The Clean Power Plan presents the states with a complex set of choices to reduce CO2 emissions from their electricity sectors. States must decide what form of target to adopt, the role of market-based emission credits or allowances, and the desired range of interstate trading opportunities. States making these choices will try to satisfy multiple objectives and respond to a broad range of stakeholder opinion on the best path forward. This paper introduces some of the tradeoffs and analyses that states and stakeholders should consider in selecting an implementation and compliance system to attain the ambitious goals of the Clean Power Plan.
In August 2015, the Environmental Protection Agency (EPA) finalized its carbon dioxide (CO2) emission standards for existing power plants under Section 111(d) of the Clean Air Act, a rule commonly known as the Clean Power Plan (CPP). At the same time, the EPA provided a blueprint for moving forward by defining tradable compliance instruments, delineating the scope of intrastate and interstate trading, and proposing sets of state and federal implementation mechanisms intended to enable compliance.
In the final CPP, the EPA pushed back by two years the deadline for states to finalize implementation plans (now 2018) and the initial compliance period (now 2022) in response to comments expressing concerns about the Draft Plan's administrative feasibility, near-term costs, and potential reliability impacts. While the derivation of the emission standards and the distribution of emission reductions among the states changed considerably between the proposed and final rule, the resulting phase-in of the emission guidelines for most states (and existing generating units) represents a more gradual transition to lower CO2 emissions than the proposed regulation.
Starting with a single set of CO2 emission rate standards that will apply to fossil steam and natural gas combined cycle (NGCC) units, the EPA derived multiple emission rate and emission mass standards that states might adopt to demonstrate compliance, under a presumption that the two types of goals are equivalent even if compliance mechanisms differ. The EPA also clarified that while states choose the compliance approach, individual existing fossil fuel-fired units will be responsible for complying with the CPP—likely via a much broader role granted to trading mechanisms of either emission allowances or emission rate credits (ERCs), depending on how states elect to implement the CPP. By issuing proposed model trading rules for states to use in developing implementation plans and proposed federal plans that rely on tradable instruments, the EPA has expressed a clear preference for market mechanisms to incentivize generation from lower-emitting resources over the next decade and a half.
This issue brief provides an overview of the CPP and discusses three key observations for stakeholders in the regulatory process:
- First, while the EPA has given states a broad slate of implementation options from which to choose, the different options are not equivalent in many important dimensions. State-level outcomes, such as cost, cost incidence, resulting CO2 mitigation and wholesale electricity prices, coal unit retirements, new in-state renewables development, and emission reductions can vary across the different implementation pathways. Therefore, states attempting to achieve particular policy objectives may favor some approaches over others. For example:
- States with significant renewable potential and a strong preference to retain coal plants may benefit from a rate-based plan;
- States expecting low load growth may find mass-based approaches less costly;
- States that expect to attain (and beat) emission rate standards with in-state renewables may prefer a state average rate approach, which would limit the ability of ERC producers from selling these credits out of state to offset higher emissions elsewhere; and
- States worried about retaining existing nuclear plants may prefer higher wholesale prices and allowance allocations under a mass-based approach.
- Second, the outcomes expected under each state's implementation decision will depend, in part, on the decisions of other states (i.e., they are co-determined). This interdependence substantially complicates the decision process, and implies that states will benefit from information about other states' deliberations and analyses of their expected choices among compliance plan options. For this reason, states will likely enjoy advantages from coordinating implementation decisions with each other in order to achieve local policy objectives in both the near and long term.
- Finally, the Regulatory Impact Analysis (RIA) that the EPA conducted is unlikely to provide useful information for states deciding between alternative implementation approaches. This means that states will have to perform their own analyses, with the input of their important stakeholders, to make implementation decisions that reflect their policy objectives.
Brief Introduction to the Final Rule
Between the proposed and final CPP, the EPA significantly changed its approach for setting CO2 emission standards for fossil electric generating units (EGUs). Most notably, the EPA excluded some zero-emission resources from the Best System of Emission Reduction (BSER) building blocks1 and moved from state-specific emission rate targets to nationwide "subcategory" performance standards that form the basis for all rate- and mass-based implementation options that states may adopt. The two subcategory performance standards apply to: (1) existing fossil steam units (i.e., coal-fired units and oil/gas steam units), and (2) NGCC units. A third category of fossil electric generation—existing simple cycle gas- or oil-fired combustion turbines (CTs)—neither factors into the standard-setting calculations nor faces compliance obligations under the final CPP.
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