This section responds to various comments concerning the EPA’s approach to subcategorization.
In this rule, we are treating all fossil fuel-fired EGUs as a single category, and, in the emission guidelines that we are promulgating with this rule, we are treating steam EGUs and combustion turbines as separate subcategories. We are determining the BSER for steam EGUs and the BSER for combustion turbines, and applying the BSER to each subcategory to determine a performance rate for that subcategory. We are not further subcategorizing among different
412 Analysis Group, Carbon Control and Competitive Wholesale Electricity Markets:
Compliance Paths for Market Outcomes, at 5 (May 2015), available at
http://www.analysisgroup.com/uploadedfiles/content/insights/publishing/clean_power_plan_mar kets_may_2015_final.pdf.
413Id. at 5 n.4.
414 Regulatory Assistance Project, Incorporating Environmental Costs in Electric Rates Working
to Ensure Affordable Compliance with Public Health and Environmental Regulations, at 17 (2011) (citing Ohio Revised Code, Section 4928.143(B)(2)(a)and (b)), available at raponlin.org.
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types of steam EGUs or combustion turbines. As we discuss below, this approach is fully consistent with the provisions of section 111(d), which simply require the EPA to determine the BSER, do not prescribe the method for doing so, and are silent as to subcategorization. This approach is also fully consistent with other provisions in section 111, which require the EPA first to list source categories that may reasonably be expected to endanger public health or welfare and then to regulate new sources within each such source category, and which grant the EPA discretion whether to subcategorize the sources for purposes of determining the BSER.
Each affected EGU can achieve the performance rate by implementing the BSER, specifically, by taking a range of actions –- some of which depend on features of the section 111(d) plan chosen by the state, such as the choice of rate-based or mass-based standards of performance and the choice of whether and how to permit emissions trading -- including investment in the building blocks, replaced or reduced generation, and purchase of emission credits or allowances. Further, in the case of a rate-based state plan, several other compliance options not included in the BSER for this rule are also available to all affected EGUs, including investment in demand-side energy efficiency measures. Such compliance options may also indirectly help affected EGUs achieve compliance under a mass-based plan.
Our approach of subcategorizing between steam EGUs and combustion turbines is reasonable because building blocks 1 and 2 apply only to steam EGUs. Moreover, our approach of not further subcategorizing as between different types of steam EGUs or combustion turbines reflects the reasonable policy that affected EGUs with higher emission rates should reduce their emissions by a greater percentage than affected EGUs with lower emission rates and can do so at a reasonable cost using the approaches we have identified as the BSER as well as other available measures. While oil- and gas-fired steam EGUs have lower CO2 emission rates than coal-fired steam EGUs, oil- and gas-fired steam EGUs represent only a small fraction of the total
generation and total CO2 emissions of steam EGUs overall. These EGUs are not disadvantaged by being placed in a subcategory whose performance rate is established based predominantly on the emissions performance of coal-fired steam EGUs with higher CO2 emission rates.
We have also exercised our discretion not to subcategorize by the Interconnection regions used in the analysis to develop the nationwide CO2 emission performance rates, as discussed in section V.A.3.f.
Likewise, although some commenters requested that we subcategorize by ownership in order to establish less stringent emission guidelines for affected EGUs owned by municipal and cooperative utilities, we decline to do so. Traditionally, our subcategorization decisions under section 111 have been based on consideration of physical and operational characteristics, now ownership characteristics. As described in sections V.A.4. and V.A.5., all types of affected EGUs, regardless of ownership, have means for accessing the building blocks and capable of achieving the emission limitations that reflect the BSER.
Of course, a state retains great flexibility in assigning standards of performance to its affected EGUs and can impose different emission reduction obligations on its sources, as long as the overall level of emission limitation is at least as stringent as the emission guidelines, as discussed below. This rule does not prevent a state from exercising that flexibility with
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consideration to the ownership characteristics of its affected EGUs, if the state is persuaded that treating its EGUs differently on that basis is appropriate.
XXVII. Additional Reliability Studies
This section notes additional studies that support the EPA’s conclusion that this rulemaking will not jeopardize reliability.
Trieu Mai, Debra Sandor; Ryan Wiser; Thomas Schneider, NREL, “Renewable Electricity Futures Study (January 2012)
GE Energy Consulting, “Minnesota Renewable Energy Integration and Transmission Study; Final Report” (October 31, 2014)
GE Energy Consulting, “Integration of Renewable Resources,” (August 2010) Analysis Group
April 2015: Ensuring Electric Grid Reliability under the CPP (a rebuttal to some of the critical comments filed with FERC this spring (25 pages or so))
March 2015: Electric System Reliability and EPA’s Clean Power Plan – the Case of PJM (like the one re: MISO)
May 2014: Greenhouse Gas Emission Reductions from Existing Power Plants: Options to Ensure Electric System Reliability
AEE Institute, NERC’s Clean Power Plan Phase I Reliability Assessment – A Critique (May 2015)
Regulatory Assistance Project, “Reliability Standards Safety Valve and the State Clean Power Plan Compliance Obligation” (April 2015)
XXVIII. Potential for emission reductions from non-BSER measures
Section V.A of the Preamble contains a discussion of the use of non-BSER measures to achieve standards of performance. As explained in that section, these technologies are potentially available for use by affected EGUs, depending on the design of state plans, under the guidelines. Non-BSER measures either reduce the amount of CO2 emitted per MWh of generation from the set of affected EGUs or reduce the amount of generation, and therefore associated CO2
emissions, from the set of affected EGUs. This section briefly discusses these options and summarizes information the agency relied on in determining that the availability of such options provides additional flexibility and potential cost savings to the individual affected EGUs and the source category to achieve emission reductions consistent with application of the BSER.
Demand-side energy efficiency (DS-EE) is foremost among options that are available, and the potential for reduction in emissions from DS-EE is substantial. For this reason, the
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EPA’s regulatory impact analysis for the final rule includes a representation of DS-EE compliance potential because energy efficiency is a highly cost-effective means for reducing CO2 from the power sector, and it is reasonable to assume that a regulatory requirement to reduce CO2 emissions will motivate parties to pursue all highly cost-effective means for making emission reductions accordingly, regardless of what particular emission reduction measures were assumed in determining the level of that regulatory requirement. The EPA has included in our illustrative plan scenarios (both rate- and mass-based) a level of demand reduction that could be achieved, and the associated costs incurred, through implementation of demand-side energy efficiency measures. For illustration, we estimated the potential for net cumulative demand reduction of 23,150 gigawatt-hours (GWh) in 2020. By 2030, that number climbs to 327,092 gigawatt-hours (GWh), representing a 7.83 percentage reduction from business-as-usual sales.
See Table 3-2 in the DS-EE TSD. See also RIA, section 3.7.1. In Chapter 5 of the DS-EE TSD, we discuss EE strategies that go beyond ratepayer-funded EE programs, of which there are many. These include building energy codes, state appliance standards, energy service performance contracting, and other coordinated efforts by utilities to manage and improve delivery of real and reactive power (referred to as “volt/VAR optimization”). By way of
illustration, total savings from state appliance standards alone could be as high as 212 terrawatt- hours (TWh) in electricity savings in 2025. See DS-EE TSD, section 5.2.4, Table 7.
The agency also believes other non-BSER measures in addition to DS-EE will be widely available to the industry. The agency discussed these in the proposal, see 79 FR 34923-25. One recent report confirms the agency’s view in the proposal, confirmed and reflected in the final rule, that non-BSER measures can potentially play a significant role for many sources. The National Association of Clean Air Agencies (NACAA) report, “Implementing EPA’s Clean Power Plan: A Menu of Options” (May 2015), identifies twenty five approaches to GHG reduction in the electric sector, provides a detailed description of compliance methods for each, and, in many cases, provides information as to the amount of emission reductions available through these approaches .415
Non-BSER measures NACAA identifies include, among others: implementing CHP; improving coal quality; optimizing grid operations; pursuing CCS; fuel switching; reducing losses in transmission and distribution; increasing clean energy procurement requirements; encouraging clean distributed generation; and revising transmission planning, among others. See id. at Intro-4-5. Some of these measures are recognized as under-utilized. For example, CHP accounts for 8 percent of U.S. generating capacity but could be increased to 20 percent, and could reduce CO2 emissions by 800 million metric tons per year by 2030. See id. at 2-1.
According to the NACAA report, use of coal washing strategies before combustion can increase plant efficiency, leading to a 2 to 3 percent decrease in CO2 emissions. See id. at 4-3.
It should be noted that in some cases, different parts of the electric sector can be expected to take advantage of different approaches. For example, the NACAA report acknowledges that fuel-switching may be feasible at some plants (e.g., where they may be already designed to co- fire alternative fuels), but prohibitively costly at others. Id. at 9-1. The key point is that there are
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multiple non-BSER strategies available, some of which may work at some facilities or in one region, and others which may work elsewhere.
The report also notes that grid optimization efforts (e.g., creating a “smart grid” and/or requiring power factor management) can reduce excessive electricity losses during transmission from peaks of around 20 percent to a more typical six or seven percent. Id. at 5-2, 5-3. Finally, by way of illustration, distributed generation, such as rooftop solar photovoltaic systems are becoming increasingly affordable and cost competitive. In six years the amount of installed distributed PV has tripled to 3 gigawatts (GW) and the module costs have dropped from about $4 per watt to about $1 per watt. Id. 17-1. The NACAA report anticipates considerable growth in distributed generation, and with grid modernization, the GHG-reducing potential of clean distributed generation will increase over time.
While the EPA does not specifically endorse the facts and statistics presented by NACAA in this report, this report confirms the broad scope of non-BSER measures to reduce emissions, and confirms that significant amounts of emissions can be reduced though these measures. Thus, these measures enhance flexibility by both sources and states, potentially lower the costs of compliance with the final rule, and safeguard the ability of affected EGUs to comply with the emission limits of this rule.