Key Differences Between Proposed and Final Rule

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1 CONCORD, MA - WASHINGTON, DC 47 Junction Square Drive Concord, MA MJB&A Summary August 14, 2015 Summary of EPA s Final Standards of Performance for Greenhouse Gas Emissions from New, Modified, and Reconstructed Stationary Sources: Electric Utility Generating Units (the 111(b) rule ) On August 3, 2015, EPA released the final standards of performance for greenhouse gas (GHG) emissions for new, modified, and reconstructed: electric utility generating units (EGUs). This announcement was in conjunction with the announcement of the final carbon rule for existing sources and the proposed federal plan for existing sources. Under authority of Clean Air Act section 111(b), EPA is establishing GHG emissions standards based on EPA s evaluation of the best system of emission reduction (BSER) for affected sources. On June 25, 2013, President Obama issued a Presidential Memorandum requesting that EPA develop a proposal to limit carbon emissions from new power plants. On September 20, 2013, EPA proposed new source performance standards (NSPS) for greenhouse gas (GHG) emissions from new EGUs, 1 and modified and reconstructed EGUs in June The two proposals have been combined in the final rule. All requirements under this rule will be codified in a new subpart TTTT of part 60 of Title 40 of the CFR. Key Differences Between Proposed and Final Rule There are several major differences between EPA s proposed and the final rule. The key changes are highlighted in Table 1 and discussed throughout the summary. Table 1. Key Differences between proposed and final GHG NSPS under 111(b) Issue Proposed Rule Final Rule Covered Sources New fossil fuel-fired utility boilers and IGCC units and natural gas stationary combustion units greater than 25 MWe and that supply at least 1/3 of output to the electric grid (on a three-year rolling average basis for natural gas stationary combustion units) and that combust fossil fuels for more than 10% heat input during any 3 consecutive calendar years. Modified and reconstructed fossil fuel-fired electric steam generating units (utility boilers and IGCC units) and natural gas-fired stationary combustion turbines. Newly constructed, modified, and reconstructed fossil fuel-fired utility boilers and IGCC units and newly constructed and reconstructed stationary combustion turbines. Covered EGUs must be capable of combusting more than 250 MMBtu/h heat input of fossil fuel, and supply a generator capable of providing greater than 25 MW net to a utility distribution system. 1 As a part of its September 2013 proposal, EPA withdrew the earlier April 2012 proposal. M.J. Bradley & Associates, LLC Strategic Environmental Consulting Page 1

2 Issue Proposed Rule Final Rule Best System of Emission Reduction Performance Standard Fossil fuel-fired electric utility steam generating units New: coal boiler with partial carbon capture and storage (CCS) Modified: most efficient demonstrated generating technology for these units Reconstructed: most efficient demonstrated generating technology for these units Stationary combustion turbines New: efficient NGCC technology Modified: efficient NGCC technology Reconstructed: efficient NGCC technology Fossil fuel-fired electric utility steam generating units New: 1,100 lb CO2/MWh gross over a 12- operating month period; or 1,050 lb CO2/MWh gross over a 7-year period Modified: 1,900 lb CO2/MWh-net for sources with heat input > 2,000 MMBtu/h; or 2,100 lb CO2/MWh-net for sources with heat input < 2,000 MMBtu/h. Reconstructed: 1,900 lb CO2/MWh-net for sources with heat input > 2,000 MMBtu/h; 2,100 lb CO2/MWh-net for sources with heat input < 2,000 MMBtu/h Stationary combustion turbines: New: 1,000 lb CO2/MWh gross for units > 850 MMBtu/hr (approximately 100 MWe) New: 1,100 lb CO2/MWh gross for units 850 MMBtu/hr (approximately 100 MWe) Fossil fuel-fired electric utility steam generating units New: highly efficient supercritical pulverized coal (SCPC) boiler implementing partial CCS technology Modified: unit-specific emission limitation consistent with each modified unit s best oneyear historical performance Reconstructed: most efficient demonstrated generating technology for these units Stationary combustion turbines Base load natural gas-fired: use of efficient NGCC technology Non-base load natural gas-fired: use of clean fuels (i.e., natural gas with an allowance for a small amount of distillate fuel) Multi-fuel-fired: use of clean fuels (e.g., natural gas, ethylene, propane, naptha, jet fuel kerosene, distillate oils 1 and 2, biodiesel, and landfill gas) New, modified and reconstructed fossil fuel-fired electric utility steam generating units New: 1,400 lb CO2/MWh gross Modified: best annual performance demonstrated from 2002 to date for large modifications (modifications resulting in an increase in hourly CO2 emissions of more than 10 percent); withdrawing proposed standard and delaying standard for small modifications Reconstructed (large): 1,800 lb CO2/MWh gross for sources with heat input > 2,000 MMBtu/h Reconstructed (small): 2,000 lb CO2/MWh gross for sources with heat input < 2,000 MMBtu/h New and reconstructed stationary combustion turbines Base load natural gas-fired: 1,000 lb CO2/MWh gross for all sizes of base load units, calculated M.J. Bradley & Associates, LLC Strategic Environmental Consulting Page 2

3 Issue Proposed Rule Final Rule Excluded Sources Modified: 1,000 lb CO2/MWh-gross for sources with heat input > 850 MMBtu/h; 1,100 lb CO2/MWh-gross for sources with heat input < 850 MMBtu/h Reconstructed: 1,000 lb CO2/MWh-gross for sources with heat input > 850 MMBtu/h; 1,100 lb CO2/MWh-gross for sources with heat input < 850 MMBtu/h New Liquid oil-fired stationary combustion turbines Three specifically exempted projects: Wolverine (Michigan), Washington County EGU (Georgia), and Holcomb EGU (Kansas) Low capacity-factor (<33%) EGUs Modified and reconstructed New units subject to the January 2014 proposal under 111(b) Existing units subject to June (d) proposal that are not modified or reconstructed, as defined Natural gas combustion turbines that do not meet sales and utilization thresholds Oil-fired stationary turbines on a 12-operating month rolling average basis; optional 1,030 lb CO2/MWh net Non-base load natural gas-fired: 120 lb CO2/MMBtu, calculated on a 120 operating month rolling average basis Multi-fuel-fired: lb CO2/MMBtu, calculated on a 12-operating month rolling average basis Units capable of burning 50 percent or more non-fossil fuel, so long as they are subject to a federally enforceable permit that limits their use of fossil fuels to 10 percent or less of their heat input capacity on an annual basis A CHP unit will be an affected unit unless it is subject to a federally enforceable permit that limits annual total electric sales to less than or equal to the unit s design efficiency multiplied by its potential electric output or 219,000 MWh, whichever is greater Combustion turbines that are physically incapable of burning natural gas Municipal waste combustors and commercial or industrial solid waste incinerators Applicability EGUs affected by this rule are steam generating units (utility boiler or IGCC) and stationary combustion turbines (simple cycle and combined cycle) with a base load rating greater than 250 MMBtu/h of fossil fuel and serve a generator capable of supplying more than 25 MW-net to the grid. General Applicability In the final rule, EPA applies the emissions standards to new, modified, and reconstructed electricity utility steam generating units and new and reconstructed combustion turbines defined as follows: New sources are defined as a newly constructed fossil fuel-fired power plant commencing construction on or after January 8, Modified units under the rule are existing steam generating units that undergo a large modification defined as any physical or operational change on or after June 18, 2014 that increases hourly CO2 emissions by more than 10 percent an hour compared to the source s highest hourly emission in the previous five years. Steam generating units that undergo small modifications will not be considered an affected unit under section 111(d). EPA is not finalizing a M.J. Bradley & Associates, LLC Strategic Environmental Consulting Page 3

4 standard for modified stationary combustion turbines under 111(b). Accordingly, modified combustion turbines will remain applicable as existing units subject to 111(d), as applicable. Reconstructed sources are existing steam generating or combustion turbine sources that on or after June 18, 2014 have: (1) made changes to the unit that exceed 50 percent the expected capital cost of a new comparable facility, and (2) are technologically and economically feasible to meet the applicable standards. 2 Turbine-Specific Applicability In the final rule, EPA finalized three subcategories for combustion turbines based on a percentage electric sales threshold and natural gas use criterion. The subcategories are: (1) base load, (2) non-base load, and (3) multi-fuel-fired units. Base load natural gas-fired units include those stationary combustion turbines capable of burning over 90 percent natural gas (based on a 12-operation month rolling average) and sell electricity in an amount greater than their design efficiency multiplied by their potential electric output (based on 12-operting month and 3-year rolling average). Non-base load natural gas-fired units refer to those burning over 90 percent natural gas (12-operation month rolling average) and have net-electric sales less than or equal to their design efficiency multiplied by their potential electric output (based on 12-operting month and 3-year rolling average). Multi-fuel-fired stationary units are those that are connected to a natural gas pipeline but burn a fuel other than natural gas for at least 10 percent of the unit s heat input capacity based on a 12-operating-month rolling average basis. In distinguishing between base load and non-base load combustion turbines, EPA finalized a sliding scale approach to determining a unit-specific threshold based on each unit s design efficiency. To calculate the sliding scale, the unit s design efficiency is multiplied by its potential electric output. For example, a simple cycle turbine with a design efficiency of 35 percent would need to keep its electric sales below 35 percent times its potential electric output in order to remain classified as a non-base load turbine. This sliding-scale approach is expected to allow more efficient non-base load turbines to sell more electricity before needing to comply with NSPS requirements. Exempted Units Sources not covered under this rule include: (1) non-fossil units, (2) industrial CHP units, (3) stationary combustion turbines not physically capable of combusting natural gas (not connected to a natural gas pipeline), (4) municipal waste combustors and commercial and industrial solid waste incinerators, and (5) certain projects under development. The exemption for non-fossil units applies to those units capable of burning 50 percent or more non-fossil fuel and are subject to federal permits that limit their use of fossil fuels to ten percent or less of heat input capacity on an annual basis. Exempted industrial CHP units are those with federally enforceable permits limiting annual net-electric sales to no more than the unit s design efficiency multiplied by its potential electric output or 219,000 MWh or less (whichever is greater). Other CHPs not meeting the industrial exemption are covered by the rule. EPA identified specific projects under development that are categorically exempted from this rule but will be subject to unit-specific permitting if and when construction commences. Best System of Emission Reduction and Performance Standards EPA determined the final standards of performance by identifying BSER for each category of affected units. Below is a summary of the rationale behind the BSER determination for new, modified, and reconstructed steam generating units and new and reconstructed stationary combution turbines. New Steam Generating Units EPA determined BSER for new steam generating units as a highly efficient supercritical pulverized coal (SCPC) boiler using partial post-combustion carbon capture and storage (CCS) technology to the degree necessary to meet a final emission limit of 2 In the proposed federal plan for existing sources, EPA is seeking comment on the proposal that if an existing source is subject to a state plan under 111(d), and then undertakes a modification or reconstruction, the source subject to the state plan, will become subject to the modification or reconstruction requirements under 111(b) and no longer be subject to the state plan. M.J. Bradley & Associates, LLC Strategic Environmental Consulting Page 4

5 1,400 lb CO2/MWh-gross. EPA estimates that this standard can be achieved by capturing and storing approximately 16 percent of the CO2 produced at a bituminous plant and 23 percent of the CO2 produced at a subbituminous or dried lignite plant. Although EPA uses the same methodology as the proposal, the final emission standard is less stringent than the proposed 1,100 lb CO2/MWh gross standard. EPA notes that the decrease in stringency is due to updated cost assumptions for partial CCS and other electric generation technologies. Using DOE/NETL and EIA AEO cost data, EPA found the cost of a new SCPC unit with partial CCS to be comparable with the cost of new base load generating technologies, other than NGCC, such as nuclear. EPA projects that the addition of partial CCS increases the capital cost of a new highly efficient SCPC unit by around 21 percent and that this cost increase is in line with cost increases of past NSPS requirements. In addition to its assessment of costs, EPA finds that the capture and storage of CO2 has been demonstrated in full-scale operations and is, therefore, technically feasible as the basis of the standard. In addition to implementing partial CCS on a new coal-fired boiler, EPA also identifies alternatives for compliance including building a new IGCC unit to co-fire with natural gas (or use pre-combustion carbon capture on a slip-stream), or for a supercritical utility boiler to co-fire with natural gas. These alternatives allow affected units to meet with the standard without implementation of partial CCS. Modified Steam Generating Units EPA determined BSER for modified steam generating units as each modified unit s best one-year historical performance from 2002 to the time of modification. EPA withdrew its proposed standard for modifications resulting in hourly CO2 increases of less than or equal to 10 percent. Reconstructed Steam Generating and IGCC Units EPA finalized BSER for reconstructed steam generating units as the most efficient demonstrated generating technology available for the unit. EPA finalized BSER for large units (sources with a heat input rating of greater than 2,000 MMBtu/h) based on SCPC or supercritical circulating fluidized bed (CFB) boiler techniques with a performance standard at 1,800 lb CO2/MWh-gross. For small units (sources with a heat input rating of less than or equal to 2,000 MMBtu/h), EPA bases BSER on subcritical boiler technology with a final performance standard of 2,000 lb CO2/MWh-gross. Reconstructed units will not be required to meet the performance standards if it is not technologically and economically feasible. If deemed infeasible, a case-by-case determination can be made for appropriate BSER, with consideration of the finalized and proposed approaches. Base Load Natural Gas-Fired Stationary Combustion Turbines EPA finalized NGCC technology as BSER for base load natural gas-fired stationary combustion turbines and set the performance standard at 1,000 lb CO2/MWh-gross, calculated on a 12-operating month rolling average basis. EPA applies the final standard to all sizes of base load units unlike the proposal that would have set a less stringent standard for smaller units (units less than or equal to 850 MMBtu/h). In its supporting analysis, EPA concluded that there is no clear break in NGCC unit sizes to distinguish between small and large units and that most existing small units already have emissions rates below the final standard. Non-Base Load Natural Gas-Fired Stationary Combustion Turbines In the final rule, EPA determined that the standard for non-base load combustion turbines to be the use of clean fuels, particularly natural gas with an allotment for distillate oil. The standard is 120 lb CO2/MMBtu calculated on a 12-operatingmonth rolling average basis. Natural gas has an input-based emissions rate of 117 lb CO2/MMBtu, meaning that units burning natural gas will automatically comply. EPA ruled out fast-start NGCC and high-efficiency simple cycle turbines as BSER due to costs and lack of data available for these technologies. EPA noted that many non-base load turbines run less than 10 percent of the time and do not provide ramping capability, thus making fast-start NGCC and high-efficiency simple cycle technologies costly alternatives for these applications. Multi-Fuel-Fired Stationary Combustion Turbines EPA determined BSER for multi-fuel-fired combustion turbines to be use of clean fuel (natural gas, ethylene, propane, naptha, jet fuel kerosene, distillate oils 1 and 2, biodiesel, and landfill gas) with a standard at 120 to 160 lb CO2/MMBtu calculated on M.J. Bradley & Associates, LLC Strategic Environmental Consulting Page 5

6 a 12-operating-month rolling average. EPA ruled out NGCC and high-efficiency simple cycle technologies as BSER for multifuel-fired turbines based on cost and potential technical constraints. Costs and Benefits EPA presumes that this rule will have negligible costs and benefits. EPA s modeling shows that most utilities will be constructing new EGUs, primarily natural gas-fired turbine technologies, in compliance with these standards based on underlying economic conditions, with no additional costs due to compliance. For this same reason, emissions reductions expected with the implementation of this rule through 2022 will be negligible compared to baseline levels, but will limit emissions from further contributing to climate change. Summary of Other Final Requirements Startup, Shut down and Malfunction In the final rule, startup and shutdown periods are included in the compliance calculation as periods of partial load. The final method to calculate compliance is to sum the emissions for all operating hours and divide that value by the sum of the electric energy output over a rolling 12-operating-month period. For compliance, sources must incorporate emissions from all periods, including startup or shutdown, during which fuel is combusted and emissions are being monitored. EPA did not consider emissions that result from EGU malfunction into the emission performance standards, as malfunctions are expected to be minimal over the 12-operating month period, would be difficult to account for, and would most likely not result in a violation of the emissions standard. Demonstrating Compliance and Emissions Performance Testing Compliance with applicable emissions standards will be demonstrated on a 12-operating month rolling average basis. Data to determine compliance will be generated from certified Part 75 monitoring systems. In determining hourly CO2 mass emissions rates (tons/hr), owners and operators of solid fossil fuel-fired EGUs must utilize continuous emission monitoring systems (CEMS) for measurement of CO2 concentration, stack gas flow rate, and stack gas moisture content if necessary. Owners and operators of fossil fuel-fired EGUs using gaseous or liquid fuels can install fuel flow meters instead of CEMS. EGU owners and operators are required to monitor hourly operating time and gross output (electrical output plus any mechanical output plus 75 percent of any useful thermal output) expressed as megawatt hours. EPA finalized performance testing requirements consistent with part 75 requirements. Traditional stack tests are not required for this rule. Reporting and Recordkeeping The final rule requires owners and operators of affected EGUs to submit a monitoring plan. All monitoring devices used to calculate CO2 emissions rates must be certified according to 40 CFR and section 6 of part 75, appendix A within the 180- day time period. These systems also must meet associated on-going quality assurance procedures in appendices B and D of part 75. Data collection is to begin after the monitoring systems are certified. Operators are to report the 12-operating-month rolling average rate rounded to three significant figures if the emission standard is greater than or equal to 1,000. Rates less than 1,000 are to be rounded to two significant figures. EPA streamlined reporting requirements with part 75. Under this rule, the EGU operator must follow notification requirements of 40 CFR 75.61, 40 CFR 60.7 (a)(1) and (a)(3), and 40 CFR Recordkeeping must also meet the requirements in subpart F of part 75. Operators using CEMS must keep records of hourly CO2 concentration, stack gas flow rate, stack gas moisture content, unit operating time, and gross electric generation. Records showing calculations to determine average CO2 mass emissions and gross output for each operating month, as well as average CO2 mass emissions rates and percentage of valid CO2 mass emission rates for each compliance period should be kept for three years. Further, all owners of affected EGUs must submit electronic emissions reports on a quarterly basis according to subpart G of part 75. M.J. Bradley & Associates, LLC Strategic Environmental Consulting Page 6

7 Contacts For more information on this topic please contact: Robert LaCount Executive Vice President (202) Chris Van Atten Senior Vice President (978) About Us MJB&A provides strategic consulting services to address energy and environmental issues for the private, public, and nonprofit sectors. MJB&A creates value and addresses risks with a comprehensive approach to strategy and implementation, ensuring clients have timely access to information and the tools to use it to their advantage. Our approach fuses private sector strategy with public policy in air quality, energy, climate change, environmental markets, energy efficiency, renewable energy, transportation, and advanced technologies. Our international client base includes electric and natural gas utilities, major transportation fleet operators, investors, clean technology firms, environmental groups and government agencies. Our seasoned team brings a multi-sector perspective, informed expertise, and creative solutions to each client, capitalizing on extensive experience in energy markets, environmental policy, law, engineering, economics and business. For more information we encourage you to visit our website, M.J. Bradley & Associates, LLC Strategic Environmental Consulting Page 7

The Clean Power Plan NJ Clean Air Council Meeting

M.J. Bradley & Associates The Clean Power Plan NJ Clean Air Council Meeting D E C E M B E R 9, 2 0 1 5 DRAFT FOR DISCUSSION PURPOSES ONLY Chris Van Atten vanatten@mjbradley.com (978) 369 5533 / www.mjbradley.com