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Climate Change Hero

Climate Change Blog

  • 07
  • October
  • 2015


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The Clean Power Plan’s Building Block 3: New Zero-emitting Renewable Generating Capacity

This is the fourth in a series of posts explaining the “building blocks” that EPA used to determine emission goals for existing power plants in the Clean Power Plan.  This post focuses on what EPA calls building block 3.  Building block 3 is based on EPA’s assumption about the extent to which generation from fossil fuel-fired EGUs can be replaced by expanding the amount of zero-emitting renewable electricity (“RE”) generating capacity. 

The renewable electricity technologies used to quantify building block 3 generation levels were: (1) onshore wind, (2) utility-scale solar PV, (3) concentrating solar power (“CSP”), (4) geothermal and (5) hydropower.    Each is a utility-scale, zero-emitting resource. EPA expressly chose not to include distributed technologies as part of the BSER.  Additionally, EPA excluded any renewable electricity technologies that have not been deployed in the U.S., including “demonstrated RE technologies for which there is clear evidence of technical feasibility and cost-effectiveness (e.g., offshore wind) . . . These RE technologies are consequently reserved for compliance.” 

EPA quantified building block 3 generation levels for each of the three BSER regions in terms of incremental, rather than total, RE generation. To calculate the Building Block 3 generation levels:

  1. EPA collected historical data on the annual change in capacity for each RE technology over the most recent five-year period. Using this data, EPA calculated each RE technology’s:  
    • average change in capacity from year to year over a five year period (2010 – 2014), and
    • maximum annual change in capacity during the same five year period. 
  2. EPA assigned each RE technology a capacity factor representative of expected future performance from 2022 through 2030.  EPA reportedly relied on the National Renewable Energy Laboratory’s (NREL) 2015 Annual Technology Baseline (ATB) to determine the appropriate capacity factor for each RE technology. 

  3. EPA then used the data from steps (1) and (2) above to calculate two levels of generation change for each RE technology.  
    • The first was the annual generation change for each RE technology associated with that technology’s five-year average capacity change (or the product of the five-year average capacity change and the capacity factor).
    • The second was the annual generation change for each RE technology associated with that technology’s maximum capacity change (or the product of the five-year maximum annual capacity change and the capacity factor).
  4. EPA estimated the RE generation from capacity commencing operation after 2012 that could be expected in 2021 without implementation of the final rule. Using base case power sector modeling projections, EPA assumed RE generation of 213,084,125 MWh in 2021. 
  6. To calculate projected RE generation for the first two years of the interim period, EPA used the more moderate level of generation change from step (3) above (the generation change associated with the historical average capacity change). This resulted in projected RE generation levels of:
    • 241,880,347 MWh in 2022, and 
    • 270,676,570 MWh in 2023.
  7. For each year of the interim period after 2023, EPA applied RE generation associated with the maximum annual capacity change from the historical data analysis.1 Aggregated across the three BSER regions, this produced generation levels of:
    • 332,869,933 MWh in 2024, and 
    • 706,030,112 MWh by 2030. 

From there, EPA conducted an analysis using an Integrated Planning Model (“IPM”) to further evaluate the cost-effectiveness and technical feasibility of these generation levels. The IPM projections incorporated a variety of constraints on the deployment of RE, including “resource constraints such as resource quality, land use exclusions, terrain variability, distance to existing transmission, and population density; system constraints such as interregional transmission limits, partial reserve margin credit for intermittent RE installations, minimum turndown constraints for fossil fuel-fired EGUs, and short-term capital cost adders to reflect the potential added cost due to competition for scarce labor and materials; and technology constraints such as construction lead times and hourly generation profiles for non-dispatchable resources by season.” 2 Additionally, the modeling framework assumed that “deployment of variable, non-dispatchable RE resources is limited to 20 percent of net energy for load by technology type and 30 percent of net energy for load in total at each of IPM’s 64 U.S. sub-regions.” 3 This 30 percent constraint reportedly reflects levels commonly modeled in grid integration studies at the level of the interconnection. EPA claimed that such studies have demonstrated that impacts to the grid in reaching levels as high as 30 percent of net energy for load from RE are relatively minor. a 

The IPM also served as the basis for apportionment of the generation levels across the three interconnections. EPA concluded that the majority of RE deployment was projected to occur in the Eastern Interconnection. The following table describes the annual building block 3 generation levels for each interconnection from 2022 through 2030.



1 EPA explained its decision to apply the five-year average capacity change to the first two years of the interim period while applying higher RE deployment levels for later years as a means “to ensure adequate opportunity to plan for and implement any necessary RE integration strategies and investments in advance of the higher RE deployment levels assumed for later years.” 

2 Preamble, Pg. 758-759.

3 Preamble, Pg. 759.

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Margaret E. Peloso

Margaret E. Peloso Partner