Rulemaking for Greenhouse Gas Emissions

from Electric Utility Steam Generating Units

Tribal Consultation

May 2011

POC: Kevin Culligan
Purpose of the Consultation

► Hear from you, your concerns and comments

► Provide background information on the standards for 

GHG emissions from EGUs

► Provide summary of issues we are exploring for the 

proposal

► Discuss your input and comments

2
Background

► On December 15, 2009 (74 FR 66496), EPA published a notice indicating that 

the EPA Administrator found that the current and projected atmospheric 

concentrations of GHGs are reasonably anticipated to endanger the public 

health and welfare of current and future generations (Endangerment Finding).

► On December 23, 2010, EPA announced that it entered into a proposed 

settlement agreement to issue rules that will address GHG emissions from 

certain fossil fuel-fired EGUs.

settlement agreement to issue rules that will address GHG emissions from 

certain fossil fuel-fired EGUs.

► Rules would establish new source performance standards (NSPS) for new

and modified natural gas-, oil-, and coal-fired EGUs and emission guidelines 

for existing natural gas-, oil-, and coal-fired EGUs.

► Under the agreement, EPA commits to issuing proposed regulations by July 

26, 2011 and final regulations by May 26, 2012.

3
Power Sector:

A Major Share of U.S. GHG Emissions

2.6 Billion Tons

40%

Carbon Dioxide (CO2), 2008

6.5 Billion Tons

Electric 

Power

Other 

Sectors

► See Appendix A for additional details

4

3.9 Billion Tons

60%

Other 

Sectors

Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2008 (2010) (CO2)

“Other” sources include transportation, other mobile sources, and industrial sources
Definition of EGU

► The regulations would apply to each EGU capable of combusting 

more than 250 million British thermal units per hour (MMBtu/hr) heat 

input of fossil fuel.

► Electric utility steam generating unit means any steam electric 

generating unit that is constructed for the purpose of supplying more 

than one-third of its potential electric output capacity and more than 

25 megawatts electric (MWe) output to any utility power 

distribution system for sale.

► Fossil fuel means natural gas, petroleum, coal, and any form of 

solid, liquid, or gaseous fuel derived from such material for the 

purpose of creating useful heat.

5
Section 111 Overview

► In setting the EGU GHG NSPS, there are two particularly relevant 

provisions under section 111 of the CAA:

► CAA section 111(b) requires EPA to regulate new and modified sources

► CAA section 111(d) requires EPA to regulate existing sources.

► Section 111(d) is only relevant when the source:

– Emits pollutants that are not regulated under other parts of the CAA (i.e., 

pollutants regulated under NAAQS requirements or air toxics requirements) 

and

– Would be subject be subject to an NSPS if the existing source an NSPS if the existing source were a new source (i.e., were a new source (i.e., 

existing sources in a source category for which NSPS under section 111(b) 

have been established would be subject to section 111(d) requirements).

► EPA may distinguish among classes, types, and sizes within 

categories of sources for the purpose of establishing standards.

► EPA bases standards on demonstrated controls and may not require 

use of any particular technology, except under narrow 

circumstances (as authorized under CAA section 111(h)).

► EPA may waive compliance for sources employing innovative 

technologies with the potential for equivalent or greater reductions 

(“innovative technology waivers”).

6
Section 111 Overview (cont.)

► Standards need not be established for all emitted 

pollutants:

► where emissions are negligible, 

► no technology exists, or 

► not economically reasonable to control.

► Where not feasible to prescribe or enforce a standard of 

performance CAA section 111(h) allows for 

establishment of:

► a design, equipment, work practice, or operational standard, or 

combination 

► which reflects the best technological system of continuous emission 

reduction, we determine has been adequately demonstrated.

► taking into consideration the cost of achieving such emission reduction, 

and any non-air quality health and environmental impact and energy 

requirements

► Believe there would not be a basis for using 111(h) 

authority 

7
Section 111(b)

► NSPS implement CAA section 111(b) and are issued for categories 

of sources which cause, or contribute significantly to, air pollution 

which may reasonably be anticipated to endanger public health or 

welfare.

► Section 111(b) requirements apply to both new and modified 

sources.

► New sources are those for which construction or modification is 

commenced after the publication of proposed regulations.

► Modification is any physical change in, or change in the method of 

operation of, a source which increases the amount of any air pollutant 

emitted by the source or which results in the emission of any air 

pollutant not previously emitted.

► Exempt: Routine maintenance, repair, and replacement and increased hours 

of operation

► May set different standards for new and modified sources

► May have different standards for different subcategories

► EGUs are already subject to 111(b) requirements for a number of 

pollutants such as SO2, NOX, and PM.

8
Section 111(b) (cont.)

► Traditionally, these standards have been set at the unit level.

► NSPS are set at the Federal level. 

► States and Tribes do not have the flexibility to approve less stringent 

requirements.

► NSPS reflect the degree of emission limitation achievable through 

application of the best system of emission reduction, taking into 

consideration:

► The cost of achieving such reduction, and

► Any non-air quality health and environmental impact, and energy 

requirements.

► Level of control referred to as Best Demonstrated Technology (BDT)

► When determining Best Available Control Technology (BACT) under 

the New Source Review (NSR) requirements of the CAA, BACT 

determinations may not be less stringent than the 111(b) standards 

the agency has set.

► NSPS are to be reviewed at least every 8 years and revised if 

appropriate.

9
Section 111(d)

► Emission guidelines are established under CAA section 111(d) for source 

categories that emit pollutants not regulated under other parts of the CAA 

and to which an NSPS would apply if such existing source were a new

source.

► Section 111(d) requirements apply to existing sources.

► Because section 111(d) only applies to pollutants not regulated under other 

parts of the CAA, it has been used very infrequently.

► Only two source categories are currently subject to section 111(d) requirements 

(i.e., sulfuric acid production plants and municipal solid waste landfills).

► Solid waste incinerators have also been regulated under a very similar provision 

(CAA section 129) which requires the Agency to regulate those sources using 

the 111(d) process.

► Under section 111(d), EPA does not set explicit emission standards on 

individual sources, rather it develops emission guidelines.

► While called “guidelines,” they go through notice and comment, and are binding 

on States.

► States must promulgate rules that are consistent with the emission 

guidelines.

10
Section 111(d) (cont.)

► Key elements of Emission Guidelines include:

► Description of system of emission reductions that EPA deems 

adequately demonstrated

► Degree of emission limitation achievable, costs, and 

environmental impacts of application

► Time required to implement

► Other information information EPA determines EPA determines is necessary is necessary to facilitate to facilitate 

formation of State Plans

► Different guidelines or compliance times (or both) may 

be specified for different sizes, types, and classes of 

designated facilities when costs, physical limitations, 

geographical location, or other factors make 

subcategorization appropriate.

11
Requirements for 111(d) State Plans

► State Plans are generally due within 9 months after 

publication of the final emission guidelines.

► Other timeframes may be set by EPA for specific standards.

► States may receive exemption from plan submittal requirements 

by certifying no designated facilities exist.

► State Plans must contain:

► Emission Emission standards standards and compliance and compliance schedules schedules “no less stringent “no less stringent 

than emission guidelines”

► Allowable emission rates and possibly allowance system

► Test methods and procedures for determining compliance

► Enforceable increments of progress for compliance schedules 

longer than 12 months

12
Requirements for 111(d) State Plans 

(cont.)

► States may adopt less stringent emission standards or longer 

compliance schedules than those set out in the guidelines where the 

States demonstrate:

► Unreasonable cost of control due to age, location or basic process 

design

► Physical impossibility of installing necessary control equipment

► “Other factors specific to the facility or class of facility that make 

application of a less stringent standard or final compliance time 

significantly more reasonable.”

► States may adopt more stringent standards or shorter compliance 

schedules than those contained in the guidelines.

► EPA has the authorities issue a Federal plan where the State fails to 

submit a satisfactory plan and to enforce the provisions of a plan in 

cases where the State fails to enforce them.

► In applying a standard of performance to any particular source under 

a State implementation plan or in promulgating a standard of 

performance under a plan prescribed by EPA, the remaining useful 

life of the existing source(s) can be considered.

13
Section 111 versus Section 112

► Technology basis of standards

► CAA section 111 standards are based on BDT

► CAA section 112 standards are based on maximum achievable control 

technology (MACT) – very prescriptive

► Other considerations

► Under CAA section 111, the cost of achieving reductions, any non-air 

quality health and environmental impacts, and energy requirements are 

considered in determining BDT

► Under CAA section 112, costs and other impacts can only be considered 

when regulating beyond the minimum MACT level (the MACT floor)

► CAA section 111(d) standards developed by EPA do not directly 

impact existing sources. States use the standards as guidelines in 

establishing implementation plans with standards of performance 

that apply to those sources.

14
GHG Standards for Utilities are part of a set of EPA 

Regulations Affecting the Power Sector 

Regulatory Compliance 

Obligations for the Utility Industry:

15
Affected Facilities

Coal, 48%

Natural Gas, 21%

Non Hydro Renewables, 3%

Hydro, 6%

Nuclear, 20%

Other, 1%

► Approximately 1,525 EGUs at 605 facilities

► Approximately 1,200 coal-fired boilers at 

450 facilities in 44 States and Puerto Rico

► Coal-fired EGUs include units that burn coal, 

coal refuse, or a synthetic gas derived from 

coal either exclusively, in any combination 

together, or in any combination with other 

supplemental fuels (e.g., petroleum coke, 

tire-derived fuels).

► Bituminous coal ~ 50% of coal generation Oil, 1%

► Subbituminous ~45% of coal generation

► Lignite ~ 5% of coal generation

► Approximately 48 percent of nationwide net 

generation

► Approximately 150 oil-fired boilers at 75 

facilities, mostly in Northeast, Midwest, 

California, Florida, and Hawaii

► Approximately 1 percent of nationwide net 

generation

16
Affected Facilities (cont.)

► Approximately 175 gas-fired boilers at 80 facilities, mostly in 

Midwest, California, Louisiana, and Texas 

► Approximately 21 percent of nationwide net generation

► Are not subject to the NESHAP for EGUs

► The regulations would apply to integrated gasification combined 

cycle (IGCC, i.e, “coal gasification”) EGUs.

► Coal is “gasified” in a high-pressure, high-temperature gasifier with a 

limited supply of either oxygen or air to produce synthetic gas (syngas).

► The syngas is cooled, cleaned, and fired in a gas (combustion) turbine.

► The hot exhaust from the combustion turbine passes through a heat 

recovery steam generator (HRSG, i.e., boiler) where it produces steam 

that drives a steam turbine.

► Electric power is produced from both the combustion and steam turbinegenerators.

► There are two IGCC plants currently operating in the U.S.

► Duke Energy Wabash River Power Station in Indiana (operation began in 

1995)

► Tampa Electric Company Polk Power Station in Florida

(operation began in 1996)

17
Affected Facilities (cont.)

► In a combined cycle gas turbine plant, a gas turbine generates electricity 

and the waste heat is used to make steam to generate additional 

electricity via a steam turbine.

► More efficient method of generating electricity 

► Used by most new gas power plants in North America and Europe

► In a simple cycle gas turbine plant, there is no heat recovery.

► Have the ability to be turned on and off within minutes

► Usually used as peaking power plants because they are less efficient

► Industry includes investor- owned, publicly-owned and rural 

cooperative EGUs.

18
Power Plants Likely Covered by the

EGU GHG Rule

Source: National Electric Energy Data System (NEEDS 4.10) (EPA, December 2010)

Note: This map displays facilities that are included in the NEEDS 4.10 data base and that contain at least one coal, oil or gas-fired steam generating unit that generates more than 25 megawatts of 

power. This includes coal-fired units that burn petroleum coke and that turn coal into gas before burning (using integrated gasification combined cycle or IGCC). NEEDS reflects available capacity online by the end of 2011; this includes committed new builds and committed retirements of old units. Only steam boilers are covered by this rule. In areas with a dense concentration of facilities, the 

facilities on the map may overlap and some may be impossible to see. American Indian Reservations / Federally Recognized Tribal Entities shown were provided by the US DOI, BIA, and GDSC; they 

are not a legal representation of reservation boundaries.

19
CO2 Emissions Control Technologies

► General types of control measures for CO2 emissions:

► Energy efficiency

► Reduce the amount of fuel used by improving the efficiency of the electrical 

generation process

► Post-combustion

► Separate the CO2for long-term storage using carbon capture technology

► Other measures

► Co-firing

► Fuel switching

► Combined heat and power

20
Efficiency Improvements for Existing EGUs

► Potential efficiency improvement technologies for existing EGUs:

► Replace/upgrade burners – up to ~5%

► Improve combustion - ~0.5% to 3%

► Recover heat – up to ~6%

► Reduce air leakage - ~1.5% to 3%

► Capture energy from boiler blowdown - ~1% to 2%

► Reduce slagging and fouling of heat transfer surfaces - ~1% to 3%

► Efficiency improvement technologies demonstrated on existing coal-fired 

EGUs:

► Combustion control optimization – 0.15% to 0.84%

► Cooling system heat loss recovery – 0.2% to 1%

► Flue gas heat recovery – 0.3% to 1.5%

► Low-rank coal drying – 0.1% to 1.7%

► Sootblower optimization – 0.1% to 0.65%

► Steam turbine design – 0.84% to 2.6%

► See Appendix B for additional details

Sources: EPA White Paper - Available and Emerging Technologies for Reducing Greenhouse Gas Emissions from Industrial, Commercial, and Institutional Boilers, October 2010 21

EPA White Paper - Available and Emerging Technologies for Reducing Greenhouse Gas Emissions from Coal-Fired Electric Generating Units, October 2010
Efficiency Improvements for New EGUs

► Potential efficiency improvements for new coal-fired EGUs:

► Use of supercritical boilers

► National Energy Technology Laboratory (NETL) analysis shows that 

supercritical boilers are approximately 2.3% more efficient than subcritical 

boilers

► Use of ultra-supercritical boilers

► Can potentially operate at efficiencies approaching 50%

► Use of IGCC technology

► NETL analysis of three coal gasification processes shows net efficiencies of 

38.2% to 41.1%

► Coal drying

► Reported net gains in overall efficiency of 2% to 4%

► Boiler feedwater heating

► Increases the output of the steam cycle and potentially lowers GHG 

emissions

► See Appendix B for additional details

Source: EPA White Paper - Available and Emerging Technologies for Reducing Greenhouse Gas Emissions from Coal-Fired Electric 22

Generating Units, October 2010
Potential Impacts of Efficiency 

Improvements

► Costs are very site-specific

► Potential impacts associated with efficiency improvement technologies for existing 

250-MW pulverized coal plant with heat rate of 9,930 But/kWh

Efficiency Improvement Technology Heat Reduction, 

Btu/kWh Capital Cost, $

Installation of Neural Network process 

controls 25 0.5 million

Installation of new air heaters 92 2.0 million

Steam turbine upgrade 255 10.2 million

► Potential impacts for new coal-fired boilers

► New coal-fired supercritical plant with net power output of 800 MWe

► Capital costs of ~$2.7 billion

► Annual cost of ~$0.5 billion/year

► New IGCC plant with net power output of 800 MWe 

► Capital costs of ~$3.5 billion

► Annual cost of ~$0.6 billion/year

Sources: Sargent & Lundy Final Report 23 – Coal-Fired Power Plant Heat Rate Reductions, January 2009; EPA White Paper –

Available and Emerging Technologies for Reducing Greenhouse Gas Emissions from Coal-Fired Electric Generating Units, October 2010

Steam turbine upgrade 255 10.2 million

Improve steam turbine seals 15 0.3 million

Overhaul/upgrade of boiler feed pump 37 0.3 million

Total 424

~4% from base heat rate 13.3 million
Technology assessment

Carbon Capture & Storage

► There are no insurmountable technological, legal, institutional, or other 

barriers that prevent carbon capture and storage (CCS) from playing a role 

in reducing GHG emissions.

► Current technologies could be used to capture CO2from new and existing fossil 

energy power plants; however they are not ready for widespread implementation

primarily because they have not been demonstrated at the scale necessary to 

establish confidence for power plant application.

► CCS retrofits could face challenges at some existing plants due to space and 

configurational limitations or proximity to a CO2 pipeline or geologic storage.

► Existing Federal programs are being used to deploy at least five to ten largescale integrated CCS projects expected to be online by 2016. 

► Federal research, development and demonstration efforts are focused on 

reducing costs of CCS to facilitate widespread cost-effective deployment 

after 2020.

► Approximately 70–90% of CCS cost is associated with capture and compression.

► The cost and performance of CCS technologies will evolve with longer-term 

testing.

Source: Report of the Interagency Task Force on Carbon Capture and Storage, August 2010 24
Compliance & Monitoring

► Considering a lb/MW-hr based standard

► Considering use of emission averaging

► Believe that Part 75 requirements provide a good 

framework

► CO2 monitoring

► Output monitoring

► Data management

► Does currently reported data have any limitations for this 

purpose?

► Quality of output data

► Use of data for annual reporting requirement to support shorter 

term compliance requirement

► Potential for averaging across units

25
Key Questions

► What should emission limits for new sources be based on?

► What should emission limits for modified sources be based on?

► What should emission limits for existing sources be based on?

► What regulatory mechanisms should be used to get reductions?

► How should State equivalency with guidelines be addressed?

26
Summary of Listening Sessions

► EPA held four listening sessions to obtain stakeholder views on the design of section 

111 performance standards to reduce GHG emissions from power plants.

► Electric Power Industry

► Allow for fleet wide averaging

► Give credit for replacement of older less efficient generation

► Coalition Groups

► Allow for State programs to be deemed equivalent

► Provide market-based flexibility

► Recognize early action

► State and Tribal Representatives 

► Allow for State programs to be deemed equivalent

► Reward the very best possible systems available

► Take a multi-pollutant approach

► Environmental and Environmental Justice 

► Allow for State programs to be deemed equivalent

► Recognize environmental benefit of non-emitting technologies

► No special considerations for biomass

► Aggressive GHG approach will reduce other pollutants as well

27
Options Suggested at Listening

Sessions

► EPA received a wide range of constructive suggestions and is evaluating the 

full range of options as the proposed EGU standards are being developed.

► Stakeholders offered multiple suggestions on how standards could be set for new 

and existing units and, for existing standards, suggested a number of mechanisms.

► These are not the only options that the Agency will consider and we are open to 

suggestions of additional options.

► Note that there was broad support for the format of the standards being output 

based (e.g., pounds of GHG per KW produced).

► New Source Standards – Potential Options

► Option 1: Fuel and technology specific efficiency standards based on existing 

technologies

► Standard would likely look at coal-based technologies currently being built such as ultrasupercritical plants and IGCC plants.

► While EPA has issued NSPS that are technology and fuel specific, in recent power sector 

NSPS actions the Agency has been moving more towards fuel neutral standards.

28
Options Suggested at Listening

Sessions (cont.)

► Option 2: Standards more aggressive than those based on highly efficient coalpowered units

► Standards could consider technologies such as CCS and/or co-firing of lower CO2fuels

► Standards could potentially include emission rate averaging with certain other categories 

of sources. For instance, offsets could be obtained from:

– existing units that perform better than the existing source standard or

– units that generate electricity but are not subject to the EGU NSPS (for instance 

industrial units with on-site generation and co-generation)

► Previous NSPS rulemakings have been based on technologies demonstrated 

in the field (e.g., in the past when both scrubbers and SCRs were not nearly as 

prevalent on the coal-fired fleet, NSPS limits were based on the performance of 

such technologies).

► Option 3: Fuel neutral standards

► Rather than setting limits based purely on technology, set standards based on use of lower 

GHG fuels – for instance, gas-fired boilers.

► Recent power sector NSPS actions have moved more towards fuel neutral approaches.

► Option 4: Phased approach

► Set a standard based on option #1 that applies immediately and also require a tighter 

standard based on option #2 or #3 after several years.

29
Options Suggested at Listening

Sessions (cont.)

► Existing Source Standards – Potential Options

► Option 1: Base guidelines on efficiency improvements of the existing fleet

► Approach would likely involve reductions on the order of 5%, based on the performance of 

best units within sub-classes of boiler types (see: Available and Emerging Technologies 

for Reducing Greenhouse Gas Emissions from Coal-Fired Electric Generating Units, 

USEPA, October 2010 (http://www.epa.gov/nsr/ghgdocs/electricgeneration.pdf) and 

Improving the Efficiency of Coal-fired Power Plants for Near Term Greenhouse Gas 

Emission Reductions, NETL, April 16, 2010 (http://www.circleofblue.org/waternews/wpcontent/uploads/2011/03/DOE-NETL-Coal-fired-energy-efficiency.pdf).

► Approach Approach of basing of basing standards standards on best on best performing performing technology technology is consistent is consistent with the way with the way 

many NSPS have been set.

► Option 2: Set more aggressive guidelines that would include not only efficiency 

improvements, but also replacement of some older generation

► Could be based on remaining useful life considerations (e.g. when a unit reached a certain 

age such as 50 years, it would be required to meet tighter standards such as the new 

source standards).

► Could be based on some form of a system wide generation performance standard that 

would gradually decrease as there was fleet turnover.

– Both the municipal waste combustor NSPS and the Clean Air Mercury Rule (CAMR) incorporated 

flexibility mechanisms that allowed averaging across facilities for compliance. While CAMR was 

overturned by the DC Circuit, the court never ruled on this specific issue.

30
Options Suggested at Listening

Sessions (cont.)

► Option 3: Phased approach

► Establish guidelines based on option #1 at the beginning of the program and 

then require a tighter standard based on option #2 after several years.

► A phased approach was used in CAMR and the court never ruled on this issue.

► Implementation Mechanisms

► Different implementation mechanisms may be used in order to achieve the limits.

► Many listening session participants suggested that States should have flexibility to 

use a wide range of mechanisms to achieve reductions.

► EPA is considering both the legal and policy implications of allowing States to use 

mechanisms to meet the section 111(d) standards that differ from the 

mechanism(s) considered in the guidelines.

► Approach would require that EPA set forth criteria (e.g., an emission rate target or a 

comparison of projected emissions under an approach laid out in the emission 

guidelines and the emissions under an alternative approach being considered by 

the State).

31
Options Suggested at Listening

Sessions (cont.)

► Implementation mechanism options suggested by stakeholders:

► Averaging with tradable credits – Units would be given emission rate targets

– If they emit below the targets, they would generate credits for each MWh generated.

– If they emit above the targets, they would still be able to comply if they obtained 

credits to offset emissions above the target.

– Such an approach would only include units covered by the EGU NSPS.

– As noted above, averaging type approaches have been used in both the municipal 

waste combustor NSPS and CAMR.

► Generation Generation performance performance standard standard – similar to “Averaging with tradable similar to “Averaging with tradable credits” credits” approach approach 

above, but would include all generating sources (e.g., renewables, nuclear, etc.).

► Recognition of regional programs such as RGGI.

– CAMR allowed the use of regional programs.

► Intrastate programs with GHG limitations.

► Other programs that impact a State’s generation mix and could lead to reductions in 

emissions from covered sources such as renewable portfolio standards or clean energy 

standards.

32
What is a modified source?

► Under the modified source provisions of the NSPS, a source is 

considered modified if it’s maximum hourly emissions of a regulated 

pollutant increase.

► Increase in hourly emissions (“hourly emissions test”) must result from a 

“physical or operational change.”

► Hourly emissions test is pollutant specific.

► Hourly emissions test looks back 5 years for the highest hourly rate 

“achievable.”

► The following are not, by themselves, considered modifications:

► Maintenance, repair, and replacement which the Administrator determines to 

be routine.

► An increase in production rate of an existing facility, if that increase can be 

accomplished without a capital expenditure on that facility.

► An increase in the hours of operation.

► Use of an alternative fuel or raw material if, prior to the date the standards 

become applicable to that source, the existing facility was designed to 

accommodate that alternative use.

33
What is a modified source? (cont.)

► We anticipate two types of scenarios in which 

the modified source provisions can be 

triggered:

► Modifications to the boiler significant enough to 

increase the amount of fuel that can be combusted

► Addition of control equipment that generates CO2

emissions

34
Options for Boiler Modifications

► Modifications to boilers significant enough to 

trigger the NSPS modification provision for 

criteria pollutants are rare

► Options for treatment of such modifications 

include:

► Efficiency improvements (because the action that 

triggered it would usually be related to a fairly 

significant over-haul, more aggressive efficiency 

improvements may be cost effective)

► Standards similar to the new source standards

35
Options for Modifications Due to 

Emission Control Installations

► Most emission controls do not chemically create 

GHGs.

► Particulate control devices such as baghouses and ESPs, and 

mercury control devices such as activated carbon injection do not 

result in chemically created greenhouse gases.

► Some sorbents used in SO2removal devices do 

result in chemically created GHGs.

► Sorbents such as lime (used in dry scrubbing applications and 

some sorbent injection applications) do not result in chemical 

creation of GHGs.

► Sorbents such as limestone (used in some wet scrubbing 

applications) and trona (used in some dry sorbent injection 

applications) do result in the chemical creation of greenhouse 

gases).

36
Options for Treatment of Emission Control 

Projects that Result in GHG Increases

► Treating like all other modifications

► Treating as a separate subcategory of modification

► Because such modifications often do not involve any 

modifications to the boiler or turbine, it might be appropriate to 

consider less aggressive efficiency measures

► Treating as an existing source

► Some stakeholders have suggested this option

► EPA is still evaluating the legal justification

► Using a different size threshold to define applicability for 

certain types of projects

37
Questions?

Project Lead: Christian Fellner

919-541-4003

fellner.christian@epa.gov

Tribal Contacts: Laura McKelvey

919-541-5497

mckelvey.laura@epa.gov

Mary Johnson

Project Oversight: Bob Wayland

919-541-1045

wayland.robertj@epa.gov

38

Mary Johnson

919-541-5025

johnson.mary@epa.gov

Kevin Culligan

202-564-0611

culligan.kevin@epa.gov
Appendix A
What are Greenhouse Gases? 

► GHGs are chemical compounds found in the Earth’s atmosphere

► They allow sunlight to enter the atmosphere freely.

► When sunlight strikes the Earth’s surface, some of it is re-radiated back 

towards space as heat (infrared radiation).

► GHGs absorb the infrared radiation and trap the heat in the atmosphere.

► Over time, if atmospheric concentrations of GHGs remain relatively stable, 

the amount of energy sent from the sun to the Earth’s surface should be 

about the same as the amount of energy radiated back into space, leaving 

the temperature of the Earth’s surface roughly constant.

► Some GHGs occur naturally and are emitted to the atmosphere through 

natural processes and human activities (e.g., carbon dioxide, methane, and 

nitrous oxide).

► Other GHGs are created and emitted solely through human activities (e.g., 

fluorinated gases).

A-1
What are Greenhouse Gases? (cont.) 

► Principal GHGs that enter the atmosphere due to human activities:

► Carbon Dioxide (CO2)

► Burning of fossil fuels (oil, natural gas, and coal), solid waste, trees and wood products

► Chemical reactions (e.g., manufacture of cement, steel, aluminum)

► Methane (CH4)

► Production and transport of coal, natural gas, and oil

► Livestock and other agricultural practices

► Decay of organic waste in municipal solid waste landfills 

► Nitrous Oxide (N2O)

► Combustion of fossil fuels and solid waste

► Agricultural and industrial activities

► Fluorinated Gases

► Hydrofluorocarbon (HFC), perfluorocarbon (PFC), and sulfur hexafluoride (SF6)

► Typically emitted in smaller quantities, but are potent GHGs

► Synthetic GHGs emitted from a variety of industrial processes

► Sometimes used as substitutes for ozone-depleting substances

► Chlorofluorocarbons (CFCs) - used as refrigerants, solvents, and foam blowing agents

► Hydrochlorofluorocarbons (HCFCs) - used to replace CFCs due to lower ozone depleting 

potential

► Halons - used as fire extinguishing agent

A-2
GHG Emissions Across Sectors 

Gas/Source Type 1990 2000 2009

CO25100.2 5976.2 5508.1

Fossil Fuel Combustion 4741.2 5597.7 5212.0

Non-Energy Use of Fuels 116.2 142.5 122.1

Iron and Steel Production & Metallurgical Coke Production 99.5 85.9 42.6

Natural Gas Systems 37.6 29.9 32.2

Cement Production 33.3 41.2 29.4

Incineration of Waste 8 11.1 12.3

GHG Emissions in U.S.

(million metric tons of CO2 equivalent)

A-3

Incineration of Waste 8 11.1 12.3

Amonia Production and Urea Consumption 16.8 16.4 11.8

Lime Production 11.5 14.1 11.2

Cropland remaining Cropland 7.1 7.5 7.8

Limestone and Dolomite Use 5.1 5.1 7.6

Soda Ash Production and Consumption 4.1 4.2 4.3

Aluminum Production 6.8 6.1 3.0

Petrochemical Production 3.3 4.5 2.7

Carbon Dioxide Consumption 1.4 1.4 1.8

Ferroalloy Production 2.2 1.9 1.6

Titanium Dioxide Production 1.2 1.8 1.5

Wetlands remaining Wetlands 1 1.2 1.1

Phosphoric Acid Production 1.5 1.4 1

Source: Table ES-2 of EPA’s Draft Inventory of U.S. Greenhouse Gas Emissions and Sinks 1990-2009, February 15, 2011
GHG Emissions Across Sectors (cont.) 

Gas/Source Type 1990 2000 2009

CH4674.9 659.9 686.5

Natural Gas Systems 189.8 209.3 221.2

Enteric Fermentation 132.1 136.5 139.8

Landfills 147.4 111.7 117.5

Coal Mining 84.1 60.4 71.0

Manure Management 31.7 42.4 49.5

GHG Emissions in U.S. (cont.)

(million metric tons of CO2 equivalent)

A-4

Manure Management 31.7 42.4 49.5

Petroleum Systems 35.4 31.5 30.9

Wastewater Treatment 23.5 25.2 24.5

Forest Land remaining Forest Land 3.2 14.3 7.8

Rice Cultivation 7.1 7.5 7.3

Stationary Combustion 7.4 6.6 6.2

Abandoned Underground Coal Mines 6.0 7.4 5.5

Mobile Combustion 4.7 3.4 2.2

Iron and Steel Production & Metallurgical Coke Production 1.0 0.9 0.4

Source: Table ES-2 of EPA’s Draft Inventory of U.S. Greenhouse Gas Emissions and Sinks 1990-2009, February 15, 2011
GHG Emissions Across Sectors (cont.) 

Gas/Source Type 1990 2000 2009

N2O 315.2 341.0 299.5

Agricultural Soil Management 197.8 206.8 204.6

Mobile Combustion 43.9 53.2 27.8

Manure Management 14.5 17.1 17.9

Nitric Acid Production 17.7 19.4 14.6

Stationary Combustion 12.8 14.6 12.8

Forest Land remaining Forest Land 2.7 12.1 6.7

Wastewater Treatment 3.7 4.5 5.0

N2O from Product Uses 4.4 4.9 4.4

GHG Emissions in U.S. (cont.)

(million metric tons of CO2 equivalent)

A-5

N2O from Product Uses 4.4 4.9 4.4

Adipic Acid Production 15.8 5.5 1.9

HFCs 36.9 103.2 125.0

Substitution of Ozone Depleting Substances 0.3 74.3 119.3

HCFC-22 Production 36.4 28.6 5.4

Semiconductor Manufacture 0.2 0.3 0.3

PFCs 20.8 13.5 5.6

Semiconductor Manufacture 18.5 8.6 1.6

Aluminum Production

SF634.4 20.1 14.8

Electrical Transmission and Distribution 28.4 16 12.8

Magnesium Production and Processing 5.4 3.0 1.1

Semiconductor Manufacture 0.5 1.1 1.0

Source: Table ES-2 of EPA’s Draft Inventory of U.S. Greenhouse Gas Emissions and Sinks 1990-2009, February 15, 2011
GHG Emissions - Energy Sector

Energy Sector GHG Emissions

(million metric tons of CO2 equivalent)

Gas/Source Type 1990 2000 2009

CO24903.6 5781.7 5379.0

Fossil Fuel Combustion 4741.2 5597.7 5212.0

Electricity Generation 1820.8 2296.9 2154.0

Transportation 1485.9 1809.5 1718.9

Industrial 849.3 853.9 738.4

Source: Table 2-4 of EPA’s Draft Inventory of U.S. Greenhouse Gas Emissions and Sinks 1990-2009, February 15, 2011

A-6

Industrial 849.3 853.9 738.4

Residential 338.3 370.7 340.2

Commercial 219.0 230.8 218.8

U.S. Territories 27.9 35.9 41.7

Non-Energy Use of Fuels 116.2 142.5 122.1

Natural Gas Systems 37.6 29.9 32.2

Incineration of Waste 8.0 11.1 12.3

Petroleum Systems 0.6 0.5 0.5
GHG Emissions - Energy Sector (cont.)

Energy Sector GHG Emissions (cont.)

(million metric tons of CO2 equivalent)

Gas/Source Type 1990 2000 2009

CH4327.4 318.6 337.0

Natural Gas Systems 189.8 209.3 221.2

Coal Mining 84.1 60.4 71.0

Petroleum Systems 35.4 31.5 30.9

Stationary Combustion 7.4 6.6 6.2

Source: Table 2-4 of EPA’s Draft Inventory of U.S. Greenhouse Gas Emissions and Sinks 1990-2009, February 15, 2011

A-7

Stationary Combustion 7.4 6.6 6.2

Abandoned Underground Coal Mines 6.0 7.4 5.5

Mobile Combustion 4.7 3.4 2.2

Incineration of Waste <0.05 <0.05 <0.05

N2O 57.2 68.1 41.0

Mobile Combustion 43.9 53.2 27.8

Stationary Combustion 12.8 14.6 12.8

Incineration of Waste 0.5 0.4 0.4
GHG Emissions – Electricity Generation

Gas/Source Type 1990 2000 2009

CO2

Fossil Fuel Combustion 1820.8 2296.9 2154

Coal 1547.6 1927.4 1747.6

Natural Gas 175.3 280.8 373.1

Petroleum 97.5 88.4 32.9

Electricity Generation-Related GHG Emissions

(million metric tons of CO2 equivalent)

Source: Table 2-13 of EPA’s Draft Inventory of U.S. Greenhouse Gas Emissions and Sinks 1990-2009, February 15, 2011

► CO2 emissions from fossil fuel combustion are ~99.5% of total GHG emissions from fossil fuel 

combustion (2009)

► CO2 emissions from coal-fired combustion are ~81% of total CO2 emissions from fossil fuel 

combustion (2009)

A-8

Petroleum 97.5 88.4 32.9

CH4

Stationary Combustion 0.6 0.7 0.7

N2O

Stationary Combustion 8.1 10.0 9.0
Appendix B
Efficiency Improvements for Existing EGUs

Efficiency Improvement 

Technology Description EfficiencyIncrease

Replace/Upgrade Burners

Replacement or upgrade of older, incorrectly sized, or 

mechanically deteriorated burners and inoperable dampers, 

broken registers, or clogged nozzles

Up to ~5%

Improved combustion

Tuning of combustion system to optimum settings and 

use/adjustment of instrumentation (e.g., temperature 

sensor, oxygen monitor, excess air setting, CO monitor)

~0.5 to 3%

Heat recovery

Use of heat from boiler exhaust to preheat incoming Up to ~6%

Efficiency Improvements for Existing EGUs

B-1

Source: EPA White Paper - Available and Emerging Technologies for Reducing Greenhouse Gas Emissions

from Industrial, Commercial, and Institutional Boilers, October 2010

Heat recovery

Use of heat from boiler exhaust to preheat incoming 

combustion air or to preheat boiler feedwater Up to ~6%

Reduce air leakages

Maintenance of boiler system to minimize air leakage 

through routine maintenance procedures and monitoring of 

indicators of air leakage (e.g., oxygen level, fuel 

consumption, gas temperature)

~1.5 to 3%

Capture energy from 

boiler blowdown

Recovery of waste heat (low-pressure steam) from 

blowdown

~1 to 2%

Reduce slagging & fouling 

of heat transfer surfaces

Operation within boiler’s design parameters (including fuel 

quality), use of cleaning system (soot blower - air or steam 

is used to periodically remove deposition on boiler walls and 

tubes), and/or fuel treatment (modifies ash characteristics)

1% to 3%
Efficiency Improvements for Existing

EGUs ( cont.)

Efficiency Improvement 

Technology Description

Reported 

Efficiency

Increase

Combustion Control 

Optimization

Adjustment of coal and air flow to optimize steam 

production for the generator 0.15 to 0.84%

Cooling System Heat Loss 

Recovery

Recovery of a portion of the heat loss from cooling water 

exiting the steam condenser 0.2 to 1%

Efficiency Improvements for Existing Coal-Fired EGUs

B-2

Source: EPA White Paper - Available and Emerging Technologies for Reducing Greenhouse Gas Emissions

from Coal-Fired Electric Generating Units, October 2010

Recovery exiting the steam condenser

Flue Gas Heat Recovery Recovery of the heat lost when flue gas is sprayed with flue 

gas desulfurization (FGD) reagent slurry and cools 0.3 to 1.5%

Low-rank Coal Drying Drying of subbituminous and lignite coals using waste heat 

from flue gas and/or cooling water systems 0.1 to 1.7%

Sootblower Optimization

Intermittent injection of high velocity gets of steam or air to 

clean coal ash deposits from boiler tube surfaces to 

maintain adequate heat transfer

0.1 to 0.65%

Steam Turbine Design

Maintain mechanical and physical condition of steam 

turbine through use of efficiently designed turbine blades 

and steam seals

0.84 to 2.6%
Efficiency Improvements for New EGUs

► Efficiency improvements for new coal-fired EGUs

► Use of supercritical boilers

► Operate at higher pressures and temperatures

► Start-up times are quicker

► National Energy Technology Laboratory (NETL) analysis shows that 

supercritical boilers are approximately 2.3% more efficient than subcritical 

boilers

► Application currently limited to facilities of approximately 200 MWe gross output 

or more due to the availability of steam turbines that are designed for 

supercritical steam conditions 

► Use of ultra-supercritical boilers

► Operate at even higher pressures and temperatures

► Can potentially operate at efficiencies approaching 50%

► Material degradation can be an issue when firing high-sulfur coal

► Use is prevalent in Denmark, Germany, and Japan

► First ultra-supercritical EGU in U.S. – Southwest Electric Power Company’s 

John W. Turk, Jr. Power Station near Texarkana, AR

► 600 MWe pulverized coal-fired EGU

► Will burn Powder River Basin subbituminous coal

► Scheduled to begin operation in late 2012

Source: EPA White Paper - Available and Emerging Technologies for Reducing Greenhouse Gas Emissions from Coal-Fired B-3

Electric Generating Units, October 2010
Efficiency Improvements for New EGUs 

(cont.)

► Use of IGCC technology

► Electric output is generated by both the combustion turbine and the steam 

turbine

► NETL analysis of three coal gasification processes shows net efficiencies of 

38.2% to 41.1%

► Coal drying

► Several advanced pre Several advanced pre-combustion coal drying technologies combustion coal drying technologies are or nearly are or nearly are 

commercially available

► Reported net gains in overall efficiency of 2% to 4%

► Boiler feedwater heating

► Use of heat sources other than the steam turbine to heat feedwater

► Increases the output of the steam cycle and potentially lowers GHG emissions

Source: EPA White Paper - Available and Emerging Technologies for Reducing Greenhouse Gas Emissions from Coal- B-4

Fired Electric Generating Units, October 2010