Output-Based Regulations:
A Handbook for Air Regulators
U.S. Environmental Protection Agency
Combined Heat and Power Partnership
August 2014
iiCHP
3EPA COMBINED HEAT ANO
POWER PARTNERSHIP
FINAL REPORT
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This handbook was prepared by ICF International and ERG Inc., under contract to the U.S. Environmental
Protection Agency. The Combined Heat and Power Partnership (CHPP) would like to thank Rich Sedano
and Rick Weston of the Regulatory Assistance Project and Christian Fellner of EPA's Office of Air Quality
Planning and Standards for their thoughtful review of the handbook.
Output-Based Regulations:
A Handbook for Air Regulators
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Table of Contents
EXECUTIVE SUMMARY 1
What is an output-based regulation? 1
Why adopt output-based regulations? 1
How do I develop an output-based emission standard? 2
How do I comply with an output-based emission standard? 3
Who has developed output-based regulations? 3
Section 1. Introduction 1-1
1.1 Purpose of the Handbook 1-1
1.2 Trends Supporting Increased Use of Output-Based Regulation 1-2
1.3 Using the Handbook 1-3
Section 2. What Is An Output-Based Regulation? 2-1
2.1 Output-Based Units of Measure 2-1
2.2 Output-Based Standards Under the Clean Air Act 2-1
Section 3. Why Adopt Output-Based Regulations? 3-1
3.1 Emission Reduction Benefits of Output-Based Regulation 3-1
3.1.1 Output-Based Emission Standards 3-1
3.1.2 Output-Based Allowance Allocations in Emission Trading Programs 3-4
3.2 Cost Reductions from Output-Based Regulations 3-6
3.3 Output-Based Format as a Measure of Environmental Performance 3-7
3.4 Output-Based Regulation and Combined Heat and Power Applications 3-8
3.4.1 What Is Combined Heat and Power? 3-8
3.4.2 What Are the Benefits of Combined Heat and Power? 3-9
Section 4. How Do I Develop An Output-Based Emission Standard? 4-1
4.1 Develop the Output-Based Emission Limit 4-1
4.1.1 Conversion from Input-Based Emission Limit (lb/MMBtu/heat input) 4-1
4.1.2 Conversion from Flue Gas Concentration Limit (ppmv) 4-4
4.1.3 Conversion from Emission Limit Based on Mechanical Power (g/bhp-hr) 4-4
4.2 Specify a Gross or Net Energy Output Format 4-5
4.3 Specify Compliance Measurement Methods 4-6
4.4 Specify How to Calculate Emission Rates for Combined Heat and Power Units 4-6
4.5 Summary of Steps to Develop an Output-Based Standard 4-10
4.6 Summary of Steps to Comply with an Output-Based Standard 4-11
Section 5. Examples of Output-Based Regulations 5-1
5.1.1 Units of Measure 5-3
5.1.2 Net Versus Gross Energy Output 5-3
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Table of Contents (Continued)
5.1.3 Selection of the Emission Limit for New Units 5-4
5.1.4 Modified and Reconstructed Units 5-5
5.1.5 Treatment of Combined Heat and Power Plants 5-6
5.1.6 NSPS C02 Limits 5-6
5.2 RAP National Model Emission Rule for Distributed Generation 5-7
5.2.1 Format of the Rule 5-7
5.2.2 Treatment of Combined Heat and Power 5-8
5.3 EPA Guidance on Output-Based N0X Allowance Allocations 5-8
5.3.1 Allocation of Allowances 5-9
5.3.2 Availability, Measurement, and Reporting of Output Data 5-9
5.4 Utility Boiler Maximum Achievable Control Technology Standards 5-11
5.4.1 Allocation of Allowances 5-11
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List of Appendices
Appendix A: Energy Conversion Factors A-l
Appendix B: Existing Output-Based Regulations B-l
B.l Conventional Emission Rate Limit Programs B-l
B.l.l New Source Performance Standards for Utility Boilers B-l
B.1.2 New Source Performance Standards for Stationary Combustion Turbines B-l
B.1.3 New Jersey Mercury Emission Limitations B-2
B.1.4 Mercury MATS B-3
B.2 Regulations for Distributed Generation B-3
B.2.1 New Hampshire Emission Fee B-3
B.2.2 California Senate Bill 1298 Regulations for Distributed Generation B-4
B.2.3 Delaware Small Distributed Generation Rule B-8
B.2.4 Rhode Island Distributed Generation Rule B-8
B.2.5 Texas Standard N0X Permit for Distributed Generation B-8
B.2.6 Texas Permit by Rule B-9
B.2.7 Regulatory Assistance Project Model Rule for Distributed Generation B-10
B.2.8 Connecticut Air Pollution Regulations 22a-174-42 B-ll
B.2.9 Maine Permit for Small-Scale Electric Generators B-12
B.2.10 Massachusetts Draft 310 CMR 7.26 Engines and Combustion Turbine Certification
Standards B-l 3
B.2.11 NewYork6 NYCRRPart222 Emissions from Distributed Generation B-14
B.3 Allowance Allocation in Emission Trading Programs B-15
B.3.1 Arkansas B-16
B.3.2 Connecticut B-16
B.3.3 Illinois B-17
B.3.4 Indiana B-17
B.3.5 Massachusetts B-17
B.3.6 Missouri B-17
B.3.7 New Hampshire B-18
B.3.8 New Jersey B-18
B.3.9 New York B-18
B.3.10 Ohio B-19
B.3.11 Pennsylvania B-19
B.3.12 Wisconsin B-19
B.4 State Multi-Pollutant Programs B-19
B.4.1 Massachusetts Multi-Pollutant Program B-19
B.4.2 New Hampshire Multi-Pollutant Program B-21
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List of Appendices
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List of Appendices (Continued)
B.5 Emission Performance Standards B-22
B.5.1 California B-23
B.5.2 New York B-23
B.5.3 Oregon B-24
B.5.4 Washington B-24
B.5.5 NSPS for New Power Plants B-24
B.5.6 Proposed NSPS for New Stationary EGUs, Section 111(b) of the CAA B-25
B.5.7 Boiler MACT Regulations B-26
B.6 New Source Review B-27
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List of Tables
Table ES-1. Current Output-Based Treatment of CHP 4
Table 2-1. Output-Based Units of Measure 2-1
Table 3-1. Design Flexibility Offered by Output-Based Standard 3-7
Table 3-2. Conventional and Output-Based Measurements for Electricity Generation 3-8
Table 3-3. Typical P/H Ratios for Common CHP Technologies 3-9
Table 4-1. Displaced Boiler Emission Rate (lb/MWheiectnc) for CHP Units 4-9
Table 4-2. Summary of Rule Development Steps 4-10
Table 5-1. List of Current Output-Based Programs 5-1
List of Tables (Appendices)
Table B-l. 2003 California Distributed Generation Certification Standards (lb/MWh) B-5
Table B-2. 2007 California Distributed Generation Fossil Fuel Emission Standards (lb/MWh) B-5
Table B-3. 2007 California Distributed Generation Waste Gas Emission Standards (lb/MWh) B-5
Table B-4. CARB BACT Guidance for Small Combustion Turbines* B-7
Table B-5. CARB BACT Guidance for Reciprocating Engine Generators* B-7
Table B-6. TCEQ Standard Permit for NOx from DG B-9
Table B-7. TCEQ PBR for CHP B-9
Table B-8. RAP Model Rule Emission Limits (lb/MWh) B-10
Table B-9. Connecticut Emission Standards for New Distributed Generators B-ll
Table B-10. Connecticut Emission Standards for Existing Distributed Generators B-ll
Table B-ll. Maine Emission Standards for Non-Emergency Generators B-12
Table B-12. Massachusetts Emission Limits for Emergency Engines and Turbines B-13
Table B-13. Massachusetts Emission Limits for Non-Emergency Engines B-13
Table B-14. Massachusetts Emission Limits for Non-Emergency Turbines B-14
Table B-15. CO2 Emission Limitations—Engines and Turbines B-14
Table B-16. Proposed NOx Emission Limits B-15
Table B-17. Massachusetts Multi-Pollutant Program Emission Limits B-20
Table B-18. Massachusetts' Proposed Mercury Emission Regulations B-21
Table B-19. NESCAUM Model Rule Emission Performance Standards B-23
List of Figures
Figure 3-la. Benefits of Output-Based Regulation 3-3
Figure 3-lb. Benefits of Output-Based Regulation 3-3
Figure 3-2. Two Typical CHP Configurations 3-9
Figure 3-3. Efficiency Benefits of CHP 3-10
Figure 3-4. Emission Benefits of CHP 3-11
A Handbook for Air Regulators
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EXECUTIVE SUMMARY
The Combined Heat and Power Partnership (CHPP), within the U.S. EPA's Climate Protection
Partnerships Division (CPPD), developed this handbook. CPPD's voluntary partnerships work to increase
the understanding of the full range of greenhouse gas (GHG) and air quality benefits provided by energy
efficiency and clean energy production. Output-based regulations can help air regulators incorporate
these benefits into their programs.
The CHPP is a voluntary program that reduces the environmental impact of power generation by
fostering the use of CHP. CHP, also known as cogeneration, produces both heat and electricity from a
single heat input. CHP is a more efficient, cleaner, and more reliable alternative to conventional
generation. The partnership works closely with the CHP industry, state and local governments, and other
stakeholders to develop tools and services to support the development of new CHP projects and
recognize their energy, environmental, and economic benefits. The use of output-based regulations is a
tool that can foster the expansion of CHP.
This handbook was developed to assist air regulators in developing emission regulations that recognize
the pollution prevention benefits of efficient energy generation technologies. It is also intended to help
CHP project owners better understand and comply with output-based environmental regulations. Clean
energy technologies prevent pollution by using less fuel and, thus, reducing associated emissions.
Output-based regulations encourage energy efficiency by relating emissions to the productive output of
the process, not to the amount of fuel burned.
While output-based regulations have been used for many industries, boilers and power generation
sources have traditionally been regulated through input-based regulations. This has been changing
recently, though, as regulators seek to promote air emission reductions and provide more compliance
flexibility to combustion sources.
The CHPP developed this handbook to assist state, local, and tribal regulators in developing output-
based regulations. The handbook provides practical information to help regulators decide if they want
to use output-based regulations and explains how to develop an output-based emission standard.
What is an output-based regulation?
Output-based regulations include output-based emission standards as well as output-based allocations
of emission allowances within a cap and trade program. An output-based emission standard relates
emissions to the productive output of the process. Output-based emission standards use units of
measure such as lb emission/MWh generated or lb emissions/MMBtu of steam generated, rather than
heat input (Ib/MMBtu) or pollutant concentration (ppm). In a cap and trade program, emission
allowances can be allocated to energy generation sources based on energy output (e.g., electricity or
steam generated) rather than fuel burned (i.e., heat input).
Why adopt output-based regulations?
The primary benefit of output-based regulations is that they encourage efficiency and pollution
prevention. More efficient combustion technologies benefit from the use of output-based regulations.
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Executive Summary
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The use of these technologies reduces fossil fuel use and leads to multi-media reductions in the
environmental impacts of the production, processing, transportation, and combustion of fossil fuels. In
addition, reducing fossil fuel combustion is a pollution prevention measure that reduces emissions of all
products of combustion, not just the target pollutant of a regulatory program.
Another benefit is that output-based standards allow sources to use energy efficiency as part of their
emission control strategy. Allowing energy efficiency as a control measure provides regulated sources,
either existing or new, with an additional compliance option that can lead to reduced compliance costs
as well as lower emissions. Input- or concentration-based standards do not provide this option.
In a cap and trade program, states can design an output-based allowance allocation system to
accomplish a number of environmental objectives. For example, a program that periodically updates
output-based allocations encourages increased energy efficiency because sources vie for a larger share
of the allocations. A program that allocates output-based allowances to non-emitting electricity
generators during these periodic updates provides a financial incentive for the introduction of
renewable energy sources, such as wind power. EPA developed guidance for states on how to develop
output-based allocations under the NOx Budget Trading Program in May 2000,1 and the CHPP has more
recently issued whitepapers and other assistance primarily to help state regulators better understand
output-based regulations and navigate the process of developing such standards. In addition to this
guide, the CHPP issued Accounting for CHP in Output-Based Regulations2 in February 2013 and Output-
Based Environmental Regulations: An Effective Policy to Support Clean Energy Supply3 in September
2011.
How do I develop an output-based emission standard?
Several decisions must be made about the format of the rule. Making these decisions involves trade-offs
between the degree to which the rule will account for the benefits of energy efficiency, the complexity
of the rule, and the ease of measuring compliance.
The steps for developing an output-based emission standard are:
• Develop the output-based emission limit. The method that is used will depend on whether or
not measured energy output data are available.
• Specify a gross or net energy output format. Net energy output more comprehensively
accounts for energy efficiency, but can increase the complexity of compliance monitoring
requirements.
• Specify compliance measurement methods. Output-based standards require designating
methods for monitoring electrical, thermal, and mechanical outputs. Instruments to
continuously monitor and record energy output are routinely used and are commercially
available at a reasonable cost.
1 EPA. 2000. Developing and Updating Output-Based NOx Allowance Allocations: Guidance for States Joining the NOx Budget
Trading Program Under the NOxSIP Call, http://www.epa.gov/airmarkets/progsregs/nox/docs/finaloutputguidanc.pdf.
2 http://www.epa.gov/chp/resources.html.
3 http://epa.gov/chp/documents/output_based_regs_fs.pdf.
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• Specify how to calculate emission rates for CHP units. For CHP units, the standard must account
for multiple energy outputs. This handbook describes two typical approaches.
How do I comply with an output-based emission standard?
• Determine compliance procedures. Compliance forms, permit forms, or other necessary
documentation must be obtained. The output-based methodology that is used will depend on
whether measured energy output data are available.
• Determine the data necessary for compliance. Review the compliance calculation and other
inputs to determine what data are needed to calculate the emission limit from the CHP system.
Electric output data (typically measured in MWh) and thermal output (measured in MMBtu) are
often required.
• Implement appropriate data collection procedures. Install appropriate emission and output
measurement devices (electric and thermal) and collect emission and output data.
• Calculate compliance. Use the required calculation to determine the output-based emissions or
other output-based feature for the CHP system.
• Submit completed forms to the state utility regulatory agency or other appropriate authority.
Who has developed output-based regulations?
A number of federal, regional, and state programs have adopted output-based emission regulations,
including emission standards for large and small generators, cap and trade allowance allocation systems,
multi-pollutant regulations, and generation performance standards (Table ES-1).
To provide additional insight into the technical and policy considerations of setting output-based
standards, this handbook describes four output-based emission reduction programs. These programs
are:
• The output-based approach that EPA used to revise the electric utility boiler New Source
Performance Standard (NSPS) (40 CFR Part 60, Subpart Da). This action reflected a major change
in approach for the NSPS and provided an efficiency-based rationale for transitioning to output-
based regulation. When originally promulgated in 1998, it was the first NSPS for boilers that
incorporated output-based emission limits; it allows CHP systems to account for 75 percent of
their secondary thermal output. This section also discusses EPA's proposed GHG NSPS for new
power plants.
• A model rule for output-based standards for small electric generators. The model rule is a good
example of a straightforward output-based emission limit program that recognizes the thermal
output of CHP.
• EPA's guidance on how to allocate emission allowances for the NOxSIP Call and Clean Air
Interstate Rule (CAIR) based on energy output. The NOx SIP Call approach was developed by a
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Executive Summary
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stakeholder group of EPA, states, industry, and environmental groups. The guidance thoroughly
discusses how output-based allocation can be applied.4
• EPA's output-based approach in its Boiler Maximum Achievable Control Technology (MACT)
regulations (40 CFR Part 63, Subpart DDDDD). This rule, finalized in December 2012, applies to
industrial, commercial, and institutional boilers and process heaters. The rule contains
provisions for boiler/steam turbine CHP to account for their secondary electricity output.
Output-based regulations are continuing to gain attention as EPA, states, and regional planning
organizations strive to find innovative ways to attain today's air quality goals. Emissions from energy
production processes contribute to a number of air pollution problems, including fine particulates,
ozone, acid rain, air toxics, visibility degradation, and climate change. An output-based regulation can be
used as part of a regulatory strategy that encourages pollution prevention and the use of innovative and
efficient energy-generating technologies. Adopting output-based regulations, therefore, is a valuable
tool for protecting air quality while fostering the development of efficient, reliable, and affordable
supplies of energy.
Table ES-1. Current Output-Based Treatment of CHP
Type of Program
Regulatory Purview
Output-Based Features
Federal NSPS regulations
NSPS for Stationary Combustion Turbines
Emission limit (Ib/MWh) gross output
NSPS for Industrial-Commercial-
Institutional Steam Generating Units
Emission limit (Ib/MWh) gross output
NSPS for Stationary Compression Ignition
Internal Combustion Engines
Emission limit (g/KW-hr)
NSPS for Stationary Spark Ignition
Internal Combustion Engines
Emission limit (g/HP-hr)
NSPS for Aluminum Reduction Plants
Emission limit (kg/Mg) or (lb/ton)
NSPS for Electric Steam Generating Units
Emission limit (Ib/MWh) gross output
and (Ib/MWh) net output
National Emission
Standards for Hazardous
Air Pollutants (NESHAP)
NESHAP for Area/Sources: Electric Arc
Furnace Steelmaking Facilities
Emission limit (lb/ton)
NESHAP for Industrial, Commercial, and
Institutional Boilers and Process Heaters
(Boiler MACT)
Emission limit (Ib/MBtu) steam output
or (Ib/MWh)
NESHAP for Coal- and Oil-Fired Electric
Utility Steam Generating Units (MATS
rule)
Emission limit (Ib/MWh) or (Ib/GWh)
Conventional state
emission rate limits
New Jersey mercury emission limits
Emission limit (mg/MWh)
4 EPA first regulated the transport of NOx in 1998 with the promulgation of the NOx SIP Call and its NOx Budget Trading Program.
Several years later, with the goal of further increasing NOx reductions and helping states attain PM2.5 standards, EPA issued the
CAIR in 2005. In 2011, EPA finalized the Cross-State Air Pollution Rule to achieve even greater emissions reductions that reflect
more stringent air quality standards. For more information about these rules, their cap and trade programs, and their inter-
related history, go to: http://www.epa.gov/airtransport/CSAPR/and http://www.epa.gov/cleanairinterstaterule/.
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Executive Summary
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Table ES-1. Current Output-Based Treatment of CHP
Type of Program
Regulatory Purview
Output-Based Features
State emission standards
for distributed generation
New Hampshire
Emission tax (Ib/MWh)
California
Emission limit (Ib/MWh)
Delaware
Emission limit (Ib/MWh)
Rhode Island
Emission limit (Ib/MWh)
Texas
Emission limit (Ib/MWh)
Regulatory Assistance Project
Model rule with output-based
emission limit (Ib/MWh)
Connecticut
Emission limit (Ib/MWh)
Maine
Emission limit (Ib/MWh)
Massachusetts
Emission limit (Ib/MWh)
New York
Emission limit (Ib/MWh)
State NOx budget trading
programs
Connecticut
Allocation of allowances
Massachusetts
Allocation of allowances
Missouri
Allocation of allowances
New Hampshire
Allocation of allowances
New Jersey
Allocation of allowances
Ohio
Allocation of allowances
CAIR state programs
Arkansas
Allocation of allowances
Connecticut
Allocation of allowances
Illinois
Allocation of allowances
Indiana
Allocation of allowances
Massachusetts
Allocation of allowances
New Jersey
Allocation of allowances
Ohio
Allocation of allowances
Pennsylvania
Allocation of allowances
Wisconsin
Allocation of allowances
Regional Greenhouse Gas
Initiative state programs
Connecticut
Allocation of set-asides
Massachusetts
Allocation of set-asides
New York
Allocation of set-asides
State multi-pollutant
programs
Massachusetts
Emission limit (Ib/MWh)
New Hampshire
Allocation of allowances
State generation emission
performance standards
California
Performance standard (Ib/MWh)
New York
Performance standard (Ib/MWh)
Oregon
Performance standard (Ib/MWh)
Washington
Performance standard (Ib/MWh)
New Source Review
Connecticut
Lowest achievable emission rate
option
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Section 1. Introduction
1.1 Purpose of the Handbook
The U.S. Environmental Protection Agency (EPA) Combined Heat and Power Partnership (CHPP) program
developed this handbook to assist air regulators in developing emission regulations that recognize the
pollution prevention benefits of efficient energy generation and renewable energy technologies.
Output-based regulations include output-based emission standards and compliance options as well as
output-based allocations of allowances within cap and trade programs. Use of output-based regulations
can advance the adoption of highly efficient combustion
technologies leading to emission reductions.
Output-based regulations do not provide a special benefit to
any particular technology and do not increase emissions.
They simply level the playing field by allowing energy
efficiency to compete on an equal footing economically with
any other method of reducing emissions (e.g., combustion
controls and add-on controls). For this reason,
environmental groups, associations of air regulators, and
proponents of clean energy technologies have endorsed the use of output-based regulations (see
Appendix C).
While output-based regulations have been used for many sources, boilers and power generation sources
have traditionally been regulated through input-based regulations. Recently, this has begun to change as
regulators have sought to promote pollution prevention and provide compliance flexibility to
combustion sources, which face ever-increasing requirements for emission reductions. This handbook is
a resource for air regulators who wish to consider applying output-based regulations to boilers or power
generation sources. Specifically, the handbook:
• Describes output-based regulations.
• Explains the benefits of output-based regulations.
• Explains how to develop an output-based emission
standard or how to comply with an output-based
standard.
• Provides a catalogue of the current use of output-
based regulations for combustion sources.
Now is an important time to examine output-based regulations because of the increasingly competitive
energy markets and the improving economics of efficient power-generating technologies. Highly
efficient generation systems, such as combined heat and power (CHP), offer the potential to cost-
effectively reduce fuel consumption and associated emissions. Output-based regulations recognize the
environmental benefits of these technologies.
An output-based standard relates
emissions to the energy output of a
process (e.g., electricity or thermal
output) rather than the material
inputs (e.g., fuel burned). An example
would be Ib/MWhoutput, rather than
Ib/MMBtU heat input-
Output-based regulations encourage
pollution prevention, leading to
reduced fuel consumption and
associated reductions in emissions.
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Introduction
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1.2 Trends Supporting Increased Use of Output-Based Regulation
Increased interest in output-based regulations began in the 1990s. During this period, air regulators
faced persistent challenges in achieving progressively more stringent air quality standards while the
demand for energy continued to grow. Emissions from fuel combustion were determined to contribute
to a variety of air quality problems, including ground-level ozone, fine particulates, acid rain, urban
toxics, visibility degradation, and climate change. To achieve air quality goals, state and federal
regulators increasingly searched for more cost-effective approaches to achieve greater emission
reductions from energy production sources. Against this backdrop, output-based regulations presented
a way to provide flexibility to regulators and sources in achieving multi-pollutant emission reductions at
the lowest cost.
A number of factors have supported the growing interest in output-based regulations:
• Growing difficulty in meeting increasingly stringent air quality standards. To meet these
standards, regulators and the regulated community constantly look for new, cost-effective tools
to reduce emissions. Policymakers realize that more efficient energy conversion technologies
can have a substantial effect on reducing emissions. Most importantly, the investment in these
technologies creates environmental benefits across all air quality programs.
• Pollution prevention as a means of emission control. Improving efficiency is one of the best
forms of pollution prevention. Avoiding pollution through energy efficiency can have long-term
cost benefits through less reliance on emission control equipment and reduced fuel use. Gains in
efficiency produce multiple pollutant benefits without creating adverse secondary
environmental impacts that are common among end-of-pipe approaches. A number of states
have implemented portfolio standards requiring a certain percentage of retail electricity sales or
energy savings in the state to come from energy efficiency measures.
• Need to assess and compare different generating technologies. The widespread deployment of
new gas combined cycle generating technology, with emissions measured as flue gas
concentration (ppm) rather than the Ib/MMBtu common for conventional plants, has made
environmental comparisons between technologies difficult. As reducing emissions from
electricity generation became a focus, regulators became increasingly interested in clear
comparisons between alternative technologies. Output-based regulations place all generators
on the same regulatory basis and promote comparisons of environmental performance.
• Increased interest in CHP. The high efficiency of CHP reduces both energy consumption and
emissions, and many regulators were looking for ways to encourage its application. However,
CHP replaces two conventional emission sources with one source. Comparing CHP to
conventional systems requires an assessment of the energy production capacity that is
displaced. Output-based measures facilitate this comparison.
• Increased interest in renewable energy technologies. Wind turbine technology, along with
photovoltaic technology, has become significantly less expensive and more competitive in
electricity markets. Growth in wind and solar generation has been dramatic, yet small cost
improvements can still make a significant difference. Allocating emission allowances on an
output basis can financially reward these facilities for their contribution to meeting allowance
allocations.
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Introduction
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• Increased use of demand response.5 Greater participation in demand response programs
requires an increased focus on emissions from backup generators, which are often called upon
during demand response events. Output-based regulations are an effective way to regulate
emissions from these backup generators. Many of the recently developed output-based
regulations focus on distributed generation (DG) technologies, including backup generators. As
DG proliferates and emissions from DG increase, this new source of pollution becomes
important to air regulators and provides a valuable opportunity for the use of output-based
regulations.
• The development of emission trading programs. Market-based emission trading programs are
proliferating and can provide a more cost-effective approach to environmental regulation. For
example, current "cap and trade" programs such as the Cross State Air Pollution Rule (CSAPR)6
limit the total tonnage of emissions from one or more fuel combustion sectors. Because of the
cap on total emissions, generators strive to maximize the productive output they can generate
within their cap. This directly links the cost of allowances to electricity generation and causes
generators to think in terms of lb emissions/MWh.
1.3 Using the Handbook
This document provides practical information for an air regulator to consider in developing an output-
based regulation.
• Section 2 defines output-based regulations and explains the output-based units of measure
typically used for different combustion technologies.
• Section 3 explains how output-based regulations encourage pollution prevention, reduce fuel
use and multiple associated pollutants, and can reduce compliance costs.
• Section 4 describes the mechanics of developing output-based standards, and discusses the
decisions involved and the compliance implications; this section also discusses complying with
output-based regulations.
• Section 5 catalogues recent output-based air regulations at the state, regional, and federal
levels and discusses three regulations in detail.
• Appendix A contains energy conversion factors.
• Appendix B lists existing output-based regulations.
5 Demand response is defined as changes in electric usage by end-use customers from their normal consumption patterns in
response to changes in the price of electricity over time, or to payments to incentivize lower electricity use when wholesale
market prices are high or when system reliability is jeopardized.
6 http://www.epa.gov/airtransport/CSAPR/pdfs/CSAPRFactsheet.pdf.
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Section 2. What Is An Output-Based Regulation?
An output-based regulation relates emissions to the productive output of the process. Outputs from
combustion sources include electrical, thermal, and mechanical energy. Output-based regulation can be
used to develop traditional emission standards or to allocate emission allowances in a cap and trade
program. In both cases, they account for the pollution prevention benefits of efficient energy generation
and renewable energy technologies.
• Output basis for emission standards. Output-based standards account for the emission benefit
of efficiency measures, such as increasing combustion efficiency, increasing turbine efficiency,
recovering useful heat, and reducing parasitic losses associated with operating the affected unit
(e.g., operation of fans, pumps, motors). Therefore, control strategies for meeting output-based
emission standards can include both emission controls and efficiency measures.
• Output basis for allowance allocations. An output basis can also be used in determining
allowance allocations in a cap and trade program. An output-based allocation provides more
allowances to more efficient plants. Traditionally, allowances (the right to emit one ton per year
of a pollutant) have been allocated based on the operating history (usually annual fuel input) of
the regulated sources. Allowances also can be updated in the future (referred to as an
"updating" allocation system). Adopting an updating
allocation system on an output basis and including
renewable energy facilities provides an incentive for
both energy efficiency and renewable energy.
2.1 Output-Based Units of Measure
The appropriate units of measure for an output-based
emission standard depend on the type of energy output and the combustion source. For most
applications, the units of measure are pounds of emissions per unit of energy output (Table 2-1). For
reciprocating engines, output-based measure is either grams of emissions per brake horsepower-hour
(g/bhp-hr) or pounds per megawatt hour (Ib/MWh), depending on whether the engine is used to
generate mechanical power or electricity.
Table 2-1. Output-Based Units of Measure
For This Type of Energy Production-
Using...
An Output-Based Measure Is...
Electricity generation
• Boilers/steam turbines
Reciprocating engines
• Combustion turbines
Pounds per megawatt hour (Ib/MWh)
Steam or hot water generation
• Industrial boilers
• Commercial boilers
Pounds per million British thermal units
(Ib/MMBtU heat output)
Mechanical power
• Reciprocating engines
Grams/brake horsepower-hour
(g/bhp-hr)
2.2 Output-Based Standards Under the Clean Air Act
Traditionally, most combustion sources have been regulated based on heat input (lb/MMBtUheatinput) or
the mass concentration of pollutants in the exhaust stream (parts per million or "ppm"). Input-based
Output-based regulations are based
on electrical, thermalor mechanical
output (MWh, MMBtu, or bhp-hr),
rather than the heat input of fuel
burned or pollutant concentration in
the exhaust.
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2-1
What is an Output-Based Regulation ?
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regulations were used during early Clean Air Act rulemaking efforts in part because data on heat input
were more readily available at the time than data on energy output. Subsequently, compliance tests
were based on heat input, and energy output data generally were not collected and reported as part of
the required monitoring or source test requirements. Similarly, when cap and trade programs were
initiated with the 1990 Clean Air Act Amendments (Title IV of which established the Acid Rain Program),
emission allowances for individual power plants were allocated based on their historical annual heat
input.
Nevertheless, output-based standards are not a new concept within the Clean Air Act. In the form of
mass emitted per unit of production, they have been used for many New Source Performance Standards
(NSPS), National Emission Standards for Hazardous Air Pollutants (NESHAP), and other state and federal
rules. For example:
• The NSPS (40 CFR part 60) uses output-based standards for primary aluminum (subpart S), wool
fiberglass (subpart PPP), asphalt roofing (subpart UU), and glass manufacturing (subpart CC).
The NSPS for stationary combustion turbines (subpart KKKK) limits emissions from stationary
combustion turbines. Affected units have the option of meeting concentration-based or output-
based nitrogen oxides (NOx) and sulfur dioxide (S02) emission limits.
• The NESHAP (40 CFR part 63) uses output-based standards for iron and steel (subpart FFFFF),
brick and structural clay (subpart JJJJJ), and other industries.
• States have used output-based standards for a variety of regulations. For example, Indiana sets
NOx emission limits for cement kilns in lb/ton of clinker produced (326 IAC 10-1-4); and New
Jersey sets NOx limits for glass melters in lb/ton of glass removed (NJAC 7:27-19.10). More
recently, Texas issued a streamlined construction air permitting program in 2012, termed a
permit by rule (PBR), under which certain types of natural-gas-fired CHP systems are eligible
(i.e., a CHP unit, up to a capacity of 8 MW without additional controls and 15 MW with
additional controls, burning only pipeline-quality natural gas). The CHP PBR, codified in 30 TAC
106.513, allows CHP systems that meet the rule's eligibility requirements to comply with output-
based NOx and carbon monoxide (CO) emission limits. Other states have similar requirements.
• The automotive emission standards are expressed in grams/mile.
Output-Based Regulations:
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What is an Output-Based Regulation ?
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Section 3. Why Adopt Output-Based Regulations?
Output-based regulations offer a variety of benefits for regulators and the regulated community. For
regulators, output-based regulations encourage pollution prevention, leading to reductions in fossil fuel
use and associated environmental impacts. For the regulated community, output-based regulations
offer greater flexibility and the opportunity for lower compliance costs for individual facilities and
society as a whole. Also, because output-based
regulations encourage energy efficiency, these
regulations can reduce the stress on today's energy
systems.
This chapter demonstrates the benefits of output-
based approaches by presenting case study
examples of the differences between output- and
input-based regulations at the facility level. Section
3.1 explains the emission reduction benefits of output-based regulations. Section 3.2 explains how costs
can be reduced by the compliance flexibility that output-based regulations provide. Section 3.3 shows
how an output-based format facilitates comparisons of environmental performance. Lastly, Section 3.4
describes CHP technologies and how output-based regulations can be used to account for their unique
efficiency benefits.
3.1 Emission Reduction Benefits of Output-Based Regulation
Output-based regulations can reduce air pollution by encouraging energy efficiency and renewable
energy technologies. The increased use of these technologies reduces fuel use and leads to multi-media
reductions in the environmental impacts of fuel production, processing, transportation, and combustion.
Reduced fuel use reduces emissions of all pollutants, not just the target pollutant of the regulatory
program. In addition, energy efficiency and renewable energy can create a permanent and consistent
emission benefit that is not subject to short-term emission increases that can result from startup,
shutdown, or malfunction of add-on control devices (e.g., selective catalytic reduction for NOxor
scrubbers for S02). Pollution prevention also reduces the secondary pollutant releases (e.g., sludge and
ash disposal) that are often associated with add-on control technologies. The sections that follow
illustrate the effect of output-based regulations in a conventional emission standards program and in an
emission trading program.
3.1.1 Output-Based Emission Standards
An output-based emission standard provides a clear indicator of emission performance, because it
accounts for the emission impact of efficiency in addition to fuel choice and emission controls. A
comparison of NOx emissions at two 300 MW power plants can demonstrate this effect (Figures 3-la
and 3-lb). Assume that each plant operates at an 80 percent capacity factor and generates about 2.1
million MWh per year. Using the traditional input- or concentration-based units of measure, Plant 1
appears to have lower emissions (0.09 lb NOx/MMBtu or 25 ppm versus 0.12 lb NOx/MMBtu or 32 ppm
for Plant 2). But input- or concentration-based measures do not account for differences in efficiency (34
percent for Plant 1 and 53 percent for Plant 2).
Benefits of output-based regulations:
Incentive for pollution prevention
Multi-pollutant emission reductions
Reduced fuel use
Avoidance of upstream environmental
impacts of fuel production and delivery
Lower compliance costs
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A Handbook for Air Regulators
3-1 Why Adopt Output-Based Regulations?
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An output-based emission measure accounts for the effect of efficiency (Figure 3-lb). The difference in
efficiency means that Plant 2 requires 35 percent less fuel to generate the same electrical output as
Plant 1. This means it emits fewer tons, even though it has a higher exhaust concentration. Plant 1 has a
lower input-based emission rate, but greater heat input, and emits more than 900 tons per year. Plant 2
has a higher emission rate, but lower heat input, and emits less than 800 tons per year. This example
illustrates that emission limits based on heat input or concentration are not good indicators of the
actual environmental impact. The output-based emission rate, however, reflects the true difference in
emissions. Plant 1 has an output-based emission rate of 0.9 Ib/MWh, while the rate for Plant 2 is 0.7
Ib/MWh.
Because output-based standards account for the effect of energy efficiency, they allow for the use of
efficiency as a control measure. This can result in multi-pollutant emission reductions. In addition to
reducing NOx emissions, the higher efficiency of Plant 2 means lower emissions of all other pollutants,
including S02, particulate matter (PM), and hazardous air pollutants (HAP), as well as unregulated
emissions such as carbon dioxide (C02).
Moreover, an output-based standard ensures consistent long-term emission reductions. Under an
output-based standard, a decrease in efficiency over time would cause an increase in the emissions per
unit of output. This increased emission rate would require the operator to reduce emissions or improve
unit efficiency to stay in compliance. On the other hand, under an input-based standard, deterioration
of unit efficiency is not reflected in the emission rate, and total annual emissions can increase without
affecting compliance.
Thus, an output-based standard offers several advantages:
• It allows sources to benefit from applying energy efficient measures, which lowers fuel use and
achieves multi-pollutant emission reductions.
• It ensures consistent, long-term emission reductions.
• It allows regulators to more clearly compare emission performance across different energy-
generating technologies and fuels.
• Provides sources with alternative compliance options that can lower costs (see Section 3.2).
Output-Based Regulations:
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3-2 Why Adopt Output-Based Regulations ?
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Figure 3-la. Benefits of Output-Based Regulation
0.09 lb/MMBtu
0.12 lb/MMBtu
Plant 1
34% Efficiency
Plant 2
~ 2.1 MM MWh/yr
2.1 MM MWh/yr
53% Efficiency
Figure 3-lb. Benefits of Output-Based Regulation
0.09 lb/MMBtu
21 MMMMBtu/yr
0.12 lb/MMBtu
13.7 MMMMBtu/yr
94^ Tons/year
0.9 lb/MWh
Plant 1
.->4% Elticiencv
787 lons/year
0.7 lb/MWh
Plant 2
2.1 MM MWh/yr
2.1 MM MWh/yr
53% Efficiency
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3-3 Why Adopt Output-Based Regulations?
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3.1.2 Output-Based Allowance Allocations in Emission Trading Programs
In recent years, recognition of the regional nature of many air quality problems has led to the increasing
use of cap and trade programs. In such a program, the total tons of emissions for a given industry sector
are capped at the desired level of emission reduction.
Emission allowances, which represent the right to emit one ton per specified time period (e.g., annually
or during the ozone season), are allocated directly to industry participants or auctioned. At the end of
each time period, every affected source is required to hold allowances equal to its emissions. Sources
comply through a combination of reducing emissions and buying additional allowances.
Emission allowances are allocated at the beginning of a
trading program on either a permanent basis or with a
provision for updating allocations for future trading periods.
For the national sulfur dioxide trading program, which was
established under the Title IV acid rain program, S02
allowances were permanently allocated based on historic
annual heat input. The regional NOx Budget left allocation
decisions up to state governments and provided guidance to
help states that might want to allocate on an output basis
(see Section 5.0 for further discussion). The Clean Air
Interstate Rule (CAIR) also gave state governments flexibility
in determining whether to allocate allowances on an output
basis. In June 2014, the U.S. government filed a motion with
the U.S. Court of Appeals for the D.C. Circuit to lift the stay
of CSAPR, which was intended to replace CAIR. While the
Court considers the motion, CAIR remains in place and no
immediate action from states or affected sources is
expected. An output-based allocation provides more allowances to efficient units than to inefficient
ones. The example on the next page illustrates this effect.
The environmental benefit of an output-based allocation system occurs only in programs where
allowances are reallocated periodically for future periods (known as an updating allocation system). For
the initial allocation, there is no difference in incentives between an input-based system of allocation
and an output-based one, because the initial allocation in both cases is based on historical data.
However, the opportunity to influence behavior comes when facility operators know that emission
allowances will be reallocated in the future. An updating output-based allocation system would provide
an incentive for increased energy efficiency because more efficient units would receive relatively more
allowances in future allocations.
Alternatively, an input-based reallocation system would provide a relative disincentive for efficiency
improvements because an efficient unit would burn less fuel and, therefore, receive fewer allowances.
f ^
On March 10, 2005, EPA issued the
Clean Air Interstate Rule (CAIR). CAIR
covers 27 eastern states and the
District of Columbia. CAIR requires
emissions reductions that each state
must achieve using one of two
compliance options: (1) meet its
emission budget by requiring power
plants to participate in an EPA-
administered interstate cap and trade
system that caps emissions in two
stages or (2) meet an individual state
emission budget through measures of
its choosing. A number of states
adopted an output-based approach
for both existing and new sources.
I J
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3-4 Why Adopt Output-Based Regulations ?
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How Do Input-Based and Output-Based Allowance Allocations Differ?
Consider a state with emissions of 1,700 tons per year and an emissions cap of 1,500 tons per year.
This cap represents a 12 percent reduction in emissions. Assume that the only emission sources are
the two plants described in Figure 3-1. The table below shows the allocation of allowances under
input- and output-based approaches.
Basis of Allocation
Plant 1
Plant 2
Heat Input
Heat input (million MMBtu/yr)
21.0
13.7
Percent of total heat input
61%
39%
Initial emissions (tons)
945
822
Allowances allocated (tons)
909
591
Implied emission reduction
4%
28%
Energy Output
Output (million MWh/yr)
2.10
2.10
Percent of total generation
50%
50%
Initial emissions (tons)
945
822
Allowances allocated
750
750
Implied emission reduction
21%
9%
In this example, Plant 1 uses 21 million MMBtu/yr, or 61 percent of the heat input, and Plant 2
uses 39 percent. Allocating the 1,500 allowances by these shares gives 909 allowances to Plant 1
and 591 allowances to Plant 2. If there were no trading, this allocation would impose a 4 percent
emission reduction for Plant 1 (the higher-emitting plant) and a 28 percent reduction for Plant 2
(the lower-emitting plant). This allocation approach seems to reward the higher-emitting plant by
awarding it more allowances while penalizing the lower-emitting plant.
Alternatively, under an output-based allocation, both plants would receive 750 tons of allowances
because they produce the same output. Without trading, this implies a 21 percent emission
reduction for Plant 1 and a 9 percent reduction for Plant 2. In this case, the trading program rewards
the lower-emitting, more efficient plant. Several states participating in the NOxSIP Call trading
program use output-based allocation, as do some existing and proposed multi-pollutant legislation
(see descriptions of these programs in Appendix B).
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3-5 Why Adopt Output-Based Regulations ?
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The primary environmental benefits of increased efficiency are the ancillary impacts. For example, if the
cap and trade program controls NOx emissions, total emissions of NOx would be the same under either
allocation method. However, the increased efficiency would reduce emissions of S02, CO, C02, HAP, and
PM, and would reduce fossil fuel demand and the environmental impacts associated with the fuel
production and transportation systems.
States can design their output-based allocation systems to
pursue their own energy and environmental policy agenda.
For example, output-based allocation under a cap and trade
program provides the opportunity to allocate emission
allowances to renewable energy sources. Output-based
allowance allocation treats renewable generators and
efficiency programs the same as conventional generators.
When done on an updating basis, the allocation promotes
the increased use and construction of these non-emitting
sources by giving them a market-based economic benefit.
Output-based allocations also provide the opportunity to
promote CHP systems by including their thermal output in the
Another way to view the allowance allocation process is that it
resource—clean air. An output-based approach allocates that I
productive output rather than raw materials used.
Thus, output-based allocation of allowances within a cap and trade program:
• Provides economic benefit to more efficient and non-emitting sources, thereby recognizing their
contribution to meeting regional emission caps.
• Encourages increased construction and use of efficient energy sources (if done on an updating
allocation basis).
• Allocates public resources (the right to emit) in proportion to the public benefit (energy output).
3.2 Cost Reductions from Output-Based Regulations
An output-based emission regulation can reduce compliance costs because it gives process designers
greater flexibility in reducing emissions. A facility operator can comply by installing emission control
equipment, using a more energy-efficient process, or combining the two steps. Regulating the emissions
produced per unit of output has value for equipment designers and operators because it gives them
additional opportunities to reduce emissions through more efficient fuel combustion, more efficient
cooling towers, more efficient generators, and other process improvements that can increase plant
efficiency.
This flexibility is particularly important for NOx because NOx formation is a function of combustion
temperature and conditions. NOx concentration and energy efficiency are often a trade-off in
combustion design. In some cases, however, equipment designers can reduce emissions by increasing
efficiency and allowing a slightly higher flue gas NOx concentration.
The section 126 NOx cap and trade
program to reduce interstate ozone
transport based the initial allowance
allocations on heat input (because
good- quality energy output data were
not available), but announced that
allowances would be updated every
five years based on energy output (65
FR 2698, January 18, 2002).
allocation calculation.
distributes the right to use a public
imited public resource on the basis of
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This control approach is not possible with input-based emission limits, but could be used under an
output-based limit.
Example of cost flexibility allowed by an output-based emission standard. Consider a planned new or
repowered coal-fired utility plant with an estimated uncontrolled NOx emission rate of 0.35
Ib/MMBtuheat input. To comply with an input-based emission standard of 0.13 Ib/MMBtuheat input, the
plant would have to install emission control technology to reduce NOx emissions by more than 60
percent. On the other hand, if the plant were subject to an equivalent output-based emission standard
of 1.3 Ib/MWh, it would have the option of considering alternative control strategies by varying both its
operating efficiency and the efficiency of the emission control system (Table 3-1). This output-based
format allows the plant operator to determine the most cost-effective way to reduce NOx emissions and
provides an incentive to reduce fuel combustion. The total annual emissions are the same in either case.
Table 3-1. Design Flexibility Offered by Output-Based Standard
Plant Efficiency (Percent)
Emission Standard Ib/MWh
Required Control Device
Efficiency (Percent)
34
1.3
60
40
1.3
55
44
1.3
48
From a broader economic perspective, achieving emission reductions through efficiency can be
significantly more attractive than through add-on controls. Add-on controls require an investment of
capital but do not increase productive output. In many cases, they reduce efficiency and/or output. The
same capital, if used to increase efficiency, will reduce emissions and increase productive output. This
contradicts the common assumption that a facility operator must choose between cost and emission
reductions. Efficiency improvement reduces operating cost, increases production, and reduces
emissions.
3.3 Output-Based Format as a Measure of Environmental Performance
An output-based format gives a clear measure of the emission impact of producing an energy product,
such as electricity or steam. As an example, the most common output-based measure for electricity
generation is Ib/MWh generated. When emissions are expressed in these units, all sources can be
directly compared, and determining the actual tons of emissions for a given level of energy generation is
straightforward. Table 3-2 shows conventional input-based units of measure for electric utility emission
limits and the comparable output-based units. The ranges shown in the table represent typical ranges of
emission rates for each combustion technology.
Output-based standards make comparing emissions between technologies easier. By contrast,
comparing 0.1 g NOx/bhp-hr from an engine to 25 ppm NOxfrom a gas turbine to 0.1 Ib/MMBtu from a
boiler is cumbersome. Using an output-based format, therefore, can simplify emission comparisons and
program design for an air quality planner.
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Table 3-2. Conventional and Output-Based Measurements for Electricity Generation
Steam Boiler*
Combustion Turbine**
Reciprocating Engine
lb/MMBtuheat input
Ib/MWh
ppm
Ib/MWh
g/bhp-hr
Ib/MWh
0.1
1.0
3
0.13
0.1
0.31
0.2
2.0
9
0.4
0.15
0.47
0.3
3.0
15
0.6
0.5
1.56
0.4
4.0
25
1.1
0.7
2.18
0.6
6.0
42
1.8
1.0
3.11
* At 10,000 Btu/kWh heat rate.
** At 12,000 Btu/kWh heat rate.
3.4 Output-Based Regulation and Combined Heat and Power Applications
CHP is one of the best examples of an energy efficiency technology that can reduce fuel consumption
and emissions. Although CHP is not a new concept, it is unfamiliar to many regulators, investors, and
potential users. This lack of familiarity can create obstacles to its widespread application. One way to
promote the use of this environmentally beneficial technology is through output-based regulations.
3.4.1 What Is Combined Heat and Power?
CHP is the sequential generation of power (electricity or
shaft power) and thermal energy from a common fuel
combustion source. CHP captures waste heat that ordinarily
is discarded from conventional power generation, which
typically discards two-thirds of the input energy as waste
heat (typically up exhaust stacks and through cooling
towers). CHP systems recover much of this otherwise
wasted energy. This captured energy is used to provide
process heat, space cooling or heating for commercial buildings or industrial facilities, and cooling or
heating for district energy systems. By recovering waste heat, CHP systems achieve much higher
efficiency than separate electric and thermal generators. Figure 3-2 shows two common configurations
for CHP systems.
The steam boiler/turbine approach was the first application of CHP and the only CHP technology for
many years. In this approach, a boiler makes high-pressure steam that is fed to a turbine to produce
electricity. However, the turbine is designed so that enough steam is left over to feed an industrial
process. This type of system typically generates about five times as much thermal energy as electric
energy. Steam boiler/turbine CHP systems are widely used in the paper, chemical, and refining
industries, especially when waste or byproduct fuel is available that can be used to fuel the boiler.
In the other common CHP system, a combustion turbine or reciprocating engine is used to generate
electricity, and thermal energy is recovered from the exhaust stream to make steam or supply other
thermal uses. These systems have been applied more in recent years, as the combustion technologies
have developed. These types of CHP systems can use very large (hundreds of MW) gas turbines or very
small (tens of kW) microturbine, engine, or fuel cell systems. The electric energy they produce is
typically one to two times the thermal energy produced.
Typical CHP technologies:
Combustion turbines
Reciprocating engines
Boiler/steam turbines
Combined cycle gas turbines
Microturbines
Fuel cells
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Figure 3-2. Two Typical CHP Configurations
Steam Boiler/Steam
Fuel „
Boiler
Water
Walef
Qas Turbine
-------
the efficiency and fuel use of conventional systems providing the same service. In this case, both
systems provide 30 units of electric energy and 45 units of thermal energy to the facility.
Figure 3-3. Efficiency Benefits of CHP
Conventional
Generation
Power Station Fuel
(U.S. Fossil Mix)
91 Units Fuel
56 Units Fuel
IL
Combined Heat and Power
5 MW Natural Gas
Combustion Turbine
and Heat Recovery Boiler
Power Plant
EFFICIENCY:
33%
EFFICIENCY:
80%
Electricity
Boiler Fuel
' 30 '
Units
Electricity
Electricity
Heat
Combined
Heat
& Power
(CHP)
51% ...OVERALL EFFICIENCY... 75%
In the conventional system, the electricity required by the facility is purchased from the central grid.
Power plants on average are about 33 percent efficient, considering both generating plant losses and
transmission and distribution losses.8 Thermal energy required by the facility is provided by an onsite
boiler that might be 80 percent efficient. Combined, the two systems use 147 units of fuel to meet the
combined electricity and steam demand. The combined efficiency to provide the thermal and electric
service is 51 percent.
With CHP, an onsite system provides the same combined thermal and electric service. Electricity is
generated in a combustion turbine and the waste heat is captured for process use. The CHP system
satisfies the same energy demand using only 100 units of fuel. This system is 75 percent efficient.
Figure 3-4 shows the emission benefits of the CHP system, in this case for NOx emissions. The CHP
system has much lower emissions because it uses 35 percent less fuel, even if the combustion process
has the same input-based emission rates as the conventional equipment. In this example, as is often the
case, the new CHP system displaces higher-emitting generators on the electric grid, and the emission
rate for the new system is lower than the conventional alternative, thus further reducing emissions. In
the case shown, the CHP system emits less than half as much NOx as the conventional system due to a
combination of greater efficiency and lower emission rate.
8 http://www.epa.gov/chp/basic/efficiency.html.
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Figure 3-4. Emission Benefits of CHP
Boiler Fuel (Gas)
Conventional
Generation
Power Station Fuel
(U.S. Fossil Mix)
i.
Emissions
¦ ¦¦¦•¦¦¦¦¦¦¦¦a av
32 kTons
Power Plant
EFFICIENCY:
33%
EFFICIENCY:
80%
Electricity
Heat
- — Emissions.
13 kTons
35,000
MWh
179,130
MMBtu
Combined Heat and Power
5 MW Natural Gas
Combustion Turbine
and Heat Recovery Boiler
Electricity
Heat
^ Emissions^ .
23 kTons
Combined
Heat
& Power
(CHP)
CHP Fuel (Gas)
45kTONs/YR ...TOTAL EMISSIONS... 23i
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Section 4. How Do I Develop An Output-Based Emission Standard?
This chapter explains how to develop an output-based emission standard. To begin, several decisions
must be made about the format of the rule. Making these decisions will involve trade-offs between the
degree to which the rule will account for the benefits of energy efficiency, the complexity of the rule,
and the ease of measuring compliance. This chapter explains the technical approach, available options,
and the implications of each option. The steps for developing an output-based emission standard are:
1. Develop the output-based emission limit. The method that you use will depend on whether you
have measured energy output data available.
2. Specify a gross or net energy output format. Net energy output will more comprehensively account
for energy efficiency, but can increase the complexity of compliance monitoring requirements.
3. Specify compliance measurement methods. Output-based rules require designating methods for
monitoring electrical, thermal, and mechanical outputs. These outputs are already monitored for
commercial purposes at most facilities.
4. Specify how to calculate emission rates for CHP units. For CHP units, the rule must account for
multiple energy outputs. Two commonly used approaches are explained.
4.1 Develop the Output-Based Emission Limit
Ideally, to develop an output-based emission limit, you must obtain emission data and simultaneously
measured energy output. Unfortunately, energy output data are not always available. Most emission
test data available today are based on energy input, consistent with current compliance measurement
requirements. But output-based emission limits can still be developed by converting input-based
emission data or existing emission limits to an output-based equivalent using unit conversions and a
benchmark energy efficiency. The following sections demonstrate the unit-of-measure conversions
from:
• Input-based emission limit in pounds per million Btu (lb/MMBtuheat input)-
• Flue gas concentration limit in parts per million by volume (ppmv).
• Emission limit based on mechanical power in grams per brake horsepower-hour (g/bhp-hr).
for the two primary types of energy outputs:
• Electrical power generation (to Ib/MWh).
• Steam or hot water generation (to lb/MMBtuheatoutput).
4.1.1 Conversion from Input-Based Emission Limit (lb/MMBtu/heatinput)
Many emission standards for boilers are expressed in lb emissions/MMBtuheatinpUt. You convert to
output-based standards using a benchmark efficiency factor and a unit-of-measure conversion. The
conversion is straightforward for electric generators and industrial boilers.
Electric generators. For utility boilers, the output-based unit of measure is Ib/MWh of electricity
generated.
output standard = (I x H) -r 1,000
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How Do I Develop an
Output-Based Standard?
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Where:
output standard = Output-based emission limit, Ib/MWh
I = Input-based emission limit, Ib/MMBtUheatinput
H = Benchmark heat rate of steam generator set, Btu/kWh
1,000 = Unit-of-measure conversion. 1,000 kWh x MMBtu
MWh 1,000,000 Btu
If the power plant efficiency is used as the benchmark rather than the heat rate, calculate the heat rate
as shown below.
heat rate = 3,413 4 efficiency
For example
3,413 4 34% efficiency = 10,000 Btu 4 kWhe|ectriCOUtpUt
Then, the output-based emission limit can be calculated using Equation 1.
Example Calculation
Consider a state with an emission limit of 0.15 lb/MMBtuheat input- Assume that you select a
benchmark heat rate of 10,000 Btu/kWh of electric output. Using this heat rate and Equation
1, the equivalent output-based limit would be:
output standard = I x H 41,000
= 0.15 Ib/MMBtu x 10,000 Btu/kWh 4 1,000
= 1.5 lb/MWhelectricoutput
While this calculation is straightforward, you must determine a benchmark efficiency to use in the
calculation. The choice of benchmark efficiency will affect the stringency of the output-based limit. Heat
rates for conventional steam turbine power plants can vary from 9,000 to 11,000 Btu/kWh, depending
on type of unit and load factor. Heat rates for older units can be higher (i.e., less efficient). Selecting a
low heat rate will result in an aggressive limit for the less efficient units in the existing source
population. Selecting an average or typical value from the population of affected sources will result in
less control of newer, more efficient units. When selecting efficiency, you should consider the goals of
the regulatory program (e.g., new source or existing source regulation) and the degree of emission
reduction needed.
Heat rates can be calculated from heat input and generation data collected by the Energy Information
Administration on Form 767. Heat rate data for individual power plants also are available in EPA's eGRID
Database (http://www.epa.gov/cleanenergy/egrid/).
Both the heat rate and efficiency should be based on the fuel's higher heating value (HHV), not its lower
heating value (LHV). Heating values describe the amount of energy released when fuel is burned. HHVs
and LHVs are determined differently, however. HHV is the heating value including the latent heat of the
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combustion products. HHV is usually used for systems using boilers. LHV is the heating value net of the
latent heat in the combustion products. LHV is often used in calculating efficiencies for combustion
turbines and reciprocating engines.
EPA's practice is to base all regulatory limits on the HHV of the fuel. Fuel is typically sold based on HHV.
If you know only the LHV, then convert to HHV as follows:
HHV = LHV + 10.3 (H2 x 8.94)
Where:
H2 = mass percent hydrogen in fuel, %
LHV = lower heating value, Btu/lb
Factors for specific fuels are listed in Appendix A. For natural gas, the HHV is 1,030 Btu/cf and
the LHV is 937 Btu/cf, or LHV h- HHV = 0.91.
Commercial/industrial steam boilers. For steam or hot water generators, the output-based unit of
measure is lb emission/MMBtuheatoutput. You can convert an input-based emission rate to an output-
based format using the boiler efficiency, as follows:
output standard = I 4- E
Where:
output standard = Output-based emission limit, Ib/MWh
I = Input-based emission limit, Ib/MMBtUheatinput
E = Benchmark steam generator efficiency, %
Typical steam generator efficiencies are in the range of 75 to 80 percent.
Example Calculation
Consider a state with an emission limit of 0.15 Ib/MMBtu for natural-gas-fired industrial
boilers. Assume that you select a benchmark efficiency of 80 percent. The output-based limit
would be:
output standard = I 4 E
= 0.15 Ib/MMBtu h-0.80
= 0.19 Ib/MMBtuheat output
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4.1.2 Conversion from Flue Gas Concentration Limit (ppmv)
Emission limits for combustion turbines and sometimes for boilers and engines are expressed as
concentration standards in ppm by volume on a dry basis. The conversion of concentration
measurement (ppmv) to output-based measures is a two-step process.
Step 1. The first step is to convert ppm concentration to an input-based limit and correct for different
levels of dilution air in the exhaust gas stream. The conversion is a function of the composition of the
exhaust stream and thus varies for different fuels because their combustion products are different. The
calculation procedure is:
( 20-9 \
lb/MMBtuheatinput = ppm x k x F x ^20 9 _ o/0q2)
The factor k accounts for unit conversions (i.e., from ppm to lb/dry standard cubic foot); F relates the
dry flue gas concentration to the caloric value of the fuel combusted. The k and F factors have been
tabulated for a variety of fuels and pollutants (see EPA Method 19 and Appendix A). The last term in the
equation adjusts the measured ppm value to a standard 02 level to correct for any bias due to stack gas
dilution. If C02 is measured rather than 02, the method of correction is explained in EPA Method 19. For
example, convert an emission limit of 25 ppmv (15 percent 02) to an input-based limit as follows:
/ 20.9 \
lb/MMBtuheatinpUt = 25 ppm N0X @ 15% 02 xkxF (2Q 9 _ 15]
= 0.09 lb/MMBtuheatinpUt
For natural gas, the conversion is:
lb/MMBtuheatinput = PPm @ 15% 02 272
Step 2. The second step is to convert the input-based limit to an output-based limit. Use either Equation
1 for electricity generators or Equation 2 for steam or hot water generators.
4.1.3 Conversion from Emission Limit Based on Mechanical Power (g/bhp-hr)
Emissions from reciprocating engines are typically measured in grams per brake horsepower-hour
(g/bhp-hr). This is an output-based measure of mechanical power that does not account for the
efficiency of the electric generator. You can determine the output-based emission limit using generator
efficiency and a unit-of-measure conversion. The conversion is as follows:
Where:
output standard
P
E
2.953
output standard = (P x 2.953) 4- E
Output-based emission limit, Ib/MWh
Input-based emission limit, lb/MMBtuheatinput
Benchmark steam generator efficiency, %
1 lb 1 hp 1,000 kW
Unit-of-measure conversion, X X
454.g 0.746 kW MW
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Using a benchmark efficiency of 95 percent, which is a typical generator efficiency, the conversion can
be simplified to:
Ib/MWh = g/bhp-hr x 3.11
4.2 Specify a Gross or Net Energy Output Format
Output-based regulations relate emissions to energy output. You must decide whether the emission
limit you are preparing will be expressed as mass per gross energy output or mass per net energy
output. These two approaches have different implications for compliance monitoring and the extent to
which the rule accounts for energy efficiency.
Gross output is the total output of a process. Gross output from an electric generating unit would be the
gross electric generation (MWh) that comes directly from the electric generator terminals before any
electricity is used internally at the plant. Gross output from an industrial boiler would be the gross
thermal output (MMBtuheatoutput) that comes directly from the boiler header.
Net output is the gross output minus any of the energy output consumed to generate the output.
Examples of output that would be subtracted from the gross output when calculating net output
include:
• Auxiliary loads related to thermal or electric generation, such as fuel handling and preparation
equipment, pumps, motors, and fans.
• Output diverted to operate pollution control devices.
• Thermal output used in heat recovery equipment such as preheaters or economizers.
• House loads (loads used inside the plant for lighting, heating, etc.).
Using a net energy output basis provides the greatest incentive for energy efficiency because it accounts
for all internal energy consumption at the plant. This method provides an incentive to use energy-
efficient devices to lower internal power consumption and realize a net gain in efficiency. But measuring
net output can be more difficult than measuring gross output, because net energy cannot always be
directly measured at a single location. Rather, determining net output can involve accounting
individually for each piece of equipment that uses steam or electricity. At complex industrial sites, it may
be difficult to determine the energy associated with power generation or to isolate parasitic losses from
energy used by production processes. At utilities, it can be difficult to determine net generation if
individual units are subject to different emission limits, because metering net energy from the site
would not allocate net energy for each boiler generator set. Thus, while a net output format will more
completely account for efficiency measures within a process, the associated measurement and
recordkeeping requirements can be burdensome.
The decision on which format to use in a particular application should balance the likely burden of
greater complexity with the potential benefits of encouraging a greater range of efficiency improvement
measures within a process. For small, distributed generation technologies (e.g., microturbines or engine
generators) the difference between a net output and a gross output is not significant, because the
technology is packaged as an integral unit. All losses are internal to the package, and net and gross
output are essentially the same.
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4.3 Specify Compliance Measurement Methods
Methods for measuring compliance with output-based standards are readily available. You must specify
what to measure and the appropriate monitoring locations that correspond to the emission standard.
Mass emissions are measured using the same emission monitors and reference methods used for input-
based standards. The only variable that changes is the quantity to which the mass emissions will be
related. Instruments to continuously monitor and record energy output are routinely used and
commercially available at a reasonable cost. Most facilities already monitor their output for a variety of
business purposes.
For electric generation applications, MWh must be measured. Measurement of MWh is straightforward
and highly accurate. In most cases, the electric output of the generator is already being measured to
record electricity sales. If it is not already being measured, the generation can easily be recorded by
standard kWh meters. Mass emissions would be divided by MWh produced to calculate Ib/MWh.
• At large power plants, multiple boilers might serve multiple generators such that a one-to-one
relationship does not exist between the emitting units and the generating units. In this case, two
different approaches could be used for relating the measured emissions to the measured
electric output:
• The simpler approach is to set the output-based emission limit for the overall plant (i.e., all
boilers combined). Compliance can be then measured as the total emissions divided by the total
generation. In this case, the output-based approach simplifies the compliance issue by focusing
on the overall impact—that is, the total emissions per MWh independent of where in the plant
the emissions come from. This approach creates an incentive for the plant operator to use the
lowest-emitting, most efficient units available.
• If the regulation applies to each boiler, the output from the various generators can be allocated
to the boilers according to their steam output. In this case, the emissions for each boiler (Ib/hr)
are measured at each stack. The total electrical output (MW) is allocated to each boiler based
on the percentage of steam output (MMBtu/hour) generated by each boiler. Allocating based
on heat input to the boilers would not be as effective, however, because that procedure would
ignore the efficiency of the boilers.
For steam generators, thermal output (MMBtuheat output) must be measured. Most large boiler facilities
measure boiler thermal output as part of system operation. In many CHP facilities, the thermal output is
sold to a separate customer and is therefore measured for commercial billing purposes. Meters can be
installed to record the thermal output of the steam or hot water produced. Alternatively, the thermal
output can be calculated using measurements of the steam or water flow and temperature rise of the
thermal fluid. Mass emissions then would be divided by the thermal output to calculate lb/MMBtuheat
output*
4.4 Specify How to Calculate Emission Rates for Combined Heat and Power
Units
CHP has been shown to be beneficial from both an energy and environmental perspective and many
regulators would like to provide recognition for these benefits in their regulations by recognizing the
increased output of a CHP facility. CHP units produce both electrical and thermal output (e.g., process
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steam). Therefore, the rule must specify the method to account for the two different types of energy in
the compliance computation. Several approaches have been used in current regulations and guidance
documents. The different methods can result in different calculated levels of efficiency (i.e., more or less
energy output in the denominator of the emission rate) and different compliance measurement
requirements.
Two ways to account for the efficiency benefits of the thermal output of a CHP system are:
1. Equivalence approach. Add the thermal output of the steam to the electric output (in consistent
units) when calculating compliance. This method maximizes the total output recorded and reduces
the lb/output emission rate. Its actual impact on the output-based emission rate can vary
substantially based on the power-to-heat ratio.
2. Avoided emissions approach. Determine the amount of avoided emissions that a conventional
boiler system would otherwise emit had it provided the same thermal output (i.e., purchasing
electricity from the grid and generating steam on site). This approach relates the value of the
thermal output of the CHP system more directly to the emissions actually avoided by the CHP
system.
The two approaches are illustrated in the examples below. Consider a simple 1 MW gas turbine that has
emissions of 0.7 Ib/hr. Its emission rate is 0.7 Ib/MWh electric. In a CHP configuration, the turbine also
could produce a thermal output of about 5.7 MMBtu/hr (or about 5700 lb steam/hr of thermal output)
in addition to its electric output. Ensure that the output-based emission limit is 0.5 Ib/MWh.
Approach 1: equivalence approach (convert thermal output to an equivalent MWh and add to
the electric output)
This approach focuses on including the full output in the calculation. It converts all of the energy output
to units of MWh and compares the total emission rate to the emission limit. First, convert the thermal
output of steam to units of MWh by a unit conversion factor (1 MWh = 3.413 MMBtu). This results in a
thermal output of 1.67 MW output. Then, add the thermal and electric output to yield a total output of
1 MW + 1.67 MW = 2.67 MW. Dividing the measured stack emissions by this total output results in a
combined emission rate of 0.7 Ib/hr 4- 2.67 MW = 0.26 Ib/MWhth+e.
The equivalence approach can recognize 100 percent of the thermal output of steam in the compliance
calculation, and the greater overall efficiency of a CHP facility results in a lower emission rate. The rule
language would state that the output will be calculated as the electric output plus the thermal output in
MW based on the conversion of 1 MWh = 3.413 MMBtu of heat output.
Several states have used this approach. The Texas PBR and Standard Permit and California conventional
emission limits and emission performance standard use this method. The U.S. EPA's 1998 NSPS for utility
boilers used the same approach but included only half of the thermal output in the calculation when it
was first released; the rule was subsequently revised and now provides credit for 75 percent of the
thermal output in the calculation. Many of the states that recognize CHP's thermal output (including
Texas, California, Massachusetts, and Connecticut) have included the full thermal value in order to
benefit CHP.
The amount of energy output calculated by this method varies greatly depending on the power-to-heat
ratio of the CHP unit. For low P/H ratios (i.e., proportionally high steam generation compared to power),
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the equivalence approach will result in a relatively high total energy output. This is because at low P/H
ratios the unit operates more like a steam boiler than a utility boiler. Output-based emission limits for
steam boilers are very different (lower) than those for utility boilers because of the significant energy
losses caused by the turbine generators.
Approach 2: avoided emissions approach
This approach recognizes the thermal output by calculating the displaced emissions associated with the
thermal output and subtracting them from the measured emission rate. The displaced emissions are the
emissions that would otherwise have been generated to provide the same thermal output from a
conventional system (applying a new source emission rate).
The avoided emissions approach is a three-step process. First, compute the emission rate (Ib/MWh) of
the CHP unit based on the total measured emissions and the amount of electricity generated (ignoring
process steam use for now). Second, for the steam output, compute the emissions avoided (in Ib/MWh)
from a conventional boiler system that otherwise would have provided the same steam output. Third,
subtract the avoided emission rate from the initial Ib/MWh rate that was computed based only on
electrical output.
The regulation would specify a five-step process to determine the emission rate for compliance
purposes:
1. Determine a gross emission rate based on electrical output only. To do this, divide the measured
stack emissions by the metered electricity generated:
Gross emission rate (lb/MWhe|ectriC) = emissions (lb) 4- electrical output (MWh)
2. Determine the new source emission rate of the thermal generator that the CHP unit displaces.
Where a CHP system directly replaces an existing thermal generator, the calculation recognizes the
actual displaced emissions up to a maximum rate. The maximum rate would be established to
prevent the CHP system from receiving "excessive" recognition for displacing very old, very high-
emitting boilers that might be scheduled for replacement anyway. For new CHP systems or where
the emissions from the existing steam generation cannot be documented, the calculation for steam
generation would be based on the emission limits for a new gas boiler in the particular state. The
avoided emissions approach would provide a conservatively low estimate of displaced emissions.
3. Convert the emission rate of the displaced steam boiler from an input to a heat output-based rate
(lb/MMBtuout). The avoided emission rate is:
Ib/MMBtUheatoutput = Ib/MMBtUheat input ^ boiler efficiency
4. Convert the displaced emissions to Ib/MWh. To do so, relate the emission rate of the displaced unit
to the electricity produced by the CHP unit. First, convert the Btus of heat output to MWh of heat
output. (1 MWh is equivalent to 3.413 MMBtu.) The P/H ratio expresses how much thermal output
is produced per unit of electric output, so divide the thermal emission factor by the P/H ratio to get
the electric equivalent:
displaced emissions lb/MWhelectric = lb/MMBtuheat outputx 3.413^^ h- (P/H)
5. Subtract the displaced emission rate from the initial output-based emission rate, which was based
only on electrical energy, to obtain the net emission rate. The resulting CHP emission rate is then
compared to the emission limit:
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CHP emission rate (lb/MWhe|ectric) = Gross emissions (Ib/MWheiectric) - Displaced emissions
(Ib/MWhelectric)
Example Calculations for the Avoided Emissions Approach
Consider the same CHP project as in the previous example—a new 1 MWe combustion turbine CHP
system with a P/H ratio of 0.6 that must meet an emission standard of 0.5 Ib/MWh or less.
1. The measured gross emission rate based only on electrical output is 0.7 lb/MWhe|ectriC.
2. For this calculation, assume that the CHP unit displaces a typical small industrial boiler with an
efficiency of 80 percent. Because the avoided emissions are not known, assume the avoided
emissions for a new gas-fired boiler. The state regulation for new gas boilers is 0.05
lb/MMBtuheat input.
3. Compute the output-based new source emission rate for the thermal output as follows
(Equation 2). This is the avoided emission rate for an equivalent industrial boiler:
1.5 Ib/MMBtUheat input 80% efficiency = 0.06 lb/MMBtuheatoutput
4. Convert the displaced emissions by relating the thermal output emission rate to the electricity
produced by this CHP system. This calculation estimates the avoided emissions as a ratio of the
lb/MWe produced by the CHP. Based on the P/H ratio of 0.6, the emission displacement on an
electric basis would be:
1.5 Ib/MMBtu x 3.413 MMBtu/MWh h- 0.6 = 0.36 Ib/MWh
5. Adjust the gross emission factor. The gross emission rate is 0.7 Ib/MWh. Subtract the displaced
emissions of 0.36 Ib/MWh from the initial emission limit. The emission rate for compliance
purposes, therefore, is:
0.70 Ib/MWh - 0.36 Ib/MWh = 0.34 Ib/MWh
The unit, therefore, is in compliance with the emission limit of 0.5 Ib/MWh. The avoided emissions
approach yields an emission rate that is higher than Approach 1, which resulted in an emission rate
of 0.26 Ib/MWh. This is a function of the P/H.
V ;
Table 4-1 computes the displaced boiler emission rate (Steps 3 and 4) for a range of avoided emission
rates (Step 2).
Table 4-1. Displaced Boiler Emission Rate (lb/MWheiectric) for CHP Units
P/H
Displaced Thermal Emission41 Rate
Ib/MMBtUheat input)
0.01
0.04
0.05
0.1
0.2
0.3
0.4
0.5
0.09
0.30
0.40
0.85
1.71
2.56
3.41
0.7
0.07
0.22
0.29
0.61
1.22
1.83
2.44
1.0
0.05
0.15
0.20
0.43
0.85
1.28
1.71
*Assuming 80 percent boiler efficiency.
Many states set a typical emission limit for new gas boilers at 40 ppm (equal to approximately 0.05
Ib/MMBtu). So, for example, a combustion turbine-based CHP system with a P/H ratio of 0.7 would have
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a displaced emission rate of 0.29 lb/MWhe|ectriCto apply against the applicable limit. A reciprocating
engine with a P/H ratio of 1.0 would have a displaced emission rate of 0.20 lb/MWhe|ectriC.
If the avoided emissions per MWh are higher than the emissions from the CHP unit, the result will be a
negative emission rate. This could happen if the avoided boiler has a very high emission rate (e.g., for
replacement of an old, high-emitting boiler) and/or a very low P/H ratio. While this may seem counter-
intuitive, it can be an accurate representation of the emission benefit of the CHP system. That said,
some regulators may choose to adjust the emission factor for an older, high-emitting boiler to a lower
factor comparable to a new boiler in order to avoid giving credit based on an out-of-date emission limit,
This would reduce the likelihood of a negative result.
4.5 Summary of Steps to Develop an Output-Based Standard
Table 4-2 briefly summarizes the information that is provided in this section.
Table 4-2. Summary of Rule Development Steps
1. Develop the output-
based emission limit.
Two methods are provided:
a. An emission limit can be based on measured emissions and energy
output data.
b. An input-based emission limit can be converted to an output-based
format using the procedures in this section:
- Conversion from lb/MMBtuheatinput for electric generators or steam
boilers.
- Conversion from flue gas concentration for combustion
turbines.
- Conversion from g/bhp-hr for engine generators.
2. Specify a gross or net
energy output format.
Net energy output will more comprehensively account for energy efficiency, but can
increase the complexity of compliance monitoring requirements.
3. Specify compliance
measurement methods.
The energy forms that must be measured are electricity generated (MWh), thermal
output (MWh or Btu), and shaft power (bhp-hr). These outputs are monitored at
most facilities for commercial purposes.
4. Specify how to calculate
emission rates for CHP
units.
Two methods are described:
a. Equivalent MWh output approach
b. Avoided boiler emissions approach
These two methods provide different results and, thus, different levels of
recognition of the efficiency benefits of a given CHP application. Neither is more
"correct" than the other, but the equivalent MWh output approach may be simpler
to calculate and can result in significantly lower calculated emission rates for low
P/H technologies.
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4.6 Summary of Steps to Comply with an Output-Based Standard
1. Determine compliance
procedures.
Compliance forms, permit forms, or other necessary documentation must be
obtained. The method that is used will depend on whether or not measured
energy output data are available.
2. Determine the data
necessary for
compliance.
Review the compliance calculation and other inputs to determine what data are
needed to calculate the emission limit from the CHP system. Electric output data
typically measured in MWh and thermal output measured in MMBtu are often
required.
3. Implement appropriate
data collection
procedures
Install appropriate emission and output measurement devices (electric and
thermal) and collect emission and output data.
4. Calculate compliance.
Use the required calculation to determine the output-based emission limit for the
CHP system.
5. Submit completed
compliance or other
necessary forms.
To the state utility regulatory agency or other appropriate authority.
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Section 5. Examples of Output-Based Regulations
A number of federal, regional, and state programs have recently adopted output-based regulations.
These regulations include emission standards for large and small generators, cap and trade allowance
allocation systems, multi-pollutant regulations, and generation performance standards. Table 5-1 lists
existing output-based regulatory programs that apply to electric and thermal generation. Each of these
programs is described more fully in Appendix B. Appendix B briefly describes the rule, jurisdiction,
applicability (type and size of units covered), specific emission limits or provisions, timing, treatment of
CHP units, references to rule language, and other relevant information.
Table 5-1. List of Current Output-Based Programs
Type of Program
Regulatory Purview
Output-Based Features
Federal NSPS Regulations
NSPS for Stationary Combustion
Turbines
Emission limit (Ib/MWh) gross output
NSPS for Industrial-Commercial-
Institutional Steam Generating Units
Emission limit (Ib/MWh) gross output
NSPS for Stationary Compression
Ignition Internal Combustion Engines
Emission limit (g/KW-hr or g/HP-hr)
NSPS for Stationary Spark Ignition
Internal Combustion Engines
Emission limit (g/HP-hr)
NSPS for Aluminum Reduction Plants
Emission limit (kg/Mg) or (lb/ton)
NSPS for Electric Steam Generating
Units
Emission limit (Ib/MWh) gross output and
(Ib/MWh) net output
Federal NESHAP
NESHAP for Area/Sources: Electric
Arc Furnace Steelmaking Facilities
Emission limit (lb/ton)
NESHAP for Industrial, Commercial,
and Institutional Boilers and Process
Heaters (Boiler MACT)
Emission limit (Ib/MMBtu) steam output or
(Ib/MWh)
NESHAP for Coal- and Oil-Fired
Electric Utility Steam Generating
Units (MATS rule)
Emission limit (Ib/MWh) or (Ib/GWh)
Conventional state emission
rate limits
New Jersey mercury emission limits
Emission limit (mg/MWh)
State emission standards
for distributed generation
New Hampshire
Emission tax (Ib/MWh)
California
Emission limit (Ib/MWh)
Delaware
Emission limit (Ib/MWh)
Rhode Island
Emission limit (Ib/MWh)
Texas
Emission limit (Ib/MWh)
Regulatory Assistance Project
Model rule with output-based emission
limit (Ib/MWh)
Connecticut
Emission limit (Ib/MWh)
Maine
Emission limit (Ib/MWh)
Massachusetts
Emission limit (Ib/MWh)
New York
Emission limit (Ib/MWh)
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Table 5-1. List of Current Output-Based Programs
Type of Program
Regulatory Purview
Output-Based Features
State NOx Budget Trading
Programs
Connecticut
Allocation of allowances
Massachusetts
Allocation of allowances
Missouri
Allocation of allowances
New Hampshire
Allocation of allowances
New Jersey
Allocation of allowances
Ohio
Allocation of allowances
CAIR state programs
Arkansas
Allocation of allowances
Connecticut
Allocation of allowances
Illinois
Allocation of allowances
Indiana
Allocation of allowances
Massachusetts
Allocation of allowances
New Jersey
Allocation of allowances
Ohio
Allocation of allowances
Pennsylvania
Allocation of allowances
Wisconsin
Allocation of allowances
RGGI state programs
Connecticut
Allocation of set-asides
Massachusetts
Allocation of set-asides
New York
Allocation of set-asides
State multi-pollutant
Programs
Massachusetts
Emission limit (Ib/MWh)
New Hampshire
Allocation of allowances
State generation emission
performance standards
California
Performance standard (Ib/MWh)
New York
Performance standard (Ib/MWh)
Oregon
Performance standard (Ib/MWh)
Washington
Performance standard (Ib/MWh)
New Source Review
Connecticut
Lowest achievable emission rate option
To provide additional insight into the technical and policy considerations of setting output-based
standards, four of these programs are described in more detail below:
• Section 5.1 describes the output-based approach that EPA used in revisions of the electric utility
boiler NSPS (subpart Da). This action reflected a major change in approach for the NSPS and
provided an efficiency-based rationale for transitioning to output-based regulation. This section
also discusses EPA's proposed greenhouse gas (GHG) NSPS for new power plants, which either
would include GHG standards for electric utility boilers in subpart Da and applicable GHG
standards for stationary combustion turbines in subpart KKKK or could include GHG NSPS
standards for these types of systems under a new subpart Mil.
• Section 5.2 describes a model rule for output-based standards for small electric generators. The
model rule is a good example of a straightforward output-based emission limit program that
recognizes the thermal output of CHP.
• Section 5.3 describes the EPA guidance on how to allocate emission allowances for the NOxSIP
Call and the later CAIR based on output. The NOx SIP Call approach was developed by a
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stakeholder group of EPA, states, industry, and environmental groups. The guidance thoroughly
discusses how output-based allocation can be applied.
• Section 5.4 describes EPA guidance on how output-based emission limits were determined
under EPA's Utility Boiler New Source Performance Standard (40 CFR 60 Subpart Da).
In 1998, EPA promulgated revisions to the NSPSfor NOxfrom Electric Utility Steam Generating Units.
The revised NSPS reflected advances in NOx control technology and a change to a uniform output-based
NOx regulation (Ib/MWh). This action was the first NSPS for boilers that incorporated output-based
emission limits. In the rationale for revisions, EPA stated that it had "established pollution prevention as
one of its highest priorities" and that "one of the opportunities for pollution prevention lies in simply
using energy efficient technologies to minimize the generation of emissions" (62 FR 36954). Up to this
point, the basis for boiler emission standards had been boiler input energy (i.e., pounds of pollutant per
million Btu of heat input). The rule also was the first NSPS to recognize the thermal output of CHP
facilities, in this case using the equivalence approach. It allows for CHP systems to account for 75
percent of their thermal output in calculating their output-based emissions.10 EPA has revised its boiler
NSPS (subpart Da) several times since 1998.
EPA considered several different output-based formats. The final structure of the rule was based on the
following goals:
1. Provide flexibility in promoting energy efficiency.
2. Permit measurement of parameters related to stack NOx emissions and plant efficiency on a
continuing basis.
3. Be suitable for equitable application to a variety of power plant configurations.
The basis of EPA's decisions on the format of the rule is explained below.
5.1.1 Units of Measure
The revised NOx emission limit is measured in Ib/MWh. EPA considered basing the emission limit on lb
per gross boiler steam output (lb/MMBtuheat output)- EPA determined that the latter approach accounted
for the boiler efficiency only and ignored turbine cycle efficiency. Since this did not meet one of EPA's
goals—providing maximum flexibility in an output-based format—EPA decided that it would not be an
acceptable basis. Therefore, EPA selected the Ib/MWh format.
5.1.2 Net Versus Gross Energy Output
EPA also decided to define energy output in terms of gross energy output in the 1998 revisions;
however, in rule revisions proposed in 2011, EPA decided to also define energy output in terms of net
energy output for an affected facility that began construction or reconstruction on or after May 3, 2011.
Initially, EPA proposed the emission limit based on net energy output because it wanted to account for
both turbine cycle efficiency and internal plant energy efficiency. Concerning the 1998 rule
amendments, several commenters on the rule claimed that monitoring net electrical output was not
practical because it:
10 http://www.epa.gov/ttn/atw/nsps/boilernsps/boilernsps.html
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• Would require significant and costly changes to the existing monitoring systems.
• Could not be measured directly due to the amount of auxiliary electrical equipment at a plant.
• Did not account for the power drain associated with many types of pollution control equipment.
• Would be difficult at plants where both NSPS and non-NSPS units existed.
• Was not well understood because EPA did not provide a specific methodology for determining
net output in the proposal.
In the 2011 rule revisions, EPA proposed emission limits based on net energy output since this would
provide a greater incentive for improving overall energy efficiency and minimizing parasitic loads. (In
general, EPA found that about 5 percent of station power is used internally by parasitic energy demands,
though this number varies based on the source.) In its proposed rule changes, EPA noted that a net
output approach could result in monitoring difficulties and unreasonable monitoring costs at modified
units. However, monitoring net output for new and reconstructed units can be designed into the facility
at a low cost.11
5.1.3 Selection of the Emission Limit for New Units
The emission limit for new sources that began construction after July 9, 1997, but before March 1, 2005,
is 1.6 lb NOx/MWh gross energy output. EPA initially proposed an emission limit of 1.35 Ib/MWh net
energy output but decided to change the emission limit in response to comments received after
proposal and further analysis of utility units.
The proposed emission limit was based on the use of selective catalytic reduction to reduce NOx
emissions to 0.15 lb/MMBtuheatinpUt. EPA applied an efficiency factor to convert the format to an output-
based limit. According to EPA's review of power plant efficiency, most plants fell into the range of 24 to
38 percent efficiency. EPA concluded, however, that newer units (both coal and gas) operate at about 38
percent efficiency, which corresponds to a heat rate of 9,000 Btu per kilowatt hour. This figure was the
baseline chosen at proposal, and it resulted in an equivalent output-based emission limit of 1.35
Ib/MWh.
0.15 Ib/MMBtu x 9,000 Btu/kWh x 1,000 kWh/MWh h- 1,000,000 Btu/MMBtu = 1.35 Ib/MWh
After proposal, a majority of commenters opposed the selection of an assumed 9,000 Btu/kWh heat rate
for use in converting the input-based emission limit to an output-based emission factor. Several
commenters provided examples of state-of-the art units that could not achieve the 9,000 Btu/kWh heat
rate that EPA used to set the output-based emission limit. EPA conducted statistical analyses of the data
submitted by the commenters and collected additional data to assess the long-term NOx emission levels
that were achievable on an output basis by new units. Considering these new data, EPA promulgated an
emission standard based on actual measured output data rather than converted heat input data. This
analysis resulted in an output-based emission limit of 1.6 Ib/MWh for the 1998 rule. In later revisions,
EPA issued lower output-based NOx emission limits for new affected facilities.
11 http://www.epa.gov/ttn/atw/utility/fr03myll.pdf.
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5.1.4 Modified and Reconstructed Units
The revised 1998 NSPS retained an input-based format for existing sources that become subject to the
NSPS by reconstruction. In response to the proposed rule, a number of commenters objected to the fact
that the proposed output-based limit was not achievable at a reasonable cost by all existing sources.
Commenters claimed that EPA's assumed heat rate of 9,000 Btu/kWh (equivalent to 38 percent
efficiency) was appropriate for new units and modified units and that existing units should not be
required to meet the same output-based standard as new sources. The higher heat rates associated
with older, less efficient plants would cause those plants to have a more difficult time complying with
the standard. To compensate for the higher heat rates, these existing units might have to use more
expensive control devices with higher NOx removal performance. In justifying the final rule, EPA noted
that while most utility plants have efficiencies ranging from 24 to 38 percent, existing plants are likely to
operate in the lower end of this efficiency range, which would make meeting an output-based standard
more costly. Therefore, to minimize this potential burden, EPA decided to require modified and
reconstructed units that become subject to the NSPS to meet a standard of 0.15 lb NOx/MMBtuheat input-
In later revisions, EPA issued output-based emission limits and also alternative heat-input-based limits
for units that began reconstruction or modification after February 28, 2005, but before May 4, 2011.
EPA also issued separate limits for affected facilities that began reconstruction or modification after May
3, 2011.
The revised NOx emission limits for new, reconstructed, and modified affected facilities are as follows:
Effective Date
NOx Emission Limit
Affected facility that commenced construction
after July 9,1997, but before March 1, 2005
1.6 Ib/MWh gross energy output
Affected facility that commenced reconstruction
after July 9,1997, but before March 1, 2005
0.15 lb/MMBtuheatmput
Affected facility that commenced construction
after February 28, 2005, but before May 4, 2011
1.0 Ib/MWh gross energy output
Affected facility that commenced reconstruction
after February 28, 2005, but before May 4, 2011
1.0 Ib/MWh of gross energy output or0.ll lb/MMBtuheatinput
Affected facility that commenced modification
after February 28, 2005, but before May 4, 2011
1.4 Ib/MWh of gross energy output or0.15 lb/MMBtuheatinpUt,
regardless of fuel type
Affected facility that began construction or
reconstruction after May 3, 2011
0.70 Ib/MWh of gross energy output or 0.76 Ib/MWh net
energy output; applies regardless of boiler or fuel type
(except coal)
Affected facility that began construction or
reconstruction after May 3, 2011, that burns 75
percent or more coal refuse (by heat input) on a
12-month rolling average basis
0.85 Ib/MWh gross energy output or 0.92 Ib/MWh net
energy output
Affected facility that made modifications after May
3, 2011
1.1 Ib/MWh gross energy output
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5.1.5 Treatment of Combined Heat and Power Plants
In applying the regulation to a utility boiler that incorporates CHP, one must account for both the
electrical energy output and the thermal output (typically steam). For CHP, the revised 1998 NSPS
defines "gross energy output" as the gross electrical output plus 50 percent of the gross thermal output
of the process steam (converted to units of MWh). The 50 percent steam conversion policy was based
on a Federal Energy Regulatory Commission regulation that defines the efficiency of CHP units as "the
useful power output plus one half the useful thermal output" (18 CFR 292, section 205). EPA later (2006)
revised this definition of "gross energy output" to mean the gross electrical or mechanical output from
the affected facility plus 75 percent of the useful thermal output. The rule was again revised for CHP
systems that were constructed, reconstructed, or modified after May 3, 2011. The definition of "gross
energy output" for these CHP systems is the gross electrical or mechanical output from the affected
facility divided by 0.95, minus any electricity used to power the feedwater pumps and any associated
gas compressors, plus 75 percent of the useful thermal output.
In establishing its 1998 rule, EPA rejected two other approaches for determining how to account for
process steam at CHP plants: (1) consider valuing steam assuming it will be used to generate electricity
and (2) consider valuing steam at greater than 50 percent of its heat value, up to 100 percent. Valuing
steam as if it were being converted to electricity would cap the energy value at 38 percent of the heat
value of the steam (based on the maximum reported efficiency for electrical production with a steam
turbine). Because EPA wanted to encourage CHP, it did not choose this option. The Agency did not
choose the option of allowing for more than 50 percent of the heat value of steam because it concluded
that including all of the thermal output created a potential for calculating an "artificially high" output
rate, especially if a large amount of steam is exported. As a sub-option, EPA also considered allowing
100 percent of the heat value, but limiting the amount of thermal energy to a specified percentage of
total output. Ultimately, EPA determined that this approach was too complex from a monitoring
standpoint. Therefore, EPA adopted the policy of 50 percent thermal energy for steam from CHP plants
because the policy will encourage energy efficiency, will not result in artificially high output rates, and
will not require complex monitoring.
5.1.6 NSPS C02 Limits
EPA is currently working on establishing GHG emission limits for new and existing power plants. EPA
released a revised proposed rule to limit GHG emissions from new power plants in January 8, 2014. The
proposed NSPS for new power plants is intended to apply generally to those boilers currently regulated
under subpart Da and to stationary combustion turbines regulated under 40 CFR subpart KKKK.12 The
proposal is an output-based standard that ranges from 1,000 to 1,100 lb C02/MWh based on fuel use
and unit size. EPA's GHG NSPS proposal for new power plants uses the equivalence approach to give
credit to CHP systems in which the useful electric or mechanical output is at least 20 percent of the total
energy output and the useful thermal output is at least 20 percent of the total energy output. CHP
systems that meet this eligibility criterion will receive credit similar to that in subpart Da and the
proposed amendments to subpart KKKK (77 FR 52554). The measured electric output would be
discounted slightly by dividing by 0.95 to account for a 5 percent avoided energy loss in the transmission
12 EPA has proposed changing applicability language slightly to benefit third-party CHP developers that would otherwise be
penalized slightly based on current subpart Da applicability language.
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of electricity (EPA's subpart Da language currently uses the same discount).13 EPA's proposed GHG NSPS
for new power plants was open for public comment through May 9, 2014.14
EPA released a proposal to regulate GHG emissions from existing power plants on June 2, 2014. Existing
units are defined as those that were in operation or had commenced construction as of January 8, 2014.
The proposal requires states to meet C02 emission targets starting in 2020 on a state-wide basis. The
proposed rule is expected to reduce C02 emissions by 30 percent below 2005 levels by 2030. State
targets proposed by EPA vary widely based on the "unique mix of emissions and power sources" in each
state and are output-based. EPA gives states the option to convert the rate-based targets into mass-
based goals incorporating renewable and nuclear generation and end use efficiency in setting the goals.
The thermal output of affected CHP systems is credited at 75 percent. EPA plans on releasing a final rule
by June 2015, and will require states to submit their implementation plans by June 30, 2016. However,
extensions for SIP submittal of up to one year may be granted upon request, and an extension of up to
two years may be granted to states that are implementing multi-state plans.
5.2 RAP National Model Emission Rule for Distributed Generation
In 2000, the National Renewable Energy Laboratory engaged the Regulatory Assistance Project (RAP) to
facilitate the development of a uniform, national model emission rule for small DG equipment. Interest
in regulating emissions from DG had been building in recent years due to the increased development of
small generators, including microturbines, fuel cells, and small engines. More importantly, there had
been increasing concern over the use of high-emitting diesel engin
for load response or peaking applications. The development of DG
emission regulations in Texas and California had sparked concern
that many individual states would develop emission standards for
DG and create an overly complex, conflicting set of permitting
requirements that would limit the development of DG. The goal of
the model rule project was to develop a model rule that could be
uniformly applied throughout the United States and provide appropriate environmental protections and
technology drivers for DG.
The stakeholder group involved with the process consisted primarily of state energy and environmental
regulators with a few participants from the DG industry and representatives from EPA, the U.S.
Department of Energy, and environmental groups. The model rule was completed in February 2003. The
emission limits for the model rule are presented in Appendix B.
5.2.1 Format of the Rule
The stakeholder group established from the beginning that the rule would be expressed in an output-
based format. Several of the participants had been involved in the development of the output-based
Texas and California DG rules, and agreed that reflecting efficiency in the regulation was important—
especially for very small DG units that do not typically use add-on controls. For these units, pollution
prevention and efficiency are the primary emission control alternatives and must be recognized by
13 http://www.gpo.gov/fdsys/pkg/FR-2014-01-08/pdf/2013-28668.pdf.
14 http://www2.epa.gov/carbon-pollution-standards/2013-proposed-carbon-pollution-standard-new-power-plants.
To learn more about
Regulation Assistance Project
Model Rule for output based
emission regulation, see
www.raponline.org.
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regulation. In addition, the rule sets one standard for all technologies, so the standard must be in units
that can be applied to all technologies. An output-based limit in Ib/MWh meets this requirement.
Finally, the participants wanted the rule to account for the efficiency of CHP and potentially recognize
renewable technologies. An output-based approach allowed the flexibility to achieve both of these
goals.
5.2.2 Treatment of Combined Heat and Power
RAP made providing recognition for CHP an important priority in the rule development process. The
group evaluated several possible methods. Several prior rules had recognized CHP by including the
thermal output converted to electric equivalent as part of the output calculation (equivalence
approach). Although this method does recognize the thermal output, the effect is largely a function of
the relative amounts of thermal and electric energy created and is not tied to the actual environmental
benefit of the CHP created by displacing conventional emitting units.
The RAP group decided to take an approach based on calculation of the displaced emissions from the
thermal output (avoided emissions approach—see section 4.4). The emission standards apply to the
electrical output of the system, and the measured emissions are reduced based on the emissions
avoided by the displacement of a thermal generator (steam boiler) providing the same thermal output
as the CHP system. For a greenfield CHP facility, the avoided emissions are based on the emission limits
applicable to a new natural gas boiler. For a retrofit system, the avoided emissions are based on the
emission rate of the boiler actually displaced by the system. There is a cap on this avoided emission rate,
however, to avoid basing the displacement on old, very high-emitting boilers.
5.3 EPA Guidance on Output-Based NOx Allowance Allocations
In October 1998, EPA issued the NOx SIP Call to reduce regional transport of ozone in the 22
northeastern states. To meet the requirements of the SIP Call, states can adopt further emission
regulations or participate in a
regional cap and trade program. In
this cap and trade program, EPA
allocated NOx allowances for an
ozone season cap and trade
program to the states, but it allowed
each state to allocate the
allowances to individual emission sources in the state.
Although the most prominent model for this allocation was the input-based allocation approach of the
acid rain S02 trading program, there was increasing interest in an output-based allocation system that
would account for the benefits of new, more efficient generators. Despite this interest, stakeholders had
a lot of questions about the actual mechanics of output-based allocation systems and whether such a
system could be efficiently implemented.
EPA convened a stakeholder working group to investigate and analyze these questions and assist in
developing guidance for states interested in applying output-based allocation in their NOxtrading
programs. The group was composed of EPA staff, industry representatives, state regulators, and
To learn more about output-based allowance allocations,
read Developing and Updating Output-Based NOx Allowance
Allocations, Guidance for States Joining the NOx Budget
Trading Program Under the NOx SIP Call, May 8, 2000
(http://www.epa.gov/airmarkets/progsregs/nox/docs/finalo
utputguidanc.pdfj.
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environmental groups. It worked for most of 1999 and produced a guidance document that addresses
issues including:
• The types of facilities to which the guidance applies.
• The assignment of allowances to units, plants, or generators.
• Technical and policy concerns in selecting the location for measuring or calculating output data
to be used in allocations.
• Requirements for sources, such as monitoring, recording, and reporting output data.
• Potential sources of output data.
• Regulatory provisions to include in state rules and actual regulatory language specifying the
allocation procedures.
Some of these issues are summarized in the following sections.
5.3.1 Allocation of Allowances
Perhaps the most basic issue considered by the stakeholder group was the actual mechanism for
allocating allowances on an output basis, including industrial boilers and CHP facilities. The basic
concept is that each unit receives allowances in proportion to its share of the total energy output in the
state. In most states, a separate pool of allowances was established for electric generators and for
industrial boilers. Under an output-based allocation program, an electric generating unit that generates
5 percent of the total electricity generated in the state would receive 5 percent of the allowances
available for electric generators. An industrial boiler that generates 5 percent of the total thermal
output generated in the state would receive 5 percent of the allowances available for industrial boilers.
A CHP facility would receive a share of each pool based on its generation of electricity and steam. If a
CHP facility generated 2 percent of the electricity and 3 percent of the steam in the state inventory of
affected units, it would receive 2 percent of the electricity allowances and 3 percent of the boiler
allowances. The guidance document presents a variety of examples of these allocation procedures and
some variations for states whose emission pools are organized differently. Overall, however, the
guidance illustrates that the procedure is straightforward and relatively simple.
One related issue was that a one-to-one relationship does not always exist between emission units and
electric generating units. Compliance is based on emission units but an output-based allocation would
relate to generating units. Some stakeholders asked whether this situation creates a problem for
compliance or enforcement. The stakeholder group determined that enforcement would remain the
same, regardless of how the allowances are allocated. It is up to the sources to ensure that they have
adequate allowances in their compliance account at the facility level, regardless of how many emission
units are on site. The allocation basis does not change the approach for the source either, as long as the
plant operators can transfer allowances as needed to cover the actual emissions from their emission
units. In fact, some industry representatives suggested that to allocate allowances at the plant level
rather than at the unit level—whether based on emissions or output—would be just as easy from a
compliance perspective.
5.3.2 Availability, Measurement, and Reporting of Output Data
One of the biggest obstacles to output-based regulations is concern about the collection of data on
output. Environmental regulators are familiar with collecting data on heat input and emissions, but not
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output. The stakeholder group determined that collecting these data is new for many regulators but
does not present any fundamental technical barriers.
One of the key insights is that the productive output of a process is a commercial product and is
therefore accurately measured for commercial purposes. In other words, utilities must measure their
generation in order to get paid. Measurement of the electric output of a generating unit is
straightforward and highly accurate and is a normal order of business for most generators. Similarly,
many CHP facilities are in the business of selling steam and must measure thermal output for
contractual purposes. While this is less true for thermal output of industrial boilers, most operators of
large boilers measure their steam output for plant management purposes. The group found that
accurate measurement technology is available "off-the-shelf" for electric and thermal output streams,
so that in the end these data are likely to be more accurate than the heat input data used in input-based
allocation systems.
A more complex question is how to measure the output. This issue is also referred to as the "net versus
gross" issue. In a large facility, some of the electricity and/or steam is used internally to operate plant
systems, including pollution control devices. The electric output could be measured at the generator
terminals (gross) or after the internal loads as it leaves the plant (net). From the policy perspective, the
net output is the preferable concept because it indicates the actual energy available from the plant.
Some stakeholders suggested that in a net energy approach, energy used for pollution control devices
should not be subtracted from the gross output, because it benefits the environment. Others pointed
out, however, that there are different ways to reduce emissions, and subtracting energy used for
pollution control would be an incentive for more efficient pollution prevention techniques.
Actually determining how to measure net output can be difficult for a complex power generation or
industrial facility. The energy flows are complicated and sometimes the plant uses grid electricity (i.e.,
not generated on site) for some of its parasitic loads. The plant may have co- located facilities
(administrative offices not directly related to the plant operation) that use some of the power generated
on site that should not be subtracted for allocation purposes. The guidance document produced by the
stakeholder group provides a number of diagrams illustrating how and where net and gross output
should be measured. In the end, the final guidance allows regulators to choose either net or gross
output, whichever method is most expedient. For very small generators, the net versus gross decision
might not be relevant because parasitic loads are internal to the prime mover.
Overall, the guidance document provides a highly effective "cookbook" for the implementation of
output-based allocation. Since its release, several states have implemented these approaches and have
operated emission trading programs with output-based allocation. The NOx SIP Call output-based
guidance document also served as a basis for states to implement output-based allocations under EPA's
CAIR rule, which regulates NOx and S02 emissions. CAIR covers 27 eastern states and the District of
Columbia. On April 29, 2014, the Supreme Court reversed a lower court ruling vacating CSAPR, which is
intended to be a successor to CAIR. At this time, CAIR remains in place until EPA has time to review the
opinion and decide upon a course of action.
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5.4 Utility Boiler Maximum Achievable Control Technology Standards
In December 2012, EPA finalized "National Emission Standards for Hazardous Air Pollutants for Major
Sources: Industrial, Commercial, and Institutional Boilers and Process Heaters." This rule is commonly
referred to as the "Boiler MACT." It impacts large boilers and process heaters at industrial, commercial,
and institutional facilities that have the potential to emit 10 tons per year (tpy) or more of any single
HAP, or a combination of such pollutants in excess of 25 tpy. The covered pollutants include CO (as a
surrogate for organic HAP), hydrogen chloride, mercury, filterable PM, or total selected metals. Existing
sources must comply with the standards by January 31, 2016; however, if needed, may request from
their permitting authority an additional year to comply.
Under the rule, all boilers must follow work practice standards that include annual boiler tune-ups and a
one-time energy assessment. These work practice standards complete the compliance obligation for
natural-gas-fired boilers and existing small (<10 million Btu per hour heat input) coal- and oil-fired
boilers; however, large coal and oil-fired boilers must meet the emission limits specified in the rule. The
rule presents an opportunity for major source sites with coal- and oil-fired boilers to consider switching
to natural gas, and subsequently to consider natural-gas-fired CHP,15 instead of installing costly emission
controls to comply with the rule. The compliance date for existing major sources is January 31, 2016;
existing sources that install CHP can have until January 31, 2017 (sources may request an additional year
to comply if they need the time to install controls or to repower; this includes the installation of CHP,
waste heat recovery, or gas pipeline or fuel feeding infrastructure).
5.4.1 Allocation of Allowances
The Boiler MACT has alternative output-based limits for all pollutants, and the thermal and electric
output are used to calculate compliance. The output-based limits are an alternative "applicable only to
boilers and process heaters that generate steam." The limits are expressed in Ib/MMBtu of steam
output. "Steam output," in the context of CHP, means "For a boiler that cogenerates process steam and
electricity (also known as combined heat and power), the total energy output, which is the sum of the
energy content of the steam exiting the turbine and sent to process in MMBtu and the energy of the
electricity generated converted to MMBtu at a rate of 10,000 Btu per kilowatt-hour generated (10
MMBtu per megawatt-hour)."
15 http://www. epa. gov/chp/documents/boiler_opportunity.pdf.
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Appendix A: Energy Conversion Factors
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Appendix A: Energy Conversion Factors
Energy Conversions
Conversion from Btu higher heating value (HHV) to Btu lower heating value (LHV)
multiply by 0.91 for natural gas
multiply by 0.94 for diesel
Conversion from Ib/MMBtu HHV to Ib/MMBtu LHV
multiply by 1.099 for natural gas
multiply by 1.064 for diesel
HHV
LHV
Natural gas (Btu/cf)
Natural gas (Btu/lb)
Diesel (Btu/gallon)
Diesel (Btu/lb)
1,030
21,980
137,000
19,490
937
20,000
128,780
18,320
1 horsepower hour (hp-hr) = 2,545 Btu
1 kW = 3,413 Btu per hour (Btu/hr)
1 kWh = 3,413 Btu
0.7457 kW = 1 hp
1,000,000 Btu = 1 MM Btu = 392.9 hp-hr
1 MMBtu/hr = 293 kW
1 MMBtu = 293 kWh
1 kW = 1.341 hp
Turbines
NOx emissions for turbines are typically presented as parts per million (ppm) reported at 15 percent 02
in the exhaust stack. Other means of reporting emission use heat input (lb per MMBtu), output (lb per
MWh), and time (tons per year).
Conversion from Ib/MMBtu to ppm
From Ib/MMBtu HHV to ppm @15% 02
For Natural Diesel Gas
NOx
272
258
CO
446
423
S02
196
185
From Ib/MMBtu LHV to ppm @15% 02
For Natural Diesel Gas
NOx
248
235
CO
406
385
S02
178
169
Conversion from ppm to Ib/MWh using heat rate
Ib/MWh = (ppm @15% O?) x (Btu HHV/kWh heat rate)
(272 x 1,000)
or
Ib/MWh =(ppm @15% O?) x (Btu LHV/kWh heat rate)
(248 x 1,000)
Example:
Ib/MWh = (25 ppm) x (10.500 Btu HHV/kWh) = 0.97 Ib/MWh
(272 x 1,000)
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Conversion from ppm to Ib/MWh using efficiency
n (ppm @15% 02)x (3.413) (ppm @15% 02) x (3.413)
lb/MWh = or =
(272) x (% efficiency HHV) (248) x (% efficiency HHV)
Example:
(25 ppm) x (3.413)
lb/MWh = vv ,n o9r, = 0-97 lb/MWh
(272) x (0.325)
Conversion from Ib/MWh to tons/year
tons/year = (Ib/MWh emission rate) x (MW capacity) x (% utilization) x (8,760 4- 2,000)
Example:
tons/year = (0.951 Ib/MWh) x (5 MW) x (0.30 utilization) x (8,760 4 2,000) = 6.25 tons/year
Engines
NOx emissions for engines typically are reported as g/hp-hr. Other means of reporting emission use heat
input (Ib/MMBtu), concentration (ppm) and time (tons per year).
The efficiency of engines is described in terms of percent efficiency or brake-specific fuel consumption
(BSFC) in Btu/hp-hr.
Conversion from BSFC to % efficiency
% efficiency = 2,545 / (BSFC Btu/hp-hr)
Example:
% efficiency = 2,545 / (7,276 Btu/hp-hr) = 35% efficiency
Conversion from g/hp-hr to lb/MWh
Ib/MWh = (g/hp-hr) x (3.11) (including 95% generator efficiency)
Example:
Ib/MWh = (5 g/hp-hr) x (3.11) = 15.55 Ib/MWh
Conversion from g/hp-hr to Ib/MMBtu
Ib/MMBtu HHV = (g/hp-hr) x (efficiency of engine HHV) x (0.866)
Example:
Ib/MMBtu HHV = (5 g/hp-hr) x (0.35) x (0.866) = 1.52 Ib/MMBtu HHV
Conversion from g/hp-hr to ppm
ppm @15% 02 = (g/hp-hr) x (efficiency of engine HHV) x (235) for natural-gas-fired engines ppm @15%
O2 = (g/hp-hr) x (efficiency of engine HHV) x (223) for diesel-fired engines
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Example:
ppm @15% 02 = (5 g/hp-hr) x (0.35) x (235) = 411 ppm @15% 02
Conversion from g/hp-hr to tons/year
tons/year = (g/hp-hr) x (hp capacity) x (% utilization)
(103.6)
Example:
tons/year = (5 g/hp-hr) x (3,000 hp) x (0.30 utilization) = 43.4 tons/year
(103.6)
Conversion between different 02 corrections for ppm reporting
ppm @actual %02 = (ppm @15% 02) x (20.9 - actual % 02)
(20.9-15)
Example:
ppm @1% 02 = (346 ppm @15% 02) x (20.9 - 1) x (1 h- (20.9 - 15)) = 1,167 ppm @ 1% 02
Generalized conversion from ppm to Ib/MMBtu
Ib/MMBtu = (ppm NOx @actual % 02) x (20.9) x (Fd) x (K)
(20.9 - actual % 02)
Fd HHV = 8,710 dscf/MMBtu HHV for natural gas
Fd HHV = 9,190 dscf/MMBtu HHV for diesel
Example: natural gas turbine at 15% 02
Ib/MMBtu = (25 ppm) x (20.9) x (8,710) x (1.194 x 10"7) h- (20.9 - 15) = 0.092 Ib/MMBtu HHV
Fd Factors from EPA Method 19 K Factors
Fd K
Fuel dcf/106 Btu Pollutant (lb/scf)/ppm
Coal: NOx 1.194 xlO"7
Anthracite 10,100 S02 1.660 x 10"7
Bituminous 9,780 CO 7.264 x 10"8
Lignite oil 9,860
Oil* 9,190
Gas:
Natural 8,710
Propane 8,710
Butane 8,710
Wood 9,240
Wood bark 9,600
MSW 9,570
* Crude, residual, or distillate.
Output-Based Regulations:
A Handbook for Air Regulators
A-3
Appendix A
-------
Appendix B: Existing Output-Based
Regulations
Output-Based Regulations:
A Handbook for Air Regulators
Appendix B
-------
Appendix B: Existing Output-Based Regulations
This appendix lists and describes output-based regulations currently in effect or under development.
B.l Conventional Emission Rate Limit Programs
Conventional emission rate regulations, such as New Source Performance Standards (NSPS), reasonably
available control technology (RACT), or maximum achievable control technology (MACT), can be made
output-based simply by changing the format of the standards. These types of regulations can allow
energy efficiency to act as a pollution control measure and enable more direct comparisons among
regulated entities. They can also include provisions that account for the energy efficiency and pollution
reduction benefits of combined heat and power (CHP) projects.
B.l.l New Source Performance Standards for Utility Boilers
NSPS are technology-based emission standards that are set for specific processes and pollutants under
the 1970 Clean Air Act. The NSPS limits apply to new, modified, or reconstructed facilities that meet the
applicability criteria in the rule. The U.S. Environmental Protection Agency (EPA) periodically reviews the
limits set in the NSPS.
In 1998, EPA revised the nitrogen oxides (NOx) limits for electric utility steam generating units and
industrial-commercial-institutional steam generating units (40 CFR Part 60 Subparts Da and Db). These
revisions changed the format of the NOx emission limit for new electric utility boilers from an input basis
(Ib/MMBtu) to an output basis (Ib/MWh) and thereby provided a means for improved efficiency to
contribute to meeting the new standards. The regulation was changed from a fuel-specific limit (i.e.,
different limits for different fuels) to a single limit of 1.6 lb NOx/MWh gross energy output, regardless of
fuel type. The rule has been modified several times since 1998, with current emission limits for new
units set at 0.70 Ib/MWh gross energy output or 0.76 Ib/MWh net energy output. Compliance with the
NOx emission limit is determined on a 30-day rolling average basis. EPA added compliance and
monitoring provisions explaining how sources must demonstrate compliance with the output-based
standards. The regulation allows CHP facilities to take a credit for the process steam generated that is
equal to 75 percent of the thermal output of process steam converted to MWh (equivalence method).
The change in format for a major emission standard was an important precedent in the diffusion and
acceptance of output-based standards. The NSPS is discussed in more detail in section 5.2 of this report.
Additional information:
William Maxwell
Energy Strategies Group, Sector Policies and Programs Division (C439-01)
U.S. EPA
Research Triangle Park, NC 27711
(919) 541-5430
h ttp://www. epa. gov/ttn/atw/nsps/boilernsps/boilernsps. h tml
B.1.2 New Source Performance Standards for Stationary Combustion Turbines
EPA's NSPS for Stationary Combustion Turbines (40 CFR Part 60, subpart KKKK) limits emissions from
stationary combustion turbines. Affected units have the option of meeting concentration-based or
output-based NOxand sulfur dioxide (S02) emission limits.
Output-Based Regulations:
A Handbook for Air Regulators
B-l
Appendix B
-------
The rule has been modified several times since 2003, with current NOx emission limits for new units set
starting at 0.43 Ib/MWh gross energy output up to 8.7 Ib/MW gross energy output (limits are based on
the size, fuel use, and location). Compliance with the proposed NOx emission limit is determined on a
30-day rolling average basis. EPA added compliance and monitoring provisions explaining how sources
must demonstrate compliance with the output-based standards. The regulation allows CHP facilities to
take a credit for the process steam generated that is equal to 100 percent of the thermal output of
process steam converted to MWh.
Additional information:
Christian Fellner
Combustion Group, Emission Standards Division
U.S. EPA
Research Triangle Park, NC 27711
(919) 541-4003
http://www.epa.gov/ttn/atw/nsps/turbine/turbnsps.html
B.1.3 New Jersey Mercury Emission Limitations
The state of New Jersey finalized output-based emission limits for mercury from coal-fired boilers in
2006 (N.J.A.C. 7:27-27.7). The rule specifies that as of December 15, 2007, the mercury emissions from
any coal-fired boiler shall not exceed 3 milligrams per megawatt hour (mg/MWh), based on the annual
weighted average of all tests performed during four consecutive quarters; alternatively, the owner or
operator of a coal-fired boiler must achieve a 90 percent reduction in mercury emissions as measured at
the exit of the air pollution control apparatus. Compliance is to be determined by averaging three stack
emission test runs per quarter for four consecutive quarters, measuring the net MWh for each quarter,
and then calculating annual weighted averages using the quarterly averages and the net MWh
generated. The Department of Environmental Protection (DEP) will allow averaging among units at the
same site.
The DEP finalized an extension of the December 15, 2007, compliance deadline to December 15, 2012,
for any facility that, by December 15, 2007, installed and operates air pollution control systems to
control: (1) NOx emissions to less than 0.100 Ib/MMBtu for dry bottom boilers and 0.130 Ib/MMBtu for
wet bottom boilers; (2) S02 emissions to less than 0.150 Ib/MMBtu; and (3) particulate matter (PM)
emissions to less than 0.030 Ib/MMBtu. This extension of the compliance deadline is only available for
half of the New Jersey coal-fired capacity of a company. The other half of the coal-fired capacity must
achieve the mercury emission limits by December 15, 2007.
If a unit plans to shut down by December 15, 2012, the DEP will allow it to be exempt from the
proposed regulations.
Additional information:
Office of Legal Affairs
New Jersey DEP
401 East State Street
P.O. Box 402
Trenton, New Jersey 08625-0402
http://www.nj.gov/dep/rules/adoptions/2006_0906mercury.pdf
Output-Based Regulations:
A Handbook for Air Regulators
B-2
Appendix B
-------
B.1.4 Mercury MATS
EPA issued final Mercury and Air Toxics Standards (MATS) in February 2012. The rule sets standards to
limit mercury, acid gases, and other toxic pollution from power plants. MATS applies to new and existing
coal- and oil-fired EGUs larger than 25 MW. The rule also affects CHP systems: "A unit that cogenerates
steam and electricity and supplies more than one third of its potential electric output capacity and more
than 25 megawatts electrical output to any utility power distribution system for sale shall be considered
an electric utility steam generating unit."16 Existing sources generally have up to four years to comply
with MATS. The rule sets emission limits based on heat input in Ib/MMBtu or Ib/TBtu, but also provides
alternative output-based emission limits (either in Ib/MWh or Ib/GWh gross output) as an option.
Additional information:
William Maxwell
Combustion Group, Emission Standards Division
Office of Air Quality Planning and Standards
U.S. EPA
Research Triangle Park, NC 27711
(919) 541-5430
http://www.gpo.gov/fdsys/pkg/FR-2012-02-16/pdf/2012-806.pdf
B.2 Regulations for Distributed Generation
Distributed generation (DG) refers to the use of technologies such as microturbines, diesel generator
sets, fuel cells, solar panels, and reciprocating engines to satisfy small-scale electrical power needs
closer to the point of use. There is increasing interest in DG because of a desire for improved
reliability, energy efficiency, and lower costs. With innovations in DG technology, there has been
increased interest in how one consistently and appropriately regulates small distributed electric
generators. This activity has coincided with the interest in output-based regulation, and several new
regulatory programs have incorporated output-based measures as a means of recognizing efficiency
as a pollution control measure. Several of these regulations also include provisions to account for the
efficiency advantages of CHP. Most of these programs are conventional emission rate limit programs
in many respects, but they include some innovative features.
B.2.1 New Hampshire Emission Fee
New Hampshire has an output-based emission fee program for DG. The program requires affected
generators to report NOx emissions and power production and either (1) offset their emissions
through the purchase of NOxemission allowances within the Ozone Transport Region or (2) pay an
emission fee. The new regulation affects any internal combustion engine or combustion turbine that
generates electricity for use or sale and emits more than 5 tons of NOx per year. However, backup,
startup, and emergency generators are exempted, as are generators used in areas where electrical
power is not reasonably and reliably available. The amount of the fee per ton of NOx emitted is $100
from October 1 to April 30 and $200 from May 1 to September 30. The fee increases over time but is
capped at $500 per ton from October 1 to April 30 and $1,000 from May 1 to September 30. A NOx
16 http://www.gpo.gov/fdsys/pkg/FR-2012-02-16/pdf/2012-806.pdf.
Output-Based Regulations:
A Handbook for Air Regulators
B-3
Appendix B
-------
emission reduction fund will be established with these fees and used to reduce NOx emissions from
generation sources. No fee or allowance is required for the first 7 Ib/MWh of NOx. The original intent
of the 7 Ib/MWh threshold was to focus the fee on higher-emitting engines, including diesels.
However, this limit provides the additional benefit of encouraging efficiency by rewarding units that
emit at a lower output-based rate.
Additional information:
Joe Fontaine
New Hampshire Department of Environmental Services
29 Hazen Drive
P.O. Box 95
Concord, NH 03302-0095
(603) 271-6794
http://www.gencourt.state.nh.us/rsa/html/nhtoc/NHTOC-X-125-0.htm
B.2.2 California Senate Bill 1298 Regulations for Distributed Generation
In 2000, California passed Senate Bill 1298 (SB 1298), which required the California Air Resources Board
(CARB) to set new emission standards and provide guidance for permitting new DG projects. In
California, generators larger than 50 MW require air permits from the California Energy Commission,
while the 35 local air quality districts issue permits for units smaller than 50 MW. Very small projects
have been exempted from permitting by the individual districts. The size threshold for the permitting
exemption varies from district to district. The threshold is typically up to 250 kW for microturbines,
engines less than 50 hp, and fuel cells.17 This variation makes it difficult to implement the regulation. SB
1298 calls for CARB to:
• Establish an emission certification program for the small projects that are exempt from
permitting.
• Develop a best available control technology (BACT) guidance document for DG projects less than
50 MW but large enough to require local district permits. (BACT in California is equivalent to
lowest achievable emission rate [LAER] in other states.)
Certification Program
The final certification regulations became effective in October 2002. The certification program sets
emission standards that must be achieved by all affected DG units that are manufactured for sale, lease,
use, or operation in California. Amendments to the regulation were adopted by the Board on October 9,
2006 and became effective September 7, 2007. The program is implemented in two phases.
Phase I took effect on January 1, 2003, and sets the standards summarized in Table B-l.
17 http://www.arb.ca.gov/energy/dg/background/background.htm.
Output-Based Regulations:
A Handbook for Air Regulators
B-4
Appendix B
-------
Table B-l. 2003 California Distributed Generation Certification
Standards (lb/MWh)
Pollutant
Not Integrated
with CHP
Integrated with CHP
Oxides of nitrogen
0.5
0.7
Carbon monoxide
6.0
6.0
Volatile organic compounds
1.0
1.0
Particulate matter
Corresponding to natural gas with sulfur content
not more than 1 grain/100 scf
The standards include a separate limit for DG units that include CHP as part of a standardized package.
DG units that use CHP may be certified to the above emission standards if they are sold with CHP
technology integrated into a standardized package by the applicant and they achieve a minimum energy
efficiency of 60 percent based on 100 percent load. In addition, DG units that are sold with a zero
emission technology integrated into a standardized package can have the electric power output of the
zero emission technology added to the electrical power output of the DG unit to meet the emission
standards.
Phase II took effect January 1, 2007, and is based on the emission level that CARB determines to be
BACT for permitted central station power plants. Table B-2 summarizes the 2007 certification standards.
Table B-2.2007 California Distributed Generation
Fossil Fuel Emission Standards (lb/MWh)
Pollutant
lb/MWh
Oxides of nitrogen
0.07
Carbon monoxide
0.10
Volatile organic compounds
0.02
Particulate matter
Corresponding to natural gas with
sulfur content not more than 1
grain/100 scf
In its 2006 amendments, CARB also established separate emission limits for waste gas systems. These
limits apply to any DG unit that is fueled by digester gas, landfill gas, or oil-field waste gas.
Table B-3. 2007 California Distributed Generation
Waste Gas Emission Standards (lb/MWh)
Pollutant
Emission Standard lb/MWh
On or after 1/1/2008
On or after 1/1/2013
Oxides of nitrogen
0.5
0.07
Carbon monoxide
6.0
0.10
Volatile organic
compounds
1.0
0.02
Output-Based Regulations:
A Handbook for Air Regulators
B-5
Appendix B
-------
In Phase II, DG units that use CHP can increase the output calculation by 1 MWh for every 3.4 MMBtu of
heat recovered in the CHP system if the system is an integrated package with the DG system and if the
overall system has an efficiency of at least 60 percent. This recognizes 100 percent the thermal output
generated.
Certified Technologies
The regulation also specifies appropriate testing, testing parameters, labeling, and recordkeeping
requirements, along with information about the equipment to be submitted by the manufacturer for
certification. The executive officer or an authorized representative will periodically inspect
manufacturer, distributors, and retailers selling or leasing DG in California to ensure compliance with the
regulations. Failure of the inspection can lead to denial, suspension, or revocation of certification. The
equipment must be guaranteed to meet the certification for 15,000 hours of operation. As of April 2013,
27 technologies have been certified.18
BACT Guidelines
CARB released its Guidance for Permitting of Electrical Generating Technologies in July 2002. The
document provides guidance to assist air control districts in making air permitting decisions for new
electrical generators that are smaller than 50 MW but larger than the local exemption level. It expresses
currently achievable emissions on an output basis.
Most BACT definitions in California are consistent with the federal LAER definition and are often referred
to as "California BACT." "California BACT" should not be confused with the less restrictive federal BACT.
The CARB BACT guidance document summarizes CARB's evaluation of the status of California BACT for
electrical generators smaller than 50 MW. SB 1298 calls for the guidance to approach the emission levels
of the cleanest central station power plants. The CARB guidance suggests that the central station levels
will only be achievable by DG technologies through the application of a CHP credit.
Table B-4 summarizes the 2002 guidance for combustion turbines. Table B-5 summarizes the 2002
guidance for reciprocating engines. All of the standards are expressed in Ib/MWh. There is no
recognition for thermal energy produced by CHP.
18 http://www.arb.ca.gov/energy/dg/eo/eo-current.htm.
Output-Based Regulations:
A Handbook for Air Regulators
B-6
Appendix B
-------
Table B-4. CARB BACT Guidance for Small Combustion Turbines*
Equipment
Category
NOx**
Ib/MWh
voc**
Ib/MWh
CO**
Ib/MWh
PM
Ib/MWh
< 3MW
3-12 MW
Combined cycle
0.5
(9 ppmvd)
0.12
(2.5 ppmvd)
0.1
(5 ppmvd)
0.04
(2 ppmvd)
0.4
(10 ppmvd)
0.2
(6 ppmvd)
An emission limit
corresponding to natural
gas with fuel sulfur content
of no more than 1 grain/100
standard cubic feet
Simple cycle
0.25
(5 ppmvd)
0.04
(2 ppmvd)
0.2
(6 ppmvd)
>12 and <50 MW
Combined cycle
Simple cycle
0.1
(2.5 ppmvd)
0.2
(5 ppmvd)
0.03
(2 ppmvd)
0.03
(2 ppmvd)
0.15
(6 ppmvd)
0.15
(6 ppmvd)
An emission limit
corresponding to natural
gas with fuel sulfur content
of no more than 1 grain/100
standard cubic feet
Waste Gas Fired
1.25
(25 ppmvd)
—
—
—
* http://www.arb.ca.gov/energy/powerpl/powerpl.htm, http://www.arb.ca.gov/energy/dg/guidance/guidelines.pdf.
All standards based upon three-hour rolling average and in Ib/MWh.
** Equivalent limit is presented in ppmvd, expressed at 15 percent 02.
Table B-5. CARB BACT Guidance for Reciprocating Engine Generators*
Equipment
NOx
VOC
CO
PM
Category
Ib/MWh
Ib/MWh
Ib/MWh
Ib/MWh
0.5
0.5
1.9
Fossil-fuel-fired
(0.15 g/bhp-hr
(0.15 g/bhp-hr
(0.6 g/bhp-hr
0.06
or
or
or
(0.02 g/bhp-hr)
9 ppmvd**)
25 ppmvd**)
56 ppmvd**)
1.9
1.9
7.8
Waste-gas-fired
(0.6 g/bhp-hr
(0.6 g/bhp-hr
(2.5 g/bhp-hr
NA
or
or
or
50 ppmvd**)
130 ppmvd**)
300 ppmvd**)
* All standards based upon three-hour rolling average and in Ib/MWh.
** Equivalent limit is presented in ppmvd, expressed at 15 percent 02.
Additional information:
Jonathan Foster
California Air Resources Board
1001 "I" Street
P.O. Box 2815 Sacramento, CA 95812
(916)327-1512
h ttp ://www. arb. ca. gov/en ergy/dg/dg. h tm
Output-Based Regulations:
A Handbook for Air Regulators
B-7
Appendix B
-------
B.2.3 Delaware Small Distributed Generation Rule
Division of Air and Waste Management Regulation No. 1144 specifies limits on DG and emergency
generation units. Delaware's output-based regulation, entitled "Control of Stationary Generator
Emissions/' limits emissions of NOx, nonmethane hydrocarbons, PM, S02, carbon monoxide (CO), and
carbon dioxide (C02). This regulation applies to new and existing stationary DG units. DG units must
comply with the limits beginning on January 11, 2006. CHP systems can receive a compliance credit
against their actual emissions based on the emissions that would have been created by a conventional
separate system used to generate the same thermal output. The credit will then be subtracted from the
actual generator emissions for determining compliance. The credit (measured in lb/MWhemiSSions) is equal
to the existing boiler's historic emission rate (in Ib/MMBtu) divided by the boiler efficiency (assumed to
be 80 percent); this result is multiplied by the conversion factor of 3.413 (to convert to MWh) divided by
the CHP system's power to heat ratio. CHP units that are at least 55 percent efficient, use at least 20
percent of a fuel's recovered energy for thermal, and at least 13 percent for electricity are eligible.
Additional information:
http://www.dnrec.state.de.us/air/aqm_page/docs/pdf/Final%20Regulation%201144.pdf
B.2.4 Rhode Island Distributed Generation Rule
In Rhode Island, new and existing distributed generators may be subject to emission limits (Ib/MWh)
pursuant to state air pollution control Regulation No. 43, established in May 2007. Using the avoided
emissions approach, the rule allows a CHP system to account for its secondary thermal output when
determining compliance with NOx, CO, and C02 emission limits. The CHP system can receive emission
compliance credits using the same method that Delaware uses, as noted above (assuming a boiler
efficiency of 80%):
credit lb/MWhemiSSions= [(boiler limit Ib/MMBtu) 4- (boiler efficiency)] x [3.412/(power to heat ratio)]
A CHP system can take into account the secondary thermal output if it meets the following criteria:
• The power-to-heat ratio is between 4.0 and 0.15.
• The design system efficiency is at least 55 percent.
Additional information:
h ttp://www. dem.ri. go v/p ubs/regs/regs/air/air43_07. pdf
B.2.5 Texas Standard NOx Permit for Distributed Generation
In May 2001, the Texas Commission on Environmental Quality (TCEQ) approved a new standard permit
for emissions from small electric generating units. This new standard:
• Applies to electric generating units that were new or modified after June 2001.
• Exempts non-emitting generators from permitting.
• Does not apply to DG used to power an individual's home.
• Provides separate standards for east and west Texas.
• Differentiates by system size and capacity factor.
• Provides full credit for heat recovery in CHP projects.
The permit sets output-based limits for units in 2001 with a more stringent limit in 2005 for 10 MW or
less in eastern Texas (Table B-6).
Output-Based Regulations:
A Handbook for Air Regulators
B-8
Appendix B
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Table B-6. TCEQ Standard Permit for N0X from DG
Region
10 MW or Less
>10 MW
East
Installed prior to 2005:
Operating >300 hrs/yr = 0.47 Ib/MWh Operating
<300 hrs/yr= 1.65 Ib/MWh
Installed starting 2005:
Operating >300 hrs/yr = 0.14 Ib/MWh Operating
<300 hrs/yr = 0.47 Ib/MWh
Operating >300 hrs/yr = 0.14 Ib/MWh
Operating <300 hrs/yr = 0.38 Ib/MWh
West
Operating >300 hrs/yr = 3.11 Ib/MWh
Operating <300 hrs/yr = 21 Ib/MWh
Operating >300 hrs/yr = 0.14 Ib/MWh
Operating <300 hrs/yr = 0.38 Ib/MWh
The rule also sets a NOx limit of 1.7 Ib/MWh for generators burning waste gases, including landfill gas,
digester gas, and oil field gas. In addition, the gas is limited to less than 1.5 grains of hydrogen sulfide
or 30 grains of sulfur compounds. CHP units can subtract 1 MWh from the output calculation for each
3.413 MMBtu of thermal output produced.
Additional information:
TCEQ Air Permits Division
Texas Natural Resource Conservation Commission
P.O. Box 13087
Austin, TX 78711-3087
(512)239-1250
air perm @tceq. texas. gov
http://www.tceq.state.tx.us/assets/public/permitting/air/NewSourceReview/Combustion/segu_final.pdf
B.2.6 Texas Permit by Rule
Texas offers a streamlined construction air permitting program, termed a permit by rule (PBR), which
was issued in July 2012 for certain types of natural-gas-fired CHP systems up to 15 MW. The CHP PBR,
codified in 30 TAC 106.513, allows CHP systems that meet the rule's eligibility requirements to comply
with NOx and CO emission limits using the equivalence approach. A CHP system can receive 100 percent
credit for its secondary thermal output (at the rate of 1.0 MWh for each 3.4 million BTU of heat
recovered) if "the heat recovered equals at least 20 percent of the total heat energy output of the CHP
system." The permit sets output-based NOx and CO limits for CHP units or a combination of CHP units
(Table B-7).
Table B-7. TCEQ PBR for CHP
Pollutant
Emission Standard (Ib/MWh)
CHP unit > 20 kW
to < 8 MW
CHP unit > 8 MW
Combo of CHP Units
< 8 MW at Least 900
Feet Apart
CHP Units > 8 MW at
Least 900 Feet Apart
NOx
1.0 Ib/MWh
0.7 Ib/MWh
1.0 Ib/MWh
0.7 Ib/MWh
CO
9.0 lb CO/MWh
9.0 Ib/MWh
9.0 Ib/MWh
9.0 lb CO/MWh
Output-Based Regulations:
A Handbook for Air Regulators
B-9
Appendix B
-------
Additional information:
TCEQ Air Permits Division
Texas Natural Resource Conservation Commission
P.O. Box 13087
Austin, TX 78711-3087
(512)239-1250
air perm @tceq. texas. go v
http://info.sos.state.tx. us/pls/pub/readtac$ext.TacPage?sl=R&app=9&p_dir=&p_rloc=&p_tloc=&p_ploc
=&pg=l&p_tac=&ti=30&pt=l&ch=106&rl=513
B.2.7 Regulatory Assistance Project Model Rule for Distributed Generation
A collaborative group of state utility regulators, state air regulators, environmental organizations, and
DG industry representatives, with participation from the U.S. Department of Energy (DOE) and EPA,
developed a model emission rule for small DG units. Supported by DOE's Office of Distributed Energy
Resources, the Regulatory Assistance Project facilitated the formation of the collaborative group as well
as its deliberations. The purpose of the model rule is to facilitate the permitting of DG projects by
providing a framework of underlying principles that can be uniformly adopted across the United States.
The model rule was completed in February 2003.
The model rule recommends output-based emission limits for NOx (separate standards for ozone
attainment and nonattainment areas), CO, and PM. The rule also requires diesel-fueled generators to
use low-sulfur highway diesel fuel. The limits are established in three phases, taking effect in 2004,
2008, and 2012. The third phase is subject to a technology review to determine whether the limits are
feasible and appropriate. The limits are summarized in Table B-8.
Table B-8. RAP Model Rule Emission Limits (lb/MWh)
NOx Attainment
NOx
Nonattainment
CO
PM*
Phase 1-2004
4
0.6
10
0.7
Phase 11-2008
1.5
0.3
2
0.07
Phase III—2012**
0.15
0.15
1
0.03
* Diesel engines only.
** Subject to technology review.
Limits on CO2 were endorsed by the collaborative group but are not part of the final
recommendations. The model rule provides compliance credit for CHP facilities based on the avoided
emissions from an equivalent thermal generator. It also allows credit for avoided combustion of waste
and byproduct gases. There is also a section on credit for combined conventional/renewable projects,
though the approach is not described in detail.
The model rule was adopted in whole or in part by a number of states, among them Connecticut,
Rhode Island, Maine, Massachusetts, and Delaware.
Output-Based Regulations:
A Handbook for Air Regulators
B-10
Appendix B
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Additional information:
Rick Weston
Regulatory Assistance Project
50 State Street, Suite 3
Montpelier, VT 05602
(802) 498-0711
http://www.google.com/url?sa=t&rct=j&q=&esrc=s&source=web&cd=l&cad=rja&uact=8&ved=0CCsQFj
AA&url=http%3A%2F%2Fwww.raponline.org%2Fdocument%2Fdownload%2Fid%2F174&ei=FldqU6G0H
MIV8gHXzoGQBA&usg=AFQjCNH6kz6UMjNki-
NY3sPF4oPonH6PaQ&sig2=5hbiLKTLGBlNzfS_lMEoSQ&bvm=bv.66111022,d.b2U
B.2.8 Connecticut Air Pollution Regulations 22a-174-42
The state of Connecticut finalized a rule setting output-based emission standards in 2005. The rule is
based on the Regulatory Assistance Project (RAP) rule for distributed generation using the avoided
emissions approach for crediting CHP. The rule regulates NOx, PM, CO, and C02.
Additionally, the rule incorporates a fuel sulfur content requirement to control S02 emissions. The rule is
based on the RAP model rule for new generators (Table B-9). The rule also sets less stringent limits for
existing generators. The rule is applicable to generators with a nameplate capacity less than 15 MW that
generate electricity for other than emergency use and have potential emissions less than 15 tons per
year.
Table B-9. Connecticut Emission Standards for New Distributed Generators
Date of Installation
NOx
(Ib/MWh)
PM
(Ib/MWh)
CO (Ib/MWh)
C02 (Ib/MWh)
On or after January 1,
2005
0.6
0.7
10
1,900
On or after May 1,
2008
0.3
0.07
2
1,900
On or after May 1,
2012
0.15
0.03
1
1,650
Table B-10. Connecticut Emission Standards for Existing Distributed Generators
NOx
PM
CO
co2
(Ib/MWh)
(Ib/MWh)
(Ib/MWh)
(Ib/MWh)
4.0
0.7
10
1,900
An owner or operator of any new or existing distributed generator subject to this section can comply
with the applicable emission standards of this section by obtaining one of the following certifications:
• Certification by CARB pursuant to Title 13, sections 94200 through 94214 of the California Code
of Regulations.
• Certification from the generator supplier that satisfies the requirements of this subsection.
Output-Based Regulations:
A Handbook for Air Regulators
B-ll
Appendix B
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The proposed regulation does recognize the thermal output of CHP systems based on displaced
emissions as long as:
• At least 20 percent of the fuel's total recovered energy is thermal and at least 13 percent is
electric, with a resulting power-to-heat ratio between 4.0 and 0.15.
• The design system efficiency is at least 55 percent.
Additional information:
Director Division of Compliance and Field Operations
Bureau of Air Management
Connecticut Department of Environmental Protection
(860) 424-3416
http://www.ct.gov/deep/lib/deep/air/regulations/mainregs/sec42.pdf
B.2.9 Maine Permit for Small-Scale Electric Generators
Maine's output-based regulation titled "Emissions from Smaller-Scale Electric Generating Resources,"
limits emissions of NOx, S02, PM, and CO. The emission standard applies to stationary generators with a
capacity equal to or greater than 50 kW installed on or after January 1, 2005. Generators that use CHP
can receive credit for heat recovery to comply with the emission standards. Credit is given at the rate of
1 MWh for each 3.4 MMBtu of heat recovered. Total CHP system efficiency must be at least 55 percent.
The heat recovered from a CHP unit must be at least 20 percent of the total energy output, and at least
13 percent of total output must be electric.
Table B-ll. Maine Emission Standards for Non-Emergency Generators
NOx
PM
CO
Installed on or after January
1, 2005
4.0 Ib/MWh
0.7 Ib/MWh
10.0 Ib/MWh
Installed on or after January
1, 2009
1.5 Ib/MWh
0.07 Ib/MWh
2.0 Ib/MWh
Installed on or after January
1, 2013
Reserved
Reserved
Reserved
Additional information:
Eric Kennedy
Bureau of Air Quality
Maine Department of Environmental Quality
17 State House Station
Augusta, ME 04333-0017
(207) 287-5412
h ttp ://www.maine. go v/sos/cec/rules/06/096/096cl 48.doc
Output-Based Regulations:
A Handbook for Air Regulators
B-12
Appendix B
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B.2.10 Massachusetts Draft 310 CMR 7.26 Engines and Combustion Turbine
Certification Standards
The state of Massachusetts has released a final output-based regulation on emissions from
commercial/industrial size engines and combustion turbines.19 The proposed rule applies to engines and
combustion turbines that are not subject to Prevention of Significant Deterioration or Non-Attainment
Review. It includes separate standards for emergency and non-emergency units. "Emergency" is defined
as not only equipment failure, but also the imminent threat of a power outage is likely due to failure of
the electrical supply or when capacity deficiencies result in a deviation of voltage from the electrical
supplier to the premises of 3 percent above or 5 percent below standard voltage. An emergency engine
or emergency turbine cannot operate more than 300 hours per 12-month rolling period during times of
emergency and for normal maintenance and testing as recommended by the manufacturer. All
emergency engines with a rated power output equal to or greater than 37 kW, and emergency
combustion turbines with a rated power output less than 1 MW installed after March 23, 2006, must
meet the following air emission limits.
Table B-12. Massachusetts Emission Limits for
Emergency Engines and Turbines
Pollutant
Emission Limit
NOx
0.60 Ib/MW-hr
Additionally, on and after July 1, 2007, emergency engines and turbines may not accept delivery of fuel
oil for burning in a unit that does not conform to EPA's sulfur limits for transportation distillate fuel (15
ppm sulfur).
Non-emergency engines are subject to declining emission output regulations through the use of three
phases based on the RAP Model Rule. The first phase occurred on and after March 23, 2006. The second
phase was from 2008 to 2012. The third phase is 2012 and beyond. The phase-in was intended to
encourage the development and commercialization of new technologies. Table B-13 summarizes the
proposed limits for non-emergency engines. Unlike the model rule, the final rule does not create or
provide any recognition for concurrent emission reductions, CHP, or end-use efficiency.
An owner or operator who installs, after March 23, 2006, an engine with a rated power output equal to
or greater than 50 kW or a combustion turbine with a rated power output equal to or less than 10 MW
is subject to the following emission limits:
Table B-13. Massachusetts Emission Limits for Non-Emergency Engines
Installation Date
NOx
PM (Liquid Fuel)
CO
On and after 03/23/2006
0.6 Ib/MWh
0.7 Ib/MWh;
> 1 MW
0.09 Ib/MWh
10 Ib/MWh
On and after 01/01/2008
0.3 Ib/MWh
0.07 Ib/MWh
2 Ib/MWh
On and after 01/01/2012
0.15 Ib/MWh
0.03 Ib/MWh
1 Ib/MWh
19 http://www.mass.gov/eea/agencies/massdep/air/approvals/stationary-engines-and-turbines.htmlftl
Output-Based Regulations:
A Handbook for Air Regulators
B-13
Appendix B
-------
The emission limits for turbines (Tables B-14 and B-15) are consistent with the Texas general permit for
DG (See section B.2.3). They vary by generator size but are not phased in over time.
Table B-14. Massachusetts Emission Limits for Non-Emergency Turbines
Rated Power Output
NOx
Ammonia
PM
CO
Less than 1 MW
0.47 Ib/MWh
N/A
0.10 Ib/MWh
0.47 Ib/MWh
1 to 10 MW
Gas—0.14 Ib/MWh
Oil—0.34 Ib/MWh
2.0 ppm at 15% 02
dry basis
0.10 Ib/MWh
Gas—0.09 Ib/MWh Oil—
0.18 Ib/MWh
Table B-15. CO2 Emission Limitations—Engines and Turbines
Installation Date
C02
On and after March 23, 2006
1,900 Ib/MWh
On and after 1/1/08
1,900 Ib/MWh
On and after 1/1/12
1,650 Ib/MWh
Additional information:
Cynthia Greene
Business Compliance Division
Massachusetts Department of Environmental Protection
One Winter Street
Boston, MA 02108
(617) 918-1813
B.2.11 New York 6 NYCRR Part 222 Emissions from Distributed Generation
The state of New York's Department of Environmental Conservation is proposing output-based
standards for NOx. Under this proposed rule, output-based limits are proposed for "economic dispatch"
engines and demand response resources in g/bhp. For combustion turbines, the emission limits are
based on heat input and are expressed in ppm. Currently, there is no recognition of CHP. The proposed
limits in the tables below are from a working draft released in October 2007.20 The department has
never finalized this proposed rule, but has stated in its January 2014 Regulatory Agenda that it plans on
doing so soon.
NOx emission limits under proposed Part 222 apply to "economic dispatch sources," defined as DG
sources used to reduce energy costs or ensure a reliable electricity supply for facilities. The rule states
that any DG source that is not an emergency-power-generating stationary internal combustion engine or
a demand response source is considered to be an economic dispatch source. "Demand response
sources" are also subject to output-based NOx limits. A demand response source is defined as a
"distributed generation source that operates for no more than 500 hours per year, or as limited to
comply with any other applicable requirement, as a mechanical or electrical power source when the
usual supply of power is unavailable and for a limited number of hours per year when called upon to
20 http://www.eea-inc.com/rrdb/DGRegProject/Documents/NYExpTerms222%20-%200ct%202007%20(2).pdf
Output-Based Regulations:
A Handbook for Air Regulators
B-14
Appendix B
-------
reduce demand on the electric grid as set forth in sections of this proposed rule." Output-based limits
are established for economic dispatch engines and demand response resources as follows:
Table B-16. Proposed NOx Emission Limits
Effective Date
Technology
NOx Emission Limits g/bhp
May 1, 2009 (economic dispatch
sources)
Lean burn engines—gas-fired
3.0 g/bhp
Rich burn engines—gas-fired
2.0 g/bhp
Oil-fired engines
7.5 g/bhp
January 1, 2010 (economic dispatch
sources)
Lean burn engines—biogas-fired
3.0 g/bhp
Rich burn engines—biogas-fired
2.0 g/bhp
May 1, 2009
Demand response resources
9.0 g/bhp
Additional Information:
Ron Stannard
New York Department of Environmental Conservation
625 Broadway
Albany, NY 12233-3251
(518) 402-8396
airregs@gw.dec.state, ny.us
B.3 Allowance Allocation in Emission Trading Programs
In emission cap and trade programs, the total tons of emissions for a given sector are capped.
Allowances represent a permit to emit one ton. Allowances are allocated to the affected sources, and
each source is required to hold allowances equal to its emissions during each regulated period. Sources
are allowed to buy and sell allowances from each other to help them meet their compliance
requirement. In themselves, these trading programs promote an output-based view on the part of
affected sources. Affected sources must try to maximize their production within the overall emission
cap; thus they are driven to relate their emissions directly to their productive output. However, other
aspects of the program can more directly relate to output-based regulation.
In these programs, the emission allowances must be allocated to participating sources at the beginning
of the program. The early cap and trade programs performed this allocation based on historical
emissions or heat input. More recently, there has been interest in doing the allocation based on energy
output. An output-based allocation can serve to recognize the benefits of efficient generation, end use
efficiency, and renewables. Past programs that include output-based allocation are primarily state
programs under the NOx State Implementation Plan (SIP) call program, the Clean Air Interstate Rule
(CAIR), and the Regional Greenhouse Gas Initiative (RGGI) as described in this section.
Some states established output-based allocations or allocation set-asides as part of their
implementation of CAIR. CAIR set emissions caps for NOx and S02 emissions for 27 states in the eastern
United States and the District of Columbia. In its CAIR model rule, EPA outlined an allocation
methodology to existing units on a heat input basis, but suggested using an output-based allocation
approach to new units. States were allowed to develop their own allocation methodologies in their SIPs.
A number of states did develop output-based allocation methodologies for existing units. These output-
Output-Based Regulations:
A Handbook for Air Regulators
B-15
Appendix B
-------
based approaches are briefly described below. On April 29, 2014, the U.S. Supreme Court issued an
opinion reversing a lower court ruling that had vacated the Cross State Air Pollution Rule, intended to be
the successor to CAIR. EPA has stated that CAIR remains in place at this time, and that "no immediate
action from States or affected sources is expected."21
RGGI applies to 10 northeastern and mid-Atlantic states. The program imposes C02 caps on electric
power generators larger than 25 MW in participating states and functions as a multi-state cap and trade
program with a market-based emission trading system. As of August 2013, nine states are participating
in the RGGI effort: Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New York,
Rhode Island, and Vermont. (New Jersey announced its withdrawal from the program in June 2011.) The
cap begins in 2009 at "current levels" and is reduced by 10 percent between 2016 and 2019. Some
states developed set-aside pools of allowances that are allocated on an output basis. Most of the RGGI
allowances are distributed through an auction process, but some allowances in set-aside pools are
allocated on an output basis.
Some actual and proposed multi-pollutant legislation also includes output-based allocation (see sections
B.4 and B.5).
B.3.1 Arkansas
Arkansas allocates allowances to existing units on an output basis as a part of CAIR.
Additional information:
http://www.adeq.state.ar.us/regs/drafts/regl9_draft_docket_06-012-R/regl9_draft_docket_06-012-
R_revision_comparison_chart.pdf
B.3.2 Connecticut
Allowances for existing electric generating units in the NOxSIP Call trading program (section 22a-174-
22b) are allocated every two years based on the percentage of each unit's average electric generation
during the previous two years relative to the total generation from affected units (output-based). The
allocation for new units, cogenerators, and industrial boilers was based on heat input.
CHP facilities receive no special treatment.
Connecticut allocates CAIR allowances for CHP units (with an efficiency of at least 60 percent) and other
facilities based on electrical output. Also, Connecticut has finalized its RGGI regulations, allocating
allowances to the CHP set-aside account and early reduction account on an output basis.
Additional information:
Connecticut Department of Environmental Protection at Bureau of Air Management
79 Elm Street, 5th Floor
Hartford, CT 06106-5127
(860) 424-3000
NOx SIP Call: http://www.ct.gov/deep/lib/deep/air/regulations/mainregs/sec22b_repealed.pdf
CAIR: http://www.ct.gov/deep/lib/deep/air/regulations/mainregs/sec22c.pdf
RGGI: http://www.ct.gov/deep/lib/deep/air/regulations/mainregs/22a-l74-31.pdf
21 http://www.epa.gov/cleanairinterstaterule/.
Output-Based Regulations:
A Handbook for Air Regulators
B-16
Appendix B
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B.3.3 Illinois
Illinois has output-based allocations for new and existing units as well as their energy
efficiency/renewable energy set-aside as a part of CAIR.
Additional information:
http://www.ipcb.state.il.us/documents/dsweb/Get/Document-58394/
B.3.4 Indiana
Indiana has established output-based regulations for new units and those that are eligible for the energy
efficiency/renewable energy set-aside under CAIR.
Additional information:
http://www.in.gov/legislative/iac/T03260/A00240.PDF
B.3.5 Massachusetts
Allocations of allowances for the NOxSIP Call trading program are revised annually, three years ahead of
the compliance year. Allocation for electric generators is based on the average of the two highest years
of generation (output) in the fourth, fifth, and sixth years before the allocation year. Allocation for
industrial boilers is based on the two highest years of steam output in the fourth, fifth, and sixth years
before the allocation year. Sources with both electric and thermal output (including CHP facilities)
receive allocations for both output streams.
Massachusetts' CAIR rule employs useful output, including the thermal output of CHP, to allocate
emission allowances to affected sources (generators > 25 MW). This approach provides a significant
economic incentive for CHP within the emission cap. Additionally, early reduction credits under the
state's RGGI rule will be allocated on an output basis.
Additional information:
Bill Lamkin
Massachusetts Department of Environmental Protection
One Winter Street
Boston, MA 02108-4746
(978) 694-3294
NOx SIP Call: http://www.mass.gov/eea/docs/dep/air/laws/output.doc
CAIR: http://www.mass.gov/eea/docs/dep/service/regulations/310cmr07.pdf
RGGI: http://www.mass.gov/eea/agencies/massdep/air/regulations/310-cmr-7-00-air-pollution-control-
regulation.html
B.3.6 Missouri
Missouri has output-based allocations under its NOx SIP Call for its energy efficiency/renewable energy
set-aside. Energy efficiency projects receive allowances based on the number of kWh saved, zero-
emitting technologies receive allowances based on electrical output, and CHP systems receive
allocations based on the difference between NOx emissions from the CHP system and the NOx emissions
that would have resulted from a business-as-usual equivalent.
Output-Based Regulations:
A Handbook for Air Regulators
B-17
Appendix B
-------
Additional information:
http://www.dnr.mo.gov/env/apcp/reghaze/appendix-v.pdf
B.3.7 New Hampshire
New Hampshire has had a NOx cap and trade program since the ozone season starting in 2003 (NH CAR
Env-A 3207). The allowances for the first three years of the program were allocated to electric
generating units based on historical generation with some modifications to allow for new units. Starting
in 2006, allocations were based directly on generation output.
There is no special treatment for CHP facilities.
Additional information:
Joe Fontaine
Air Resources Division
New Hampshire Department of Environmental Services
P.O. Box 95
Concord, NH 03302-0095
(800) 271-6794
jfontaine@des.state.nh. us
B.3.8 New Jersey
The New Jersey allocation system for NOx allowances under the SIP Call (NJ AC Title 7, chapter 27,
subchapter 31) treated sources differently depending on their emission rate.
Allocations are done annually three years in advance. Allowances for sources with an emission rate less
than or equal to 0.15 lb/MMBtUheatinput are based on actual emissions. Allowances for sources with an
emission rate greater than 0.15 lb/MMBtuheat input are allocated based on output. For electric generating
units, the allocation is 1.5 Ib/MWh times the average of the two highest years' electrical generation
outputs in the three ozone seasons before the allocation. For industrial boilers, the allocation was 0.44
Ib/MMBtUheat output times the average of the two highest years' heat outputs for the three ozone seasons
before the allocation.
New Jersey has output-based regulations for new and existing units as well as its energy
efficiency/renewable energy set-asides as a part of CAIR.
Additional information:
Air Quality Management, Bureau of Regulatory Development
New Jersey Department of Environmental Protection
401 East State Street, 7th Floor
P.O. Box 418
Trenton, NJ 08625-0418
(609) 292-6710
h ttp://www.state.nj. us/dep/aqm/
B.3.9 New York
New York allocates allowances under its RGGI early reduction set-aside account on an output basis (see
Part 242: C02 Budget Trading Program).
Output-Based Regulations:
A Handbook for Air Regulators
B-18
Appendix B
-------
Additional information:
New York State Department of Environmental Conservation
625 Broadway
Albany, New York 12233-0001
(518) 402-8452
DARWeb@gw.dec.state.ny.us
h ttp ://www. dec. ny. gov/regs/2492. h tml
B.3.10 Ohio
In July 2002, the Ohio EPA established a program for issuing credits to energy efficiency/renewable
energy (EE/RE) and innovative technology (IT) projects in its NOx Budget Trading Program. The rule set
aside NOx allowances for EE/RE and IT projects. Demand-side programs such as lighting retrofits could
also receive credits. The program ended when CAIR started in 2009. However, Ohio has an EE/RE set-
aside with output-based allocations under CAIR.
Additional information:
h ttp -.//codes, ohio. go v/oac/3745-109-17
B.3.11 Pennsylvania
Pennsylvania allocates CAIR allowances to existing and new units on an output basis.
Additional information:
http://www.pacode.com/secure/data/025/chapterl45/subchapDtoc.html
B.3.12 Wisconsin
Wisconsin has output-based regulations for new and existing units as well as its energy
efficiency/renewable energy set-asides as a part of CAIR.
Additional information:
http://docs.legis.wisconsin.gov/code/admin_code/nr/400/432.pdf
B.4 State Multi-Pollutant Programs
Several states have recently implemented multi-pollutant regulations for power generators. These
regulations comprise integrated emission reduction programs for power generators. Some are cap and
trade programs, while others are conventional emission rate limit programs. Several programs include
output-based approaches to regulation.
B.4.1 Massachusetts Multi-Pollutant Program
Massachusetts had a multi-pollutant regulation (310 CMR 7.29) for S02, NOx, mercury (Hg), and C02
from older coal-fired power plants in the state that applied to emissions that occurred prior to 2009. The
regulation set output-based emission limits for NOx, S02, C02, and Hg (Table B-17). The regulation
targeted specific coal-fired plants, including Brayton Point, Canal Electric, Mount Tom, Mystic Station,
Salem Harbor Station, and Somerset Station.
The NOx emission standard was 1.5 Ib/MWh rolling annual average (beginning October 2004), with an
additional 3.0 Ib/MWh monthly average that took effect in October 2006. The limit of 1.5 Ib/MWh is the
nominal level established for the ozone season by the NOx SIP Call, but this regulation expanded
Output-Based Regulations:
A Handbook for Air Regulators
B-19
Appendix B
-------
compliance with the SIP Call standard to a year-round requirement, rather than the ozone season. It also
set a fixed standard rather than a cap and trade program. Compliance dates were moved two years in
the future for units that were approved for major modifications or repowering before 2003.
that the rem
Table B-17. Massachusetts Multi-Pollutant Program Emission Limits
Effective Date
Emission Limits (Ib/MWh, Rolling 12-Month Average)
NOx
S02
co2
Mercury
2002
—
—
See limits below
2004
1.5
6.0
Historical emissions
2006
1.5*
3.0**
1,800
* Must also meet 3.0 Ib/MWh monthly average.
** Must also meet 6.0 Ib/MWh monthly average.
S02 emission standards were 6.0 Ib/MWh (as of October 2004). Early reduction credits could be
generated by participating facilities and used by these facilities to meet emissions above the 6.0
Ib/MWh annual level. Beginning in October 2006, the standard dropped to 3.0 Ib/MWh (rolling annual)
and 6.0 Ib/MWh (monthly). Title IV S02 allowances could be purchased and used for compliance with the
3.0 Ib/MWh standard but were discounted at a 3:1 ratio. Title IV allowances used for this purpose were
required to be excess allowances above those used to comply with the federal requirements. These
standards reduced nominal emission levels allowed under Title IV by half and set specific limits.
Compliance dates were moved to 2008 for units that were approved for major modifications or
repowering before 2003.
C02 emissions from 2004 to 2006 could exceed historical annual emissions from a facility. Beginning in
2006, facilities were required to have an average emission rate not greater than 1,800 Ib/MWh (annual
average). The average emission rate was calculated by dividing pounds of C02 emitted by net electrical
output. Compliance with these standards was required to be demonstrated by using offsite reductions
or sequestration to offset emissions.
Mercury emission limits were set in January 2002 at the average historical annual emission level from a
facility. This average was calculated using the results of stack tests. The Massachusetts Department of
Environmental Protection (DEP) first completed an evaluation of the technological and economic
feasibility of controlling and eliminating emissions of mercury from the combustion of solid fossil fuel in
December 2002. In 2004, DEP released a draft proposal for mercury emission regulations.
The mercury regulations affected four large coal-burning power plants, which contributed 17 percent of
the point source mercury emissions in Massachusetts. DEP concluded a mercury feasibility report in
2003 by finding that there is strong evidence oval of 85 to 90 percent of mercury in flue gas is
technologically and economically feasible for coal-fired power plants.
The regulations contain output-based mercury rate limitations that were implemented in two phases
(Table B-18). Under the first phase of the mercury reductions, each utility had a choice between a
minimum 85 percent removal of mercury from inlet levels measured in 2001-2002 or a maximum Hg
Output-Based Regulations:
A Handbook for Air Regulators
B-20
Appendix B
-------
emission rate of 0.0075 pounds per net gigawatt-hour of electricity generated, calculated as a rolling
annual average. This standard took effect January 1, 2008.
Table B-18. Massachusetts' Proposed Mercury Emission Regulations
Phase
Mercury Limit
Phase 1—Effective January 1, 2008, or 15 months after
the Phase 1 NOx and S02 compliance dates
85% Hg removal efficiency or maximum emission limit of
0.0075 Ib/GWhnet
Phase 2—Effective October 1, 2012
95% Hg removal efficiency or maximum emission limit of
0.0025 Ib/GWhnet
Under the second phase, each utility has a choice between a minimum 95 percent removal of mercury
from inlet levels measured in 2001-2002 or a maximum Hg emission rate of 0.0025 pounds per net
gigawatt-hour of electricity generated, calculated as a rolling annual average. This standard took effect
October 1, 2012, with the first annual average calculated for the October 1, 2012, to September 30,
2013, period.
The inlet levels measured in 2001-2002 were used as the basis of the removal standard so that a facility
could not increase overall emissions by meeting the removal efficiency standard based on a higher inlet
measurement. The department did allow some flexibility for compliance. Through December 31, 2009,
compliance with the mercury emission rate limitations must be demonstrated by using offsite
reductions to offset excess emissions. The rule did allow averaging between a facility's units, but not
between facilities.
Emission averaging among boilers within a plant was allowed for all standards. Early reduction credits
could be created to meet the S02 standards.
Additional information:
Sharon Weber
Massachusetts Department of Environmental Protection
One Winter Street
Boston, MA 02108-4746
Sharon. weber@state.ma. us
http://www.mass.gov/eea/docs/dep/service/regulations/310cmr07.pdf
B.4.2 New Hampshire Multi-Pollutant Program
On May 8, 2002, New Hampshire passed a multi-pollutant law, known as the Clean Power Act, for
existing fossil fuel power plants. The rule specifies emission reduction requirements for four pollutants
(S02, NOx, mercury, and C02). This law was aimed at controlling emissions from three plants: Merrimack
Station in Bow, Schiller Station in Portsmouth, and Newington Station in Newington. The language,
however, is somewhat vague and could include other existing units.
The law sets annual emission caps. Allowances are allocated to the plants on an output basis, and
trading is allowed for S02, NOx, and C02. Mercury reduction provisions were adopted in 2006. Caps were
as follows:
• S02 emissions: 7,289 tpy. This was a 75 percent reduction from 2000 levels by the end of 2006.
Output-Based Regulations:
A Handbook for Air Regulators
B-21
Appendix B
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• N0X emissions: 3,644 tpy. This was a 70 percent reduction from early 2000 levels by the end of
2006.
• C02 emissions: 5,046,055 tpy. This reduction will put emissions at 7 percent below 1990 levels
by 2010.
Amendments were adopted in 2006 to incorporate provisions for mercury reductions. Mercury trading
was prohibited, but provisions were added to allow mercury credits to be converted to S02 allowances
and used for compliance in that trading program.
Affected units are required to file compliance plans to meet the requirements of the Clean Power Act
and to describe monitoring and reporting procedures for mercury content in emissions. Caps are met
through reductions or trading. Allowances from federal and regional trading programs may be used as
well, but mercury credits from other programs are only valid for reductions above the level required by
federal limits. An S02 allowance from an upwind state was upgraded by 25 percent, meaning 0.8 tons
purchased from an upwind state are credited as 1.0 allowances by the state. Discrete NOx emission
reduction credits may not be used for compliance from May to September. Credit is given for early
reductions of C02 and mercury. Voluntary expenditures for energy efficiency, renewable energy, and
conservation programs are provided allowances equivalent to the cost of the renewable, efficiency, and
conservation programs.
Compliance with the law began in 2007.
The regulation determined the annual allocation approach as follows, beginning in 2006:
• S02—baseline power generation (in the year 1999) multiplied by 3 Ib/MWh.
• NOx—baseline power generation (in 1999) multiplied by 1.5 Ib/MWh.
• C02—93 percent of 1990 emissions.
• Mercury—emission cap of 82 lb.
Individual unit allocations for NOx and S02 are based on the unit's average electrical output from two
years prior multiplied by the emission factors above. In 2008, HB 1434 amended the Act to include RGGI
for further C02 reductions.
Additional information:
Joe Fontaine
Air Resources Division
New Hampshire Department of Environmental Services
P.O. Box 95
Concord, NH 03302-0095
(800) 498-6868
http://des.nh.gov/organization/divisions/air/tsb/tps/aetp/categories/overview.htm
B.5 Emission Performance Standards
Several states have developed programs to set emission performance standards for retail sellers of
electricity. These output-based programs apply to all sellers, including those using non-combustion
generation. "Emission performance standards" (EPS), as discussed in this section, refers to a state rule
limiting the average emissions of the entire generation portfolio of a retail seller of electricity.
Output-Based Regulations:
A Handbook for Air Regulators
B-22
Appendix B
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Massachusetts initially proposed an EPS with restructuring legislation, requiring the establishment of an
EPS for at least one pollutant by May 2003. The principle is that each retail seller of electricity must
meet certain emission limits in Ib/MWh for its portfolio of electricity. These limits extend to all sellers
and all sources of electricity, including those outside the state. This raises some complicated issues of
tracking of electricity sales, emissions, and even limits on interstate commerce. After Massachusetts
passed its EPS language, Connecticut and New Jersey passed similar language. These programs,
however, were contingent on adoption of similar programs by other states in the region which never
occurred.
In 1999, the Northeast States for Coordinated Air Use Management (NESCAUM) sponsored the
development of a model rule approach to an EPS that would address some of the critical issues and
allow states to implement such a program consistently. A stakeholder group was convened to discuss
these issues and a proposed model approach was released.22
Under the rule, any electric generating unit that sells electricity in a state would be subject to the
performance standards. The proposed standards are listed in Table B-19.
Table B-19. NESCAUM Model Rule Emission
Performance Standards
Pollutant
Emissions (Ib/MWh)
NOx
1
S02
4
C02
1,100
CO
Reserved
Mercury
Each retail supplier is limited to no more than the
actual emission rate for the reporting calendar year.
CHP units would be assigned an emission rate calculated by allocating emissions on a pro rata basis
between electric energy output and thermal energy output multiplied by CHP factor. The factor is
initially set at 50 percent.
B.5.1 California
In September 2006, Governor Schwarzenegger signed SB 1368, creating an emission performance
standard for electric generation. Utilities may not enter into long-term purchase agreements for
baseload generation unless emissions from the plant do not exceed those of a combined-cycle natural
gas plant, set at 1,100 pounds of carbon dioxide per MWh.23
B.5.2 New York
In June 2012, New York adopted an emission performance standard. The rule, 6 NYCRR Part 251, went
into effect on July 12, 2012; it applies to new power plants with capacity of at least 25 MW and capacity
additions of at least 25 MW at existing power plants. Unlike emission performance standards in other
states, the New York rule adopts carbon limits for not only baseload plants (925 lb per MWh or 120 lb
22 http://www.nescaum.org/pdf/EPSRuleFINAL.pdf.
23 http://www.c2es.org/sites/default/modules/usmap/pdf.php?file=5889.
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B-23
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per million Btu) but also for simple cycle combustion turbines (1450 lb per MWh or 160 lb per million
Btu).
B.5.3 Oregon
SB 101, signed in July 2009, applies a different performance standard to all baseload power plants.
Generators of baseload power must have emissions equal to or less than 1,100 pounds of GHGs per
MWh, and utilities may only make long-term purchase agreements for baseload power with generators
that meet this standard. This bill addresses all baseload power, including coal plants (there is only one
coal-fired power plant in Oregon), whereas an earlier bill, HB 3283, applied only to baseload gas plants
and other non-baseload facilities. The rule does exempt certain facilities, including CHP in operation
prior to July 1, 2010, unless subject to a new long-term financial commitment. SB 101 does not have any
provisions for compliance through offsets.
B.5.4 Washington
SB 6001, enacted on May 3, 2007, issued an emission performance standard for baseload electric
generation. Electric utilities may not enter into long-term purchase agreements for baseload generation
unless the power plant emits less than 1,100 pounds of GHGs per MWh.
B.5.5 NSPS for New Power Plants
In January 2014, EPA proposed NSPS regulations to limit C02 emissions from new electric generating
units, using combustion turbines and steam boilers (EPA proposes including these requirements either
in NSPS Subparts Da and KKKK,24 or in a new subpart Till).25 The 2014 proposal replaced previous
proposals issued in 2012 and 2013 and reflects public comments received on the previous version. The
latest proposal includes separate standards for natural-gas-fired turbines and coal-fired units.26 The
revised proposed NSPS regulations apply to new electric utility steam generating units, including CHP,
where the facility has more than 73 MW (250 MMBtu/hr) design heat input and supplies more than one-
third of its potential electric output and more than 219,000 MWh net electric output to the grid per
year.27 The standards propose output-based emission limits (lb of C02/MWh), and are as follows:28
1. Fossil-fuel-fired boilers and integrated gasification combined cycle units (coal-fired):
• 1,100 lb C02/MWh gross over a 12-operating month period, or
• 1,000-1,050 lb C02/MWh gross over an 84-operating-month (seven-year) period.
2. Natural-gas-fired stationary combustion turbine units:
• 1,000 lb C02/MWh gross for larger units (> 850 mmBtu/hr)
• 1,100 lb C02/MWh gross for smaller units (< 850 mmBtu/hr)
24 EPA. Subpart Da—Standards of Performance for Electric Utility Steam Generating Units, http://www.ecfr.gov/cgi-bin/text-
idx?c=ecfr;sid=032e902341db8873af7fel53511e9f67;rgn=div6;view=text;node=40%3A7.0.1.1.1.10;idno=40;cc=ecfr.
EPA. Subpart KKKK—Standards of Performance for Stationary Combustion Turbines, http://www.ecfr.gov/cgi-bin/text-
idx?c=ecfr;sid=86adad5cd90377b914f73235b8506ef6;rgn=div6;view=text;node=40%3A7.0.1.1.1.99;idno=40;cc=ecfr.
25 EPA. 2013. Standards of Performance for Greenhouse Gas Emissions from New Stationary Source: Electric Utility Generating
Units. Proposed Rule, http://www2.epa.gov/sites/production/files/2013-09/documents/20130920proposal.pdf.
26 EPA. 2013. 2013 Proposed Carbon Pollution Standard for New Power Plants, http://www2.epa.gov/carbon-pollution-
standards/2013-proposed-carbon-pollution-standard-new-power-plants.
27 EPA. 2013. Standards of Performance for Greenhouse Gas Emissions from New Stationary Source: Electric Utility Generating
Units. Proposed Rule, http://www2.epa.gov/sites/production/files/2013-09/documents/20130920proposal.pdf.
28 Ibid.
Output-Based Regulations:
A Handbook for Air Regulators
B-24
Appendix B
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The public comment period for the proposed rule for new power plants ended on May 9, 2014. EPA has
started the rulemaking process for existing power plants in compliance with Section 111(d) of the CAA; a
proposed rule is planned by June 2, 2014, to be finalized by June 1, 2015, and states are to submit their
implementation plans by June 30, 2016.
A unit-specific, output-based emission limit such as lb C02/MWh can be set for CHP, to recognize both
electrical and thermal outputs. The equivalence approach has been applied in the existing boiler or
turbine NSPS for NOx and the ICI Boiler MACT and proposed for C02 under 111(b). However, the avoided
emissions approach is another alternative.
B.5.6 Proposed NSPS for New Stationary EGUs, Section 111(b) of the CAA29
Standard
• Output-based—
c Coal: 1,100 lb C02/MWh gross for coal (over a 12-month operating period), or 1,000-1,050
lb C02/MWh gross for coal (over an 84-month, seven-year operating period),
c Gas: 1,000 lb C02/MWh gross for larger gas units (> 850 mmBtu/hr); 1,100 lb C02/MWh
gross for smaller gas units (< 850 mmBtu/hr).
Applicability
• In the proposed regulation, a "combined heat and power facility" (also known as
"cogeneration") is an electric generating unit that that use a steam-generating unit or stationary
combustion turbine to simultaneously produce both electric (or mechanical) and useful thermal
energy from the same primary energy source.
• EPA proposes that CHP facilities meeting the general applicability criteria should be subject to
the same requirements as electric-only generators. The proposed C02 standards of performance
apply to a facility that supplies more than one-third of its potential electricity output and more
than 219,000 MWh "net electric output" to the grid per year. The current definition of net
electric output for purposes of criteria pollutants is "the gross electric sales to the utility power
distribution system minus purchased power on a calendar year basis."
• Owners/operators of a CHP facility under common ownership with an adjacent facility using the
thermal output from the CHP facility (i.e., the thermal host) may subtract power purchased by
the adjacent facility on an annual basis when determining applicability. However, third-party
CHP developers would not be able to benefit from the "minus purchased power on a calendar
year basis" provision in the definition of net electric output when determining applicability,
since the CHP facility and the thermal host(s) are not under common ownership.
Options for Codifying the Requirements
• EPA is considering two options—either proposing a new subpart Till to include the GHG
standards of performance or codifying the standards in existing 40 CFR part 60 subparts Da
(boilers) and KKKK (turbines).
29 EPA. 2014. Proposed Rule. Standards of Performance for New GHG Emissions from New Stationary Sources: Electric Utility
Generating Units. Proposed Rule. 79 FR 1430.
Output-Based Regulations:
A Handbook for Air Regulators
B-25
Appendix B
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Credit for CHP
• CHP systems in which at least 20 percent of the total gross useful energy output consists of
electric or direct mechanical output and 20 percent of the total gross useful energy output
consists of useful thermal output, on a rolling three-calendar-year basis, are to receive similar
credit as in subpart Da and proposed amendments to subpart KKKK (77 FR 52554).
• The electric output of a CHP system is to be credited at 95 percent (to account for a 5 percent
transmission loss).
• The thermal output of a CHP system is to be credited at 75 percent based on an equivalence
approach; thermal energy qualifies that is not used to generate additional electric or mechanical
output or to enhance the performance of the unit (e.g., steam delivered to an industrial process
for a heating application)
Additional information:
Mr. Christian Fellner
Energy Strategies Group
Sector Policies and Programs Division (D243-01)
U.S. EPA
Research Triangle Park, NC 27711
(919) 541-4003
http://www2.epa.gov/carbon-pollution-standards/2013-proposed-carbon-pollution-standard-new-
power-plants
B.5.7 Boiler MACT Regulations
In December 2012, EPA finalized "National Emission Standards for Hazardous Air Pollutants for Major
Sources: Industrial, Commercial, and Institutional Boilers and Process Heaters." This rule is commonly
referred to as the "Boiler MACT." It impacts large boilers and process heaters at industrial, commercial,
and institutional facilities that have the potential to emit 10 tons per year (tpy) or more of any single
hazardous air pollutant (HAP), or a combination of such pollutants in excess of 25 tpy. The covered
pollutants include CO (as a surrogate for organic HAP), hydrogen chloride, Hg, filterable PM, or total
selected metals. Existing sources must comply with the standards by January 31, 2016; however, if
needed, may request from their permitting authority an additional year to comply.
Under the rule, all boilers must follow work practice standards that include annual boiler tune-ups and a
one-time energy assessment. These work practice standards complete the compliance obligation for
natural-gas-fired boilers and existing small (<10 million Btu per hour heat input) coal- and oil-fired
boilers; however, large coal and oil-fired boilers must meet the emission limits specified in the rule. The
rule presents an opportunity for major source sites with coal- and oil-fired boilers to consider switching
to natural gas, and subsequently to consider natural-gas-fired CHP,30 instead of installing costly emission
controls to comply with the rule. The compliance date for existing major sources is January 31, 2016;
existing sources that install CHP can have until January 31, 2017 (sources may request an additional year
to comply if they need the time to install controls or to repower; this includes the installation of CHP,
waste heat recovery, or gas pipeline or fuel feeding infrastructure).
30 http://www. epa. gov/chp/documents/boiler_opportunity.pdf.
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A Handbook for Air Regulators
B-26
Appendix B
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The Boiler MACT has alternative output-based limits for all pollutants, and the thermal and electric
output are used to calculate compliance. The output-based limits are an alternative "applicable only to
boilers and process heaters that generate steam." The limits are expressed in Ib/MMBtu of steam
output. "Steam output/' in the context of CHP, means "For a boiler that cogenerates process steam and
electricity (also known as combined heat and power), the total energy output, which is the sum of the
energy content of the steam exiting the turbine and sent to process in MMBtu and the energy of the
electricity generated converted to MMBtu at a rate of 10,000 Btu per kilowatt-hour generated (10
MMBtu per megawatt-hour)."
Additional information:
Mr. Brian Shrager
Energy Strategies Group
Sector Policies and Programs Division
Office of Air Quality Planning and Standards
U.S. EPA
Research Triangle Park, NC 27711
(919) 541-7689
shrager.brian@epa.gov
http://www.epa.gov/ttn/atw/boiler/fr23dellmajor.pdf
B.6 New Source Review
NSR requires a case-by-case determination of BACT for new and modified emission sources. It is one of
the most important components of environmental permitting. Although there has been significant
interest in developing an output-based approach to NSR, such an approach has yet to be developed.
Recently, NSR for combustion sources has been based on determination of the best add-on control,
regardless of the baseline efficiency. Although EPA guidance (New Source Review Workshop Manual
October 1990) allows states to consider the baseline emission levels, most states have not done so. The
manual states:
In many cases, a given production process or emissions unit can be made to be inherently less polluting
(e.g., the use of water-based versus solvent-based paints in a coating operation or a coal-fired boiler
designed to have a low emission factor for NOx). In such cases, the ability of design considerations to
make the process inherently less polluting must be considered as a control alternative for the source.
Permit levels resulting from NSR determinations could be expressed in output-based format rather than
conventional input-based or concentration-based units. This would allow some consistency in
measurement. However, it would not integrate efficiency into the actual determination of control
requirements.
While there is continuing discussion of how to address this issue within the existing structure of NSR,
one state, Connecticut, has directly addressed the possibility in its regulations. The state's revised NSR
regulation (22a-174-3a, effective March 15, 2002) specifically allows for BACT to be determined on an
output basis, though it does not specify how it would be done.
Output-Based Regulations:
A Handbook for Air Regulators
B-27
Appendix B
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Additional information:
Chris Nelson
Connecticut Department of Environmental Protection at Bureau of Air Management
79 Elm Street, 5th Floor
Hartford, CT 06106-5127
(860) 424-3454
http://www.ct.gov/deep/lib/deep/air/regulations/mainregs/sec3a.pdf
Output-Based Regulations:
A Handbook for Air Regulators
B-28
Appendix B
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