Clean Power Plan with New Source Performance Standards for power generation

Release Date: 9/15/2016

The Clean Air Act (CAA) sets the regulatory framework for federal efforts to control emissions of air pollutants in the United States, requiring, among other things, the application of preferred technology standards to limit pollutants found to pose a threat to human health and the environment. Using CAA provisions, the U.S. Environmental Protection Agency (EPA) has developed a three-part program to limit carbon dioxide (CO2) emissions from the electric power sector:

1. CO2 performance standards for new power plants
2. CO2 performance standards for existing power plants (the CPP)
3. Rules for states electing federal implementation options and model trading program design

Final rules to support the performance standards were published in October 2015, with the performance standards for existing power plants and the proposed model trading rule scheduled to take effect starting in 2022. However, in February 2016 the Supreme Court issued a stay on enforcement of the existing power plant CPP, pending resolution of legal challenges. At the time the stay was issued, no lower court had considered the merits of the legal challenges to the rule, and there was no enforceable judgment either affirming or vacating the CPP. Under these circumstances the AEO2016 Reference case includes the CPP and an alternative No CPP case that excludes the CPP for comparison.

Regulatory background: legal basis for CPP/NSPS rules

In Section 111 of the CAA, Congress provided for the development of emissions standards to limit pollutants from new sources. The new source performance standards (NSPS) were intended to be nationwide and uniform, as a complement to the regional application of ambient air quality standards to control emissions from existing sources. However, the CAA requires that, once EPA has established standards for new sources EPA must require states to develop standards for existing sources.

For CO2 emissions from electricity generation units, EPA developed the following regulations for new and existing sources concurrently:

• Performance standards for new sources (as well as modified and reconstructed sources) under authority of Section 111(b) [8]
• Performance standards for existing sources under Section 111(d), published in October 2015 [9] and stayed in February 2016 [10]
• Federal plan and model trading rules, proposed in October 2015 [11], with EPA’s announced intent to finalize the rules for both mass-based (cap and trade) and rate-based versions by summer 2016

EPA provides for the exclusion of units subject to the Section 111(b) rule from Section 111(d) plans, so that if a source covered by a Section 111(d) plan is modified or reconstructed, it drops out of Section 111(d) coverage and only needs to meet the Section 111(b) requirements.

Representing new source CO2 emissions standards: Sec 111(db rules

The CAA requires that standards issued under Section 111 reflect the degree of emissions limitation achievable through the best system of emission reduction (BSER) found by EPA to have been adequately demonstrated. In its final rule, for new sources, which also covers modified and reconstructed sources, EPA specified CO2 standards for four types of new electric generating units (EGUs):

1. New fossil steam EGUs: 1,400 pounds CO2/megawatthour (MWh) gross
2. Modified fossil steam EGUs: limit determined by unit's best historical annual CO2 rate (from 2002 to the date of the modification) but no greater than reconstructed coal EGUs
3. Reconstructed coal steam EGUs:

a. 1,800 pounds CO2/MWh gross (if heat input is more than 2,000 million British thermal units (Btu)/hour)
b. 2,000 pounds CO2/MWh gross (if heat input is 2,000 million Btu/hour or less)

4. New combined-cycle combustion turbine: 1,000 pounds CO2/MWh gross, or 1,030 pounds CO2/MWh net, where the state has the option to choose between having combustion turbine operators report their generation output on a gross basis (including total electric output) or a net basis (excluding the power necessary to operate the plant itself)

The new coal plant technology modeled in the AEO2016 National Energy Modeling System (NEMS) includes 30% carbon capture to ensure the ability to meet the standard. New coal plants without carbon capture and storage technology are not allowed to be built. The new natural gas combined-cycle plants modeled in previous AEOs were already below the 1,000 pounds CO2/MWh standard, and no change was necessary to the natural gas technology assumptions to reflect the final rule. The NEMS electricity model does not explicitly represent modified or reconstructed power plants.

Representing existing-source CO2 emissions standards: Section 111(d) rules

EPA adopted interim and final CO2 emission performance rates for two subcategories of fossil fuel-fired EGUs:

1. Existing fossil steam EGUs: interim/final rate, 1,534/1,305 pounds CO2/MWh net

2. Existing stationary CTs: interim/final rate, 832/731 pounds CO2/MWh net [12]

The emission performance rates, which are set uniformly for the nation for both subcategories, were determined using an analysis of BSER that reflects an emission adjustment according to EPA’s assessment of the potential mass emission reductions associated with lower-emitting compliance options (e.g., new renewable energy generation or more efficient thermal plant operation). The adjustment is made by:

• Estimating the annual net generation from an achievable amount of qualifying incrementally lower-carbon and zero-carbon generation
• Substituting that generation to displace baseline electricity generation and CO2 emissions from the affected EGUs that have higher emissions
• Replacing fossil steam and natural gas-fired combined-cycle generation with regionally identified incremental (2012 and beyond) potential renewable generation on a pro rata basis corresponding to the baseline mix of fossil generation in each region [13]

To facilitate flexibility in state implementation of the CPP rule, EPA developed both rate-based and mass-based state-specific standards, with states able to choose between the two program types. In so doing, each state must determine whether to apply its emissions reduction requirements to affected EGUs, or to meet the equivalent state-wide CPP rate-based goal or the massbased goal. After choosing the rate-based or mass-based compliance option, states must then choose between: (1) an Emission Standards Plan Type, in which the state places all requirements directly on its affected EGUs, with all requirements federally enforceable; and (2) a State Measures Plan Type, which can include a mix of measures that may apply to affected EGUs and/or other entities, and may lead to CO2 reductions from affected EGUs, but are not federally enforceable. States may use a wide variety of measures to comply with the rate-based standards, including options not assumed by EPA in the calculation of the standard. For example, new nuclear generation, new end-use renewable generation, and incremental demand reductions as a result of energy efficiency can be used as zero-emitting compliance options to offset emissions from affected generators.

Implementation of the CPP rule in AEO2016 reflects four key design choices:

• First, an assumption is made about which type of trading program states choosing interstate cooperation would elect: ratebased or mass-based. Based on a review of the existing literature, including comments made to EPA and in other public forums, a majority of comments (from state regulatory authorities and/or the regulated utilities) suggested a preference for a mass-based trading program. This preference appeared to be based on the states’ familiarity with mass-based (cap and trade) programs and their ability to use mass-based allowance allocation to compensate affected parties, such as ratepayers and energy-intensive industries. The AEO2016 Reference case assumes that all states use the mass-based approach for all sources. In addition to the Reference case, the CPP Rate case assumes rate-based regulation in all states, and the CPP Hybrid case assumes a hybrid approach, in which some states use mass-based regulation and others use rate-based regulation.
• Second, an assumption is made about the level at which states would choose to cooperate (for example, regional, Independent System Operator/Regional Transmission Organization, interconnect, or national). Based on a review of public commentary and analysis, the AEO2016 Reference case assumes trading at the regional level, designed to replicate current power market trading patterns. The CPP Interregional Trading case examines the implications of trading beyond regional boundaries.
• Third, under a mass-based program, there is a need to specify the method by which allowances would be allocated. A review of the literature indicated that over time there has been an evolution in allowance allocation approaches in similar programs that tends to favor the offset of potential increases in electricity rates (for example, allocations to affected electric utilities under California's AB 32 program). The allocation of CPP allowances to load-serving entities in the AEO2016 Reference case is a broad approach with potential to minimize price impacts for consumers. The CPP Allocation to Generators case considers the implications of an allowance auction or allocation directly to generators, which can result in higher price impacts for electricity customers, even as they reduce effective costs for generators.
• Finally, to ensure the integrity of emissions reductions achieved under the program, EPA required states to warrant that their use of mass-based goals does not result in shifts of generation to unaffected sources (leakage). EPA allows states to design their own leakage control policies, or to regulate total mass emissions from both existing and new sources under a single limit for carbon emissions. The AEO2016 Reference case assumes a mass-based program using EPA’s budgets that include new sources (rather than the budgets for existing units only), given that other policies to control for leakage are not yet well specified.

Endnotes

8. U.S. Environmental Protection Agency, "Standards of Performance for Greenhouse Gas Emissions From New, Modified, and Reconstructed Stationary Sources: Electric Utility Generating Units" (Washington, DC: October 23, 2015), https://www.federalregister.gov/articles/2015/10/23/2015-22837/standards-of-performance-for-greenhouse-gas-emissions-from-newmodified-
   and-reconstructed-stationary.
9. U.S. Environmental Protection Agency, "Carbon Pollution Emission Guidelines for Existing Stationary Sources: Electric Utility Generating Units" (Washington, DC: October 23, 2015), https://www.federalregister.gov/articles/2015/10/23/2015-22842/carbon-pollution-emission-guidelines-for-existing-stationary-sources-electric-utility-generating.
10. L. Deniston, SCOTUSBlog, "Carbon Pollution Controls Put On Hold" (Washington, DC: February 9, 2016), http://www.scotusblog.com/2016/02/carbon-pollution-controls-put-on-hold/.
11. U.S. Environmental Protection Agency, "Federal Plan Requirements for Greenhouse Gas Emissions From Electric Utility Generating Units Constructed on or Before January 8, 2014; Model Trading Rules; Amendments to Framework Regulations" (Washington, DC: October 23, 2015), https://www.federalregister.gov/articles/2015/10/23/2015-22848/federal-planrequirements- for-greenhouse-gas-emissions-from-electric-utility-generating-units.
12. As indicated above, the EPA provided an option for certain new and reconstructed baseload CTs to elect between gross outputbased and net output-based standards. For existing sources, EPA elected to specify a net generation basis for the standard.
13. U.S. Environmental Protection Agency, "Carbon Pollution Emission Guidelines for Existing Stationary Sources: Electric Utility Generating Units" (Washington, DC: October 23, 2015), Section IV.B.1 under Table 11, p. 64812, https://www.federalregister.gov/articles/2015/10/23/2015-22842/carbon-pollution-emission-guidelines-for-existing-stationary-sources-electricutility-generating.