tokyo municipal emissions trading system also covers both direct and indirect emissions. Indirect emissions are included in the emissions trading system specifically to cover the emissions from electricity consumption in commercial buildings. In Tokyo, electricity represents 40% of energy consumed, but 90% of this electricity is produced outside of the geographic boundaries of the city. A fixed emissions factor is therefore used to calculate CO₂ emissions from electricity use, to separate out efforts made to reduce electricity demand from fluctuations in the CO₂ emission factor on the supply side. Since 2006, facilities have been required to calculate and report their emissions to the national government, including CO₂ emissions related to fuel usage, and the use of electricity and heat. This mandatory data collection in the years before the emissions trading system is recognised as a key to the success of the programme, allowing facility-level understanding of indirect emissions through electricity and heat use.

• How does the specific power market structure impact carbon price signals, and in turn the required design features of the emissions trading system?
• How can the carbon price be reflected in the expansion planning, power plant dispatch decisions and end-use prices?
• In markets where electricity supply is liberalised but heat supply remains regulated, how is the carbon pricing allocated to the electricity and heat output of co-generation plants?