On August 3, 2015, the U.S. Environmental Protection Agency issued its final regulation, known as the Clean Power Plan (CPP), establishing carbon dioxide emission guidelines for existing affected electric utility generating units (EGUs) pursuant to Section 111(d) of the Clean Air Act. The final rule requires states to submit their plans to implement the emission guidelines to EPA by September 6, 2016. In addition to requiring the initial submission by that date, the regulation allows states to obtain an extension for submitting a final plan by September 6, 2018.
If a state does not submit a plan that meets the requirements of the emission guidelines, EPA will issue a regulation known as a "federal implementation plan" that will apply to the affected EGUs in that state. EPA issued a proposed federal implementation plan and model rule concurrently with the Clean Power Plan and will be accepting comments on that proposal for 90 days following its publication in the Federal Register.
For a complete explanation of the Clean Power Plan, see our August 27, 2015, mailing.
Changes in the Final Rule
The basic framework of the final CPP is similar to the proposed CPP, published June 18, 2015. As in the proposed rule, EPA established the emissions targets applicable to affected EGUs by focusing on the interconnected nature of the production and delivery of electricity. EPA analyzed emissions reductions that affected EGUs could achieve by applying three "building blocks," which EPA concluded met the statutory standard "best system of emission reduction" (BSER):
- Improving heat rate at existing coal-fired steam EGUs;
- Shifting electricity generation from higher-emitting coal-fired steam EGUs to lower-emitting existing natural gas combined cycle generation (NGCC); and
- Shifting generation from affected fossil fuel-fired EGUs to new, zero-emitting renewable energy generation, such as onshore wind, utility-scale photovoltaic solar, concentrating solar power, geothermal and hydropower.
In the proposed regulation, EPA also had included demand-side energy efficiency measures as Building Block 4 but did not include reductions that could be achieved by such measures in the final rule. Although such measures were not used as a basis for establishing the guidelines' emission targets, states can implement these measures (and others that were not included as part of BSER) in order to achieve compliance.
EPA made other notable changes in the final CPP. In the proposed rule, the interim compliance period began in 2020, but in the final CPP, the interim compliance period begins in 2022, with a "glide path" toward the final compliance date of 2030. This was done in part to provide states with additional time to promote non-NGCC-based measures to reduce CO2 emissions.
EPA also changed its approach to calculating the emissions targets. In the final CPP, EPA promulgated nationwide "sub-category" CO2 emission performance standards applicable to affected steam EGUs and stationary combustion turbines. In a new development, states can, if they so choose, simply require affected EGUs to meet these emission rate standards. As in the proposed rule, EPA also calculated statewide target emission rates, although the method used to calculate the state targets was different in the final rule. EPA also included equivalent mass-based limits for each state in order to make it easier for states to adopt intrastate or interstate allowance-based emissions trading.
Promotion of Clean Energy Generation
The emission guidelines are designed to shift generation from higher-emission steam-generating units to lower-emitting generation and zero-emission renewable generation. States will be permitted to set aside a percentage of their allowance caps to be issued to qualifying renewable energy or energy efficiency projects. Early action wind and solar projects and energy efficiency projects in low-income communities also will be encouraged in states that implement the Clean Energy Incentive Program, included in the final CPP.
The guidelines also explain the issuance and use of “Emission Rate Credits” (ERCs), an important compliance mechanism for states that target compliance with the achievement of subcategory or statewide emission rates. As long as all requirements are met, ERCs created by renewable energy or other projects located in one state could be traded to affected EGUs in a second state.
Potential Implications for Developers and Utilities
There is a great deal of uncertainty surrounding the implementation of the CPP. The rule itself provides the states with the initial authority and flexibility to determine how they will implement the emission guidelines, subject to the targets set by EPA and other limitations and requirements that are part of the CPP. Although promotion of renewable energy is inherent in the structure of the CPP and the final rule is designed to encourage the states to use flexible, market-based mechanisms that will provide incentives for renewable energy, the final regulations applicable to affected EGUs will not be known until the process of developing and approving state plans (or finalizing federal plans in states that do not choose to submit their own plans) has been completed. And finally, the CPP is a controversial regulation that already has been and will continue to be subject to multiparty litigation involving the federal government, energy regulators, the states, the power generation sector, other industrial sectors (including coal mining) and environmental groups. There are a number of potential outcomes to this litigation, including the possibility that the use of the "outside the fenceline" approach to setting emissions targets for existing fossil fuel electric-generating units is not authorized by Section 111(d) of the Clean Air Act.
Once the dust settles, the CPP could benefit developers of clean energy generation and traditional rate-regulated utilities. Because the owners and operators of affected EGUs are likely to rely upon clean energy projects to achieve compliance with the state plans developed pursuant to the CPP, this may make it easier for clean energy project developers to obtain the power purchase agreements necessary for project financing. Regulated utilities that make investments to upgrade their plants, develop lower-emitting replacement generation, or expand transmission and distribution capacity in order to comply with the regulation also could benefit.