	Introduction

On October 23, 2015, the U.S. Environmental Protection Agency (EPA) released the final version of its regulations to reduce greenhouse gas (GHG) emissions from existing power plants (also referred to as electric generating units or EGUs). Since carbon dioxide (CO 2 ) from fossil fuel combustion is the primary source of GHG emissions, and fossil fuels are used for the majority of electric power generation, reducing CO 2 emissions from power plants plays a key role in the Administration's climate change policy. The combined state targets are expected to result in reducing CO 2 emissions from power generation in the United States approximately 32% by 2030 as compared to 2005 levels. EPA is also giving each state a specific CO 2 emissions rate based on these national performance rates and the state's existing power generation portfolio. A state must implement an EPA-approved plan to ensure that power plants individually, in aggregate, or in combination with other measures undertaken by the state, achieve the equivalent of the interim CO 2 emissions performance rates (over the "glide path" period of 2022 to 2029), and the final CO 2 performance rates, rate-based goals or mass-based goals by 2030. Building Block 1 : Improving the heat rate at affected coal-fired steam EGUs. Building Block 2 : Substituting increased generation from lower-emitting existing natural gas combined cycle (NGCC) units for reduced generation from higher-emitting (primarily coal-fired) affected steam generating units. Building Block 3 : Substituting increased generation from new zero-emitting renewable energy generating capacity for reduced generation from affected fossil fuel-fired generating units. Increased dependence on renewable generation will likely require new transmission lines, and many of today's transmission projects awaiting regulatory approvals are intended to serve renewable electricity projects. It can take anywhere from 3 to 10 years to get the federal, state, and local permits in place to build a major electric transmission line. If additional transmission capacity is required, planning would likely need to begin soon to get new lines in place for when they would be needed in the early 2020s. The agency has modelled potential implications of the CPP in its Regulatory Impact Analysis (RIA) for the Clean Power Plan Final Rule. State decisions on the design and availability of DSEE programs will be crucial to attaining the levels of subscribership necessary to achieve the cost reductions projected in EPA's RIA analysis. For some states, attaining the levels of cost-effective DSEE projects needed to reduce CPP compliance costs may be a challenge. For the top tier of states engaged in DSEE, the challenge may be where to look for the next increment of cost-effective projects. Given the CPP's focus on the three legs of the BSER (representing potential actions by EGUs inside the fence line), the EPA's inclusion of demand-side energy efficiency (representing actions outside the fence line) in the RIA does not clarify the costs of the BSER. However, the actual overall costs of CPP compliance will not begin to be known until after state compliance plans are filed and implemented. Concluding Comments

EPA declares in the CPP that states and affected EGUs can use whatever methods they choose to meet the applicable CO 2 emissions or emission rate reductions in the timeframes proposed. In so doing, EPA creates a plan that, according to EPA, allows most states and affected EGUs to be able to comply within the timeframe allowed. Going forward, EPA CO 2 regulations may provide a basis for the evolution of the U.S. electric power sector. In its final rule, EPA has largely calculated the CPP compliance obligations based on increasing renewable generation as the technology of choice for new power generation, emphasizing less fossil-fueled generation (including generation fueled by natural gas).
On October 23, 2015, the Environmental Protection Agency (EPA) released the final version of regulations to reduce greenhouse gas (GHG) emissions from existing power plants (also referred to as electric generating units or EGUs by EPA). Since carbon dioxide (CO2) from fossil fuel combustion is the largest source of U.S. GHG emissions, and fossil fuels are used for the majority of electric power generation, reducing CO2 emissions from power plants plays a key role in the Administration's climate change policy. Under the provisions of the Clean Power Plan (CPP), states must prepare plans that reduce either total CO2 emissions or emission rates at affected EGUs. When implemented, EPA projects the state plans will reduce CO2 emissions from U.S. power generation approximately 32% by 2030 compared to 2005 levels.
EPA prepared state-specific CO2 emissions rates based on newly established national performance standards and the state's existing power generation portfolio. A state must implement an EPA-approved plan to ensure that power plants individually, in aggregate, or in combination with other measures undertaken by the state, achieve the equivalent of the interim CO2 emissions performance rates (over the "glide path" period of 2022 to 2029), and the final CO2 performance rates, rate-based goals, or mass-based goals by 2030.
EPA based the national performance standards in the CPP on the best system of emissions reduction (BSER). In the final rule, BSER includes three ("inside the fence line") Building Blocks (BBs): BB 1 involves improving the heat rate (i.e., efficiency) of coal-fired steam EGUs. BB 2 substitutes generation from (lower-emitting) existing natural gas combined cycle (NGCC) units for generation from (higher-emitting) steam generating units. BB 3 has generation from new (zero-emitting) renewable energy generating capacity replacing generation from fossil fuel-fired generating units.
EPA has modeled potential implications of the CPP in its Regulatory Impact Analysis (RIA), and emphasizes demand-side energy efficiency (DSEE) as a potential low-cost option. While DSEE is not a part of the BSER (and is an "outside the fence" activity), EPA's RIA assumes DSEE can lower electricity demand and reduce electric system costs, thereby offsetting estimated electricity price increases. As a result, EPA projects lower average electricity bills nationally by 2030. EPA's RIA also estimates reduced electricity demand will lower natural gas consumption, even as more NGCC capacity may be called upon to back up increased intermittent and variable renewable electric generation. Increased dependence on renewable generation may require new transmission lines. Many of today's transmission projects awaiting regulatory approvals are intended to serve renewable electricity projects. It can take from 3 to 10 years to get the federal, state, and local permits to build a major electric transmission line; planning may need to begin now so that new lines will be in place for when they may be needed in the early 2020s. State decisions on the design and availability of DSEE programs may be crucial to attaining the levels of subscribership necessary to achieve the demand reductions projected in the RIA. For some states, attaining the levels of cost-effective DSEE projects needed to reduce CPP compliance costs may be a challenge, while for the top tier of states currently engaged in DSEE, the challenge may be identifying the next increment of cost-effective projects.
Going forward, EPA's GHG regulations may provide a basis for the evolution of the U.S. electric power sector. EPA has based the CPP on increasing renewables as the technology of choice for new power generation. EPA declares in the CPP that states and affected EGUs can essentially use whatever methods they choose to meet CO2 emissions and emission-rate reductions in timeframes proposed, and in so doing, creates a plan it believes most states and affected EGUs may be able to comply with in the timeframe allowed. The overall costs of CPP compliance will not begin to be known until after state compliance plans are filed and implemented.