Republican members of a House subcommittee may be bringing up the fact at an Oct. 7 hearing to U.S. EPA official Janet McCabe that EPA’s CO2-reducing plan for new power plants calls for CO2 capture from new coal-fired plants and that no commercial demonstration projects for carbon-capture technology on such plants yet exist in the U.S.
On Oct. 7, the Subcommittee on Energy and Power of the House Energy and Commerce Committee will hold a hearing entitled “EPA’s CO2 Regulations for New and Existing Power Plants.” McCabe, the Acting Assistant Administrator of Air and Radiation for EPA, is to be the only witness.
A subcommittee staff memo on the hearing, released Oct. 5 by the panel’s GOP majority, noted that on Aug. 3, EPA announced two final rules and a third proposed rule to regulate CO2 emissions from new and existing fossil fuel-fired power plants. The rules are being promulgated under the President’s Climate Action Plan and a Presidential Memorandum, which directs the EPA to develop new regulations for power plants under section 111 of the Clean Air Act (CAA).
“The rules exceed 3,000 pages and have not yet been published in the Federal Register,” the memo said. “Section 111 of the CAA authorizes the Administrator of EPA, under certain circumstances, to establish standards of performance under section 111(b) for new stationary sources, and to issue guidelines under section 111(d) for existing stationary sources. Such regulations are referred to by the agency as ‘New Source Performance Standards’ and ‘Existing Source Performance Standards.'”
The memo says about each rule:
Final Rule for New Plants (a/k/a “111(b) Rule”)
In its final rule for new fossil fuel-fired plants,5 EPA establishes separate CO2 standards for natural gas-fired and coal-fired electric generating units. For new coal-fired plants, the rule determines that the “best system of emissions reduction” (BSER) is based on the performance of a natural gas combined cycle (NGCC) unit, and the agency sets a standard of 1,000 pounds of CO2 per megawatt-hour on a gross-output basis (lb CO2/Mw-gross). For new coal-fired units, the rule determines that the BSER is based on the performance of a supercritical pulverized coal utility boiler implementing partial carbon capture and storage (CCS) and sets a standard of 1,400 lb CO2/Mw-gross.
“There are currently no full-scale coal-fired power plants in commercial service in the United States that have installed and operated the CCS technologies necessary to comply with the rule,” the memo said. “The only operating power plant unit using CCS cited by the agency is a Canadian government funded, small-scale 110 megawatt (MW) unit, retrofitted to an existing plant, for enhanced oil recovery in the province of Saskatchewan, Canada. Concerns have been raised that a standard based on CCS would constitute a de facto ban on the construction of new coal-fired power plants in the United States, including the most state-of-the art coal-fired units presently under construction in other nations.
Final Rule for Existing Plants (a/k/a “Clean Power Plan” or “111(d) Rule”)
In its final rule for existing fossil fuel-fired plants, EPA establishes mandatory CO2 emissions “goals” for each state’s electricity sector, including “interim” goals beginning in 2022 (separated into three steps in 2022-2024, 2025-2027, and 2028-2029), and a “final” goal in 2030. The mandatory goals are expressed in terms of statewide rate-based and mass-based CO2 emissions goals.
The goals are calculated based on 2012 emissions data, and EPA has prepared “State Specific Fact Sheets” and a Table estimating the percentage reductions from 2012 CO2 emissions.
For existing fossil fuel-fired electric generating units, EPA has determined that three “building blocks” reflect the BSER, including: heat rate improvements at existing coal units; shifting from coal-fired generation to generation from existing NGCC units; and shifting from coal-fired generation to generation from renewables, primarily wind and solar.
EPA calculates state goals based on this BSER, and has developed separate emissions performance rates for coal and natural gas plants, including an interim emissions rate for existing coal units of 1,534 lbs CO2 per Net MWh and a final rate of 1,305 lbs CO2 per Net MWh, and an interim emissions rate for existing natural gas units of 832 lbs CO2 per Net MWh and the final rate is 771 lbs CO2 per Net MWh.
Under the rule, states would be required to submit detailed plans to meet their mandatory CO2 goals. State plans must be either “rate-based” or “mass-based” and take an “emissions standards approach,” or alternatively a “state measures approach.” States may submit individual or multi-state plans, and are encouraged to use emissions trading, and develop plans that will make their affected units “trading ready.”
The final rule includes detailed provisions relating to development and implementation of state plans, including provisions relating to state measures, Emission Rate Credits (ERCs), allowances, emissions trading, demonstrations, monitoring and verification requirements, and recordkeeping and reporting requirements.
The rule includes an optional “Clean Energy Incentive Program” under which states would award early action ERCs for eligible renewable energy or demand-side energy efficiency projects that generate megawatt hours or reduce energy demand during 2020 and 2021. The rule also includes provisions restricting the construction of new natural gas plants as a compliance measure.
Under the rule, states must submit plans by Sept. 6, 2016, with the possibility of a two-year extension to be granted at the discretion of the agency. In the event that a state fails to submit a satisfactory plan, the EPA would impose a yet to be finalized “Federal Plan.”
Accompanying the final 111(d) rule is a proposed rule setting forth two approaches to the “Federal Plan” that EPA would implement in any state that does not submit an approvable state plan. For this “Federal Plan,” the agency proposes both a rate-based trading program and a mass-based trading program, but intends to finalize only a single approach. These proposals also constitute proposed “Model Trading Rules” that would be “presumptively approvable” for inclusion in state plans, the memo explained. The proposed rule also includes revisions to the agency’s current regulations for implementing section 111(d), including provisions relating to the disapproval of state plans.
In the Regulatory Impact Analysis (RIA) accompanying the final 111(d) rule, EPA estimates costs to range from $1.4 billion to $2.5 billion in 2020, $1.0 billion to $3.0 billion in 2025, and $5.1 billion to $8.4 billion in 2030. In developing these estimates, EPA assumes investments in demand side energy efficiency of $2.1 billion to $2.6 billion in 2020, $16.7 billion to $20.6 billion in 2025 and $26.3 billion to $32.5 billion in 2030. These additional costs are offset by projected reductions in electricity demand of up to 7.8% by 2030, according to the agency.
According to EPA’s estimates, natural gas use in the power sector may decline by as much as 4.5% over the base case in 2030, and coal production for the electric power sector declines by as much as 17% by 2025.
The GOP staff memo said that the following issues relating to EPA’s regulations may be examined at the hearing:
- Legal, timing, implementation and compliance issues;
- Potential impacts on states, local governments, and affected entities;
- Potential impacts on electricity rates and reliability; and
- Potential impacts on electricity markets.
The full House of Representatives on June 24 approved H.R. 2042, the Ratepayer Protection Act, by a vote of 247-180. The act, which if enacted would severely cripple the U.S. Environmental Protection Agency in imposing its Clean Power Plan for existing power plants, was introduced by House Energy and Power Subcommittee Chairman Ed Whitfield, R-Ky., Rep. Sanford Bishop, D-Ga., Rep. Morgan Griffith, R-Va., and Rep. Collin Peterson, D-Minn. It is Whitfield’s subcommittee that will hold the Oct. 7 hearing.