Department of the Environment TECHNICAL SUPPORT DOCUMENT FOR

Department of the Environment  TECHNICAL SUPPORT DOCUMENT FOR
Department of the Environment
TECHNICAL SUPPORT DOCUMENT
FOR
COMAR 26.11.38 - Control of NOx Emissions
from Coal-Fired Electric Generating Units
May 26, 2015
PREPARED BY:
MARYLAND DEPARTMENT OF THE ENVIRONMENT
1800WashingtonBoulevard
BaltimoreMaryland21230
NOxRegulationsforCoalEGU’s
COMAR26.11.38
I. INTRODUCTION..............................................................................................................................5 A. Ozone NAAQS and Designations ...................................................................................................................... 5 B. Maryland Historic Design Values ..................................................................................................................... 6 C. Health and Environmental Impacts .................................................................................................................. 7 II. RATIONALE......................................................................................................................................9 A. Maryland Coal‐fired NOx Regulations .............................................................................................................. 9 B. Performance of Existing Coal‐fired Electric Generating Units ......................................................................... 10 C. Proposed NOx Emissions Control Strategies ................................................................................................... 12 D. The Proposed Regulation – COMAR 26.11.38 ................................................................................................ 15 III. THEANALYSES........................................................................................................................20 A. Peak Day Electricity Generation and High NOx Emissions ............................................................................... 20 B. 2015 Emission Reduction Estimates ............................................................................................................... 20 C. Modeling ...................................................................................................................................................... 22 D. The Effectiveness of NOx Reductions ............................................................................................................. 23 IV. REGULATIONREQUIREMENTDETAILSFOROPERATINGANDCOMPLIANCE...26 A. Affected Sources ........................................................................................................................................... 26 B. NOx Reduction Requirements ........................................................................................................................ 26 V. ECONOMICANALYSIS................................................................................................................30 A. Cost Categories ............................................................................................................................................. 30 B. Assumptions ................................................................................................................................................ 30 VI. BACKGROUNDINFORMATION–OZONEPOLLUTION................................................31 A. Background................................................................................................................................................... 31 2
B. Effects of Ground Level Ozone ....................................................................................................................... 31 VII. OVERVIEWOFRELEVANTFEDERAL,REGIONALANDSTATESTANDARDSAND
REGULATIONS.......................................................................................................................................32 A. National Ambient Air Quality Standards (NAAQS) ......................................................................................... 32 B. NOx SIP Call ................................................................................................................................................... 33 C. Clean Air Interstate Rule (CAIR) ..................................................................................................................... 34 D. Maryland Healthy Air Act (HAA) .................................................................................................................... 35 VIII. MARYLANDELECTRICGENERATINGUNITS..................................................................38 A. Coal‐Fired Electric Generating Units Located In Maryland .............................................................................. 38 B. Brandon Shores Generating Station: .............................................................................................................. 39 C. H.A. Wagner Generating Station: ................................................................................................................... 40 D. Charles P. Crane Generating Station: ............................................................................................................. 41 E. Morgantown Generating Station: .................................................................................................................. 42 F. Chalk Point Generating Station: ..................................................................................................................... 43 G. Dickerson Generating Station: ....................................................................................................................... 44 H. Warrior Run Generating Station: ................................................................................................................... 45 I. NOx Emissions Control Equipment on Affected Electric Generating Units ........................................................ 45 Table VIII‐1: Summary of NOx Control Equipment Installed on Coal‐Fired EGU’s in Maryland ............................. 46 IX. OVERVIEWOFNOXCONTROLTECHNOLOGIESFORCOAL‐FIREDELECTRIC
GENERATINGUNITS...........................................................................................................................47 A. Selective Catalytic Reduction (SCR) Technology ............................................................................................. 47 B. Selective Non‐Catalytic Reduction (SNCR) Technology ................................................................................... 49 C. Selective Autocatalytic Reduction (SACR) Technology .................................................................................... 50 X. APPENDICES.................................................................................................................................51 3
APPENDIXA‐HEALTHYAIRACTNOTICEOFPROPOSEDACTION2007
APPENDIXB‐MARYLANDUNITSWITHSCRANDSNCRRATESANDTONS
APPENDIXC‐MARYLANDNOXRATE24HOURBLOCK
APPENDIXD‐NOXRATESFORSCRANDSNCR
APPENDIXE‐OTCRACTPRINCIPALSSTATEMENT
APPENDIXF‐SUMMERSTUDY
APPENDIXG‐EMISSIONREDUCTIONCALCULATIONS
APPENDIXH‐COMPLIANCEPLAN
APPENDIXI‐COLLABORATIVESOLUTIONTOTHEOZONETRANSPORTPROBLEM
4
I.
Introduction
A. Ozone NAAQS and Designations
On March 12, 2008, EPA strengthened the national ambient air quality standard (NAAQS), for
ground-level ozone, setting both the primary and secondary standards to a level of 0.075 parts
per million (ppm) or 75 parts per billion (ppb) averaged over an 8-hour period. The primary
standard serves to protect public health, while the secondary standard serves to protect public
welfare such as property, vegetation and ecosystems.
In April and May 2012, EPA designated all areas of the country with respect to the 0.075 ppm
ozone standard. Designations include “attainment” which indicates that an area is meeting the
standard, or “nonattainment” indicating areas that do not meet it. Three areas of Maryland were
designated nonattainment and were then classified with respect to the severity of their ozone
problem:
1. Baltimore area – “moderate” nonattainment area
This area includes Anne Arundel County, Baltimore County, Baltimore City, Carroll
County, Harford County, and Howard County.
2. Philadelphia-Wilmington-Atlantic City, PA-NJ-MD-DE – “marginal” nonattainment area
This area includes one jurisdiction in Maryland: Cecil County.
3. Washington, DC-MD-VA – “marginal” nonattainment area
This nonattainment area includes the following Maryland jurisdictions: Calvert County,
Charles County, Frederick County, Montgomery County, and Prince George’s County.
Under Clean Air Act (CAA) requirements and subsequent EPA guidance, nonattainment areas of
“moderate” or higher classification are required to submit a reasonable further progress (RFP)
plan. The RFP plan must show progress by making a 15 percent reduction in emissions over six
years toward attainment of the ozone standard.
The Baltimore “moderate” nonattainment area must also submit a state implementation plan
(SIP) revision by June 2015 that includes an attainment demonstration. This SIP confirms via
modeling and other analyses the success of selected emission reduction strategies in enabling the
Baltimore area to attain the standard by 2018.
In 2014, pursuant to Clean Air Act §182, the Maryland Department of the Environment (MDE)
is required to review and, as appropriate, revise the nitrogen oxides (NOx) Reasonably Available
Control Technology (RACT) requirements in the Maryland SIP. EPA defines RACT as the
lowest emissions limitation that a particular source is capable of meeting via the application of
control technology that is reasonably available considering technological and economic
feasibility. The emissions limitation may, for example, be measured on a “parts per million” or
“pounds per million British thermal units (Btu)” basis. Control technology includes, for example,
installation and operation of low-NOx burners.
5
Whenever EPA establishes a new ozone standard, states with an ozone nonattainment area of
“moderate” or higher classification are required to determine whether existing RACT
requirements are stringent enough. The state must consider technological advances, the
stringency of the revised ozone standard, and the presence in the nonattainment area of new
sources subject to RACT. Maryland's RACT SIP for the new 75 ppb ozone standard must
examine major sources of NOx and their existing controls to determine whether additional
controls are economical and technically feasible.
The following table describes the classification and required attainment dates for Maryland’s
nonattainment areas.
Table I-1: 8-Hour Ozone Nonattainment Areas in Maryland*
Nonattainment
Designation
Counties
Classification
Area
Date
Baltimore
07/20/12
Anne Arundel
Moderate
Baltimore City
Baltimore
Carroll
Harford
Howard
Philadelphia –
07/20/12
Cecil
Marginal
Wilmington –
Atlantic City
Washington DC
07/20/12
Calvert
Marginal
Charles
Frederick
Montgomery
Prince George’s
Attainment Date
12/31/18
12/31/15
12/31/15
*Source: U.S. EPA. NAAQS for ground-level ozone is 0.075 parts per million (ppm) or 75 parts per billion (ppb)
averaged over an 8-hour period.
References
http://www.epa.gov/airquality/ozonepollution/implement.html
http://www.epa.gov/ozonedesignations/2008standards/state.htm
B. Maryland Historic Design Values
While Maryland’s air quality has improved over recent years, the state continues to struggle to
attain the 8-hour 0.075 ppm ozone standard. As shown in Figure 1, Maryland’s design values
hover at 76 ppb due to the two very mild summers of 2013 and 2014. During summers with
warmer temperatures when the weather is more conducive to ozone formation, Maryland will
likely not be able to maintain compliance with the ozone standard. Even though air quality is
improving, on November 26, 2014, EPA proposed adoption of a lower ozone standard in the
range of 65 to 70 ppb. Stricter controls on local emissions, such as this regulatory action, and
federal and regional controls on upwind sources of emissions will be needed to satisfy both
6
RACT and attainment requirements to reduce ozone levels in Maryland. This regulatory action
plays a major role in fulfilling both requirements.
Figure 1: Maryland 8-Hour Ozone Design Values
8‐Hour Ozone Design Values
107
120
104
94
93
91
93
89
85
77
80
40
8-Hour Ozone (ppb)
107
0
1997 1999 2001 2003 2005 2007 2009 2011 2013
Source: Maryland Department of the Environment.
Several major regulations are responsible for the most significant reductions in historic ozone
levels, such as the EPA NOx SIP Call and Maryland Healthy Air Act. More recent studies of
ozone chemistry have shown that NOx reductions are the most effective strategy for reducing
ozone levels. Ground-level ozone levels dropped nationwide in 2003 due to the NOx SIP call.
The NOx SIP call resulted in the installation of advanced pollution controls such as selective
catalytic reduction (SCR), selective non-catalytic reduction (SNCR), and selective alternative
catalytic reduction (SACR) technologies at well over 100 electric generating units and
significantly reduced the amount of NOx produced throughout the nation resulting in much less
monitored ozone pollution. See Chapter VI for additional historic background.
C. Health and Environmental Impacts
Impacts on Public Health and Welfare
Researchers have associated ozone exposure with adverse health effects in numerous
toxicological, clinical and epidemiological studies. Reducing ozone concentrations is associated
with significant human health benefits, including the avoidance of mortality and respiratory
illnesses. NOx is an ozone precursor, and reducing NOx emissions would also reduce adverse
health effects associated with NO2 exposure. These health benefits include fewer asthma
attacks, hospital and emergency room visits, lost work and school days, and lower premature
mortality.
Impacts on the Chesapeake Bay
More than one-third of the pollution entering the Chesapeake Bay comes from the air. Pollutants
released into the air (primarily from power plants and vehicle emissions) eventually make their
way back down to the earth’s surface and are dispersed onto the land and transported into
waterways. In addition to other State and federal regulations currently in effect, the standards and
7
requirements in the proposed regulation reduce the amount of nitrogen entering the Bay each
year.
Impacts on Vegetation and Agriculture
Exposure to ozone has been associated with a wide array of adverse impacts on vegetation and
ecosystem. These effects include those that damage or impair the intended use of the plant or
ecosystem. According to the EPA, new scientific evidence since the last review of the ozone
NAAQS continues to document the adverse impact of ozone on the public welfare. This
includes reduced growth and/or biomass production in sensitive plant species, including forest
trees. High ozone levels reduce crop yields, reduce plant vigor (e.g., increased susceptibility to
harsh weather, disease, insect pest infestation, and competition), and cause visible foliar injury,
species composition shift, and changes in ecosystems and associated ecosystem services.
References
http://www.epa.gov/groundlevelozone/health.html
http://www.epa.gov/airquality/ozonepollution/ecosystem.html
8
II.
Rationale
The Maryland Department of the Environment proposes COMAR 26.11.38 - Control of NOx
Emissions from Coal-Fired Power Plants as a key element in Maryland’s current and future State
Implementation Plans (SIPs) to achieve statewide compliance with the federal ozone standard. In
2015, the Department is required to submit an ozone attainment SIP that includes emission
reduction strategies designed to achieve compliance with the 75 ppb ozone standard by 2017. In
addition, Sections 182 and 184 of the Clean Air Act requires the Department to review and
revise NOx RACT requirements in Maryland’s SIP as necessary to achieve compliance with new
more stringent ambient air quality standards.
Although the Department previously promulgated several regulations applicable to coal-fired
power plants, NOx emissions from this source category continue to comprise a large percentage
of ozone season NOx emissions - in large part due to high electricity demand days.
This proposed regulation, when effective, will result in immediate reductions in ozone season
NOx emissions from these sources, especially on high electricity demand days which are needed
to achieve and maintain compliance with the 75 ppb ozone standard.
A. Maryland Coal-fired NOx Regulations
As stated earlier, Maryland has three nonattainment areas under the 75 ppb ozone standard. One
of the requirements for such areas is review of the RACT requirements for each category of
major sources to determine whether current RACT limits are adequate in light of the more
stringent standard and advancing technologies. The category of coal-fired electric generating
units is one of the first categories reviewed.
Under the Maryland Healthy Air Act, all active coal-fired electric generating units added NOx
reduction technologies that utilize chemical reductants to lower NOx outputs. These
technologies included selective catalytic reduction (SCR), selective non-catalytic reduction
(SNCR), and selective alternative catalytic reduction (SACR), which are discussed in further
detail in Chapter IX. The Healthy Air Act achieved significant reductions in NOx emissions
through the application of mass limitations or caps on the affected coal-fired units. Separate caps
were applied to annual and ozone season emissions. The use of caps rather than rates allowed the
units flexibility to comply under all modes of operation, but were stringent enough to severely
restrict the amount of operating time when the controls were not being optimized. The
implementing regulation allowed system-wide compliance with the emission limits by
demonstrating that the total tons from the all the units in the system did not exceed the tonnage
limit for all units within the system. Systems are defined as all units under the same ownership.
At this time, there are two systems: (1) units owned by Raven Power Finance LLC consisting of
Brandon Shores Units 1 and 2, H. A. Wagner Units 2 and 3, and C. P. Crane Units 1 and 2
(Raven Power System); and (2) units owned by NRG Energy, Inc. consisting of Morgantown
Units 1 and 2, Chalk Point Units 1 and 2, and Dickerson Units 1, 2 and 3 (NRG System). The
practice of demonstrating compliance by allowing a system of units to combine to meet the
requirement is often referred to as “averaging”.
9
Prior owners of these two systems installed SCR, SNCR and SACR at units subject to the
requirements of the Healthy Air Act. The companies made decisions on which of these control
systems would be utilized with the concept of averaging emissions from the individual units in
mind. “Baseload” units were equipped with SCR while “load following” units were equipped
predominantly with SNCR or SACR. Overall, the controls yielded a 75 percent reduction in NOx
emissions from 2002 levels. The mass emission caps driving this reduction were based on
historic utilization of the units, at high levels of operation and electricity production.
B. Performance of Existing Coal-fired Electric Generating Units
In recent years the utilization of coal plants has changed dramatically on a national level as well
as in Maryland. The sharp decline in natural gas prices, the rising cost of coal, and reduced
demand for electricity are all contributing factors to a substantial reduction in how often coalfired plants are called upon to operate.
Figure 2: Maryland HAA Coal Fired Power Plant Capacity Factors
*Source: Maryland Department of the Environment. See Appendix A - Maryland HAA Notice of Proposed Action
March 30, 2007
Today, as a result of these changes in the electricity markets some coal-fired plants only operate
during periods of peak electricity demand. This reduction in operation results in lower overall
NOx emissions and units can operate in compliance with the mass emission caps of the Healthy
Air Act without having to run the NOx pollution controls in a manner that optimizes NOx
emission reductions. Emissions are higher over shorter operating time periods. The Department
10
found through data analysis that existing SCR and SNCR controls at the coal-fired units were not
consistently operating to maximize emission reductions. At most units the ozone season NOx
emission rate has increased steadily since 20081.
1
An evaluation of performance data related to units equipped with SCR and SNCR can be found in Appendix B and
Appendix C.
Through analysis of NOx emission rate trends, the Department found that coal-fired plants with
frequently run units equipped with SCRs, such as Morgantown, were operating the SCRs to
achieve peak performance. At peak performance, operation of controls on these units reduced
NOx emissions sufficiently on most operating days to achieve compliance with the HAA and
other federal limitations with only sporadic operation of SNCRs or SACR units and units with no
controls. Thus, with an increasing amount of electricity generation (load) served by gas-fired
units and a decreasing amount of load served by coal-fired units, operation of installed controls
was orchestrated to remain within the applicable emission limits, rather than to maximize NOx
reductions.
The Department’s analysis also revealed that while units equipped with SNCRs operated less
than units equipped with advanced NOx controls, they often operated on high temperature days
when electricity demand is highest (“peak days”). These are the days that also are the most
conducive to ozone formation. The operation of these units without the operation of the installed
controls often increased the total NOx emissions of the system by as much as 50% on peak days.
The units complied with their regulatory limits, but contributed significantly to high ozone levels
locally. The Department developed modeling analyses to evaluate the impact of this lost
emission reduction potential. Operation of installed controls is much less expensive than
installation of the controls. Optimization of existing controls can produce substantial additional
emission reductions very cost-effectively. Effective emission limits in the form of rates can
require operation of controls whenever units are called upon to operate.
Most of the existing electricity generating capacity in Maryland is very old. The remaining
useful life of a unit is a factor in choosing to equip units with less costly SNCR controls. SNCRs
are less efficient at reducing NOx emissions than SCRs, achieving a 20-40 percent emission
reduction depending on the unit. While numerous studies exist evaluating the effectiveness of
SCRs at controlling NOx emissions, substantially less information exists regarding the
effectiveness of SNCRs. In a study prepared by Andover Technology Partners and the EPA2,
high operation units typically achieved rates of 0.07 lbs/MMBtu NOx when equipped with an
SCR. Units equipped with SNCRs typically operate in the 0.2 - 0.3 lbs/MMBtu NOx range.
The Department did not find clear data regarding exactly when controls on the various units
operated for use in identifying unit by unit performance rates. Raven Power and NRG voluntarily
agreed to conduct an in-depth study during the summer of 2014 to determine how to achieve
optimal performance of installed controls. The agreements of the 2014 Summer Study are
attached in Appendix F and the raw data files will be available on MDE’s website. This
information will be used in developing the plan each company needs to submit under the
regulation detailing operational parameters for each individual unit in all modes of operation.
Because the weather patterns occurring during the summer of 2014 were not typical of the
patterns that form ozone in Maryland, operating hours for a number of units were curtailed and
11
sufficient data was not available to develop individual unit by unit rates. The study did lay the
foundation for more detailed record keeping on the operational parameters of the units during all
modes of operation in preparation for development of the plans required under Regulation
.03A(1).
2
Staudt, James E., Khan, Sikander R., and Manuel J. Oliva. “Reliability of Selective Catalytic Reduction (SCR) and
Flue Gas Desulfurization (FGD) Systems for High Pollutant Removal Efficiencies on Coal Fired Utility Boilers”.
2004 MEGA Symposium, Paper # 04-A-56-AWMA. Andover Technology Partners. Paper can be found in
Appendix D.
C. Proposed NOx Emissions Control Strategies
The Department weighed emission reductions achieved by establishing generic rates for units
controlled with specific equipment (SCR, SNCR and SACR) against establishing a system-wide
rate. Through data analysis, the Department found that many of the units with SCR could
achieve very stringent rates, exceeding the stringency of the commonly accepted 0.07
lbs/MMBtu NOx rate. Rates lower than 0.07 lbs/MMBtu NOx are used to offset higher emission
rates from units equipped with SNCR or SACR. The better controlled units operate more often
and provide more of the reductions. The proposed regulation includes a not-to-exceeded rate of
0.15 lbs/MMBtu NOx as a system-wide 30-day rolling average. Under this emission limit,
operation of units controlled with SCR is not limited as long as the controls operate. Operation of
units with SNCR is determined by how well the controls are run and how much overcontrol is
provided by the other units in the system. Operation of the SNCR-controlled units may be
curtailed in some instances to comply with the 0.15 lbs/MMBtu NOx emission limit. Curtailment
of operation of a unit becomes another method of control. The use of a system-wide rate allows
well-controlled units to operate maximally, while limiting operation of less well-controlled units.
While a not-to-exceed ozone season rate of 0.15 lbs/MMBtu NOx, called a hard rate, provides
assurance that emissions remain below a set level averaged over a system, it is evident that
during high demand operations with controls optimized, the system is capable of meeting a much
lower rate. Coal-fired units operate most efficiently at high utilization, but, as discussed above,
current economic conditions force coal-fired units to operate in a number of less efficient ways
that require the units to ramp up and down more often. During these times, the operating
parameters of the unit do not support the maximum NOx removal efficiency of the control
device. Historically, coal-fired units started up, ramped up to higher load capacity and operated
in that manner for quite a long time. While load may have varied by 20 or 30 percent, the units
were operating at fairly high capacity. In today’s electricity markets, operations are different.
Units may start-up and shut down in the same day. Or they may operate at low capacity,
combusting coal and producing electricity at the lowest possible rate. The units can then be ready
to ramp up on short notice during peak demand times. Instead of including an exception for low
load operation in the regulation as other states have done, the Department requires a plan to
minimize NOx emissions under all modes of operation in Regulation .03A1. The plan will
establish alternate rates for each mode of operation, applicable when the unit is operating in that
mode. At all times, the controls at each unit will be operating in the most optimal manner
possible considering the technical limitations of the control.
The provisions of §A(2) in Regulation .03 require a unit that is operating to optimize the use of
all installed control technology to minimize NOx emissions consistent with the technological
12
limitations, manufacture’s specifications, good engineering and maintenance practices, and good
air pollution control practices. The provisions of §A(1) in Regulation .03 requires each unit to
develop a plan for operation of the unit that details how the controls will be operated not only at
times of peak performance, but also during other modes of operation when operating at low load,
ramping up or down, or other off-peak mode. The plan will be reviewed and approved by the
Department and by EPA. The table below reproduced from Regulation .05 represents indicator
rates of good performance for the named units based on utilization of the installed control
technology. See Chapter IV for an expanded discussion of the indicator rates. The rates are
calculated in 24-hour blocks to limit the amount of averaging that can take place to offset rates
that are higher than the indicator rates. If a unit fails to meet the 24-hour block average indicator
rate for a day, the unit operator must submit a report to the Department detailing the operating
parameters of the unit for that day. These operating parameters will be compared to the approved
plan to evaluate whether the unit followed best practices for the conditions of operation
occurring that day. Suggested elements for inclusion in the plan can be found in Chapter IV.
Compliance with the 0.15 lbs/MMBtu rate, as well as the indicator rates, will be included in a
monthly report. Units that fail to meet the indicator rates will submit supporting operational data
for comparison with the unit’s emission minimization plan.
Table II-1: Indicator Rates for Coal-Fired Electric Generating Units
Affected Unit
24-Hour Block Average
NOx Emissions
in lbs/MMBtu
Brandon Shores
Unit 1
0.08
Unit 2
< 650 MWg
≥ 650 MWg
0.07
0.15
C.P. Crane
Unit 1
0.30
Unit 2
0.28
Chalk Point
Unit 1 only
0.07
Unit 2 only
0.33
Units 1 and 2
combined
0.20
Dickerson
Unit 1 only
0.24
Unit 2 only
0.24
Unit 3 only
0.24
Two or more Units
combined
0.24
13
H.A. Wagner
Unit 2
0.34
Unit 3
0.07
Morgantown
Unit 1
0.07
Unit 2
0.07
The Department’s analysis of data and modeling information during ozone season indicates that
exceedances of the ozone standard occur most often on days when the electricity system is
operating at peak load. During this time, the less well-controlled high emitting units are called to
operate, increasing the daily NOx emissions by at least 50 percent.
14
D. The Proposed Regulation – COMAR 26.11.38
Title 26 DEPARTMENT OF THE ENVIRONMENT
Subtitle 11 AIR QUALITY
Chapter 38 Control of NOx Emissions from Coal-Fired Electric Generating Units
Authority: Environmental Article, § 1-404, 2-103 and 2-301—2-303, Annotated Code of Maryland
ALL NEW MATTER
.01 Definitions.
A. In this chapter, the following terms have the meanings indicated.
B. Terms Defined.
(1) "Affected electric generating unit" means any one of the following coal-fired electric
generating units:
(a) Brandon Shores Units 1 and 2;
(b) C.P. Crane Units 1 and 2;
(c) Chalk Point Units 1 and 2;
(d) Dickerson Units 1, 2, and 3;
(e) H.A. Wagner Units 2 and 3;
(f) Morgantown Units 1 and 2; and
(g) Warrior Run.
(2) "Operating day" means a 24-hour period beginning midnight of one day and ending the
following midnight, or an alternative 24-hour period approved by the Department, during which
time an installation is operating, consuming fuel, or causing emissions.
(3) "Ozone season" means the period beginning May 1 of any given year and ending
September 30 of the same year.
(4) System.
(a) "System" means all affected electric generating units within the State of Maryland
subject to this chapter that are owned, operated, or controlled by the same person and are located:
(i) In the same ozone nonattainment area as specified in 40 CFR Part 81; or
(ii) Outside any designated ozone nonattainment area as specified in 40 CFR 81.
(b) A system must include at least two affected electric generating units.
(5) “System operating day” means any day in which an electric generating unit in a system
operates.
(6) “30-day system-wide rolling average emission rate” means a value in lbs/MMBtu
calculated by:
(a) Summing the total pounds of pollutant emitted from the system during the current
system operating day and the previous twenty-nine system operating days;
(b) Summing the total heat input to the system in MMBtu during the current system
operating day and the previous twenty-nine system operating days; and
(c) Dividing the total number of pounds of pollutant emitted during the thirty system
operating days by the total heat input during the thirty system operating days.
(7) “24-hour block average emission rate” means a value in lbs/MMBtu calculated by:
15
(a) Summing the total pounds of pollutant emitted from the unit during 24 hours
between midnight of one day and ending the following midnight;
(b) Summing the total heat input to the unit in MMBtu during 24 hours
between midnight of one day and ending the following midnight; and
(c) Dividing the total number of pounds of pollutant emitted during 24 hours
between midnight of one day and ending the following midnight by the total heat input during 24
hours between midnight of one day and ending the following midnight.
.02 Applicability.
The provisions of this chapter apply to an affected electric generating unit as that term is
defined in §.01B of this chapter.
.03 2015 NOx Emission Control Requirements.
A. Daily NOx Reduction Requirements During the Ozone Season.
(1) Not later than 45 days after the effective date of this regulation, the owner or operator
of an affected electric generating unit shall submit a plan to the Department and EPA for
approval that demonstrates how each affected electric generating unit (the unit) will operate
installed pollution control technology and combustion controls to meet the requirements of §A(2)
of this regulation. The plan shall summarize the data that will be collected to demonstrate
compliance with §A(2) of this regulation. The plan shall cover all modes of operation, including
but not limited to normal operations, start-up, shut-down and low load operations.
(2) Beginning on May 1, 2015, for each operating day during the ozone season, the
owner or operator of an affected electric generating unit shall minimize NOx emissions by
operating and optimizing the use of all installed pollution control technology and combustion
controls consistent with the technological limitations, manufacturers’ specifications, good
engineering and maintenance practices, and good air pollution control practices for minimizing
emissions (as defined in 40 C.F.R. § 60.11(d)) for such equipment and the unit at all times the
unit is in operation while burning any coal.
B. Ozone Season NOx Reduction Requirements.
(1) Except as provided in §B(3) of this regulation, the owner or operator of an affected
electric generating unit shall not exceed a NOx 30-day system-wide rolling average emission rate
of 0.15 lbs/MMBtu during the ozone season.
(2) The owner or operator of an affected electric generating unit subject to the provisions
of this regulation shall continue to meet the ozone season NOx reduction requirements in
COMAR 26.11.27.
(3) Ownership of Single Electric Generating Facility.
(a) An affected electric generating unit is not subject to B(1) if the unit is located at an
electric generating facility that is the only facility in Maryland directly or indirectly owned,
operated or controlled by the owner, operator or controller of the facility.
(b) For the purposes of §B(3) of this regulation, the owner includes parent companies,
affiliates and subsidiaries of the owner.
C. Annual NOx Reduction Requirements. The owner or operator of an affected electric
generating unit subject to the provisions of this regulation shall continue to meet the annual NOx
reduction requirements in COMAR 26.11.27.
D. NOx Emission Requirements for Affected Electric Generating Units Equipped with
Fluidized Bed Combustors.
16
(1) The owner or operator of an affected electric generating unit equipped with a
fluidized bed combustor is not subject to the requirements of §§A, B(1), B(2) and C of this
regulation.
(2) The owner or operator of an affected electric generating unit equipped with a
fluidized bed combustor shall not exceed a NOx 24-hour block average emission rate of 0.10
lbs/MMBtu.
.04 Compliance Demonstration Requirements.
A. Procedures for demonstrating compliance with §.03(A) of this chapter.
(1) An affected electric generating unit shall demonstrate, to the Department’s
satisfaction, compliance with §.03(A)(2) of this chapter, using the information collected and
maintained in accordance with §.03(A)(1) of this chapter and any additional documentation
available to and maintained by the affected electric generating unit.
(2) An affected electric generating unit shall not be required to submit a unit-specific
report consistent with §A(3) of this regulation when the unit emits at levels that are at or below
the following rates:
Affected Unit
24-Hour Block Average
NOx Emissions
in lbs/MMBtu
Brandon Shores
Unit 1
0.08
Unit 2
< 650 MWg
≥ 650 MWg
0.07
0.15
C.P. Crane
Unit 1
0.30
Unit 2
0.28
Chalk Point
Unit 1 only
0.07
Unit 2 only
0.33
Units 1 and 2
combined
0.20
Dickerson
Unit 1 only
0.24
Unit 2 only
0.24
Unit 3 only
0.24
Two or more Units
combined
0.24
H.A. Wagner
17
Unit 2
0.34
Unit 3
0.07
Morgantown
Unit 1
0.07
Unit 2
0.07
(3) The owner or operator of an affected electric generating unit subject to
§.03(A)(2) of this chapter shall submit a unit-specific report for each day the unit exceeds its
NOx emission rate of §A(2) of this regulation, which shall include the following information for
the entire operating day:
(a) Hours of operation for the unit;
(b) Hourly averages of operating temperature of installed pollution control
technology;
(c) Hourly averages of heat input (MMBtu/hr);
(d) Hourly averages of output (MWh);
(e) Hourly averages of Ammonia or urea flow rates;
(f) Hourly averages of NOx emissions data (lbs/MMBtu and tons);
(g) Malfunction data;
(h) The technical and operational reason the rate was exceeded, such as:
(i) Operator error;
(ii) Technical events beyond the control of the owner or operator (e.g. acts of
God, malfunctions); or
(iii) Dispatch requirements that mandate unplanned operation (e.g. start-ups and
shut-downs, idling and operation at low voltage or low load);
(i) A written narrative describing any actions taken to reduce emission rates; and
(j) Other information that the Department determines is necessary to evaluate the
data or to ensure that compliance is achieved.
(4) An exceedance of the emissions rate of §A(2) of this regulation as a result of
factors including but not limited to start-up and shut-down, days when the unit was directed by
the electric grid operator to operate at low load or to operate pursuant to any emergency
generation operations required by the electric grid operator, including necessary testing for such
emergency operations, or to have otherwise occurred during operations which are deemed
consistent with the unit’s technological limitations, manufacturers’ specifications, good
engineering and maintenance practices, and good air pollution control practices for minimizing
emissions, shall not be considered a violation of §.03A(2) of this chapter provided that the
provisions of the approved plan as required in §.03A(1) of this chapter are met.
B. Procedures for demonstrating compliance with NOx emission rates of this chapter.
(1) Compliance with the NOx emission rate limitations in §§.03B(1), .03D(2), and
.04A(2) of this chapter shall be demonstrated with a continuous emission monitoring system that
is installed, operated, and certified in accordance with 40 CFR Part 75.
(2) For §.03B(1) of this chapter, in order to calculate the 30-day system-wide rolling
average emission rates, if twenty-nine system operating days are not available from the current
ozone season, system operating days from the previous ozone season shall be used.
18
.05 Reporting Requirements.
A. Reporting Schedule.
(1) Beginning 30 days after the first month of the ozone season following the effective
date of this chapter, each affected electric generating unit subject to the requirements of this
chapter shall submit a monthly report to the Department detailing the status of compliance with
this chapter during the ozone season.
(2) Each subsequent monthly report shall be submitted to the Department not later than
30 days following the end of the calendar month during the ozone season.
B. Monthly Reports During Ozone Season. Monthly reports during the ozone season shall
include:
(1) Daily pass or fail of the NOx emission rates of §.04A(2) of this chapter.
(2) The reporting information as required under §.04A(3) of this chapter.
(3) The 30-day system-wide rolling average emission rate for each affected electric
generating unit to demonstrate compliance with §.03B(1) of this chapter.
END NEW MATTER
19
III.
The Analyses
In preparation for the development of the required SIPs, the Department performed a number of
technical analyses regarding the level of emissions over time, the level of controls already
installed both in Maryland and surrounding states, and modeling analyses predicting the ozone
levels expected from a controlled level of emissions. These analyses suggested strategies for
Maryland’s attainment SIP and appropriate levels of control for the coal-fired electric generating
sector that would also satisfy the RACT requirements for the 2008 ozone standard, and address
the new proposed ozone standard. The relevant analyses are presented in this chapter with
supporting data included in the Appendices.
A. Peak Day Electricity Generation and High NOx Emissions
The Department has engaged in extensive analysis of NOx emissions data from electric
generating units to determine how well previously installed controls were operating for Maryland
and a number of other states. In many cases, the rate of NOx emissions indicated the controls
were not operating or were not operating optimally. While all of the coal-fired electric generating
units (EGUs or units) in Maryland comply with the HAA, the annual and ozone season caps do
not require all units to consistently run emission controls each day and meet a specified
emissions rate. This is problematic during “peak days” or episodic air quality events when high
temperatures trigger high electricity demand and elevated ozone pollution levels.
NOx emission data analysis indicates that compliance with the HAA annual and ozone season
caps through system-wide averaging has not effectively limited daily NOx emissions during
certain peak days. For economic purposes, companies use systems to minimize operating costs.
In a system, one or more of the highly utilized units will be over-controlled while less well
controlled units operate without using controls. This allows the company to comply with current
regulations but results in higher NOx emissions on days conducive to ozone formation and leads
to higher ozone levels. On these days, optimal use of pollution controls on every unit is needed
to keep ozone levels below the standard.
The proposed regulations have a new 0.15 lb/MMBTU NOx rate averaged on a 30-day rolling
average will take effect for the Raven Power and NRG systems. At the same time, the
requirements to run installed controls at all times and minimize NOx emissions will begin.
B. 2015 NOx Emission Control Requirements - Emission Reduction Estimates
Coal-fired electric generating units in Maryland have accounted for more than 80 percent of the
State’s power plant NOx emissions. The Department projects that the implementation of the
requirements of Regulation .03 will result in an estimated daily NOx emission reduction of 25
percent, or 9 tons/day from the average level of 36 tons/day, provided ownership of the two
existing systems does not change. This projected reduction is based on data from 2011 through
20133. Additional emission reductions should be realized on peak days as the NOx emission rate
optimization requirements from Regulation .03A(2) will ensure improved performance from
units that traditionally have operated only on high electricity demand days and often without
controls. Reducing locally produced NOx on peak days limits ozone production, keeping local
ozone levels lower.
20
3
Calculations for the 2015 NOx Emission Reduction Estimates in the regulation can be found in Appendix G.
As stated earlier, the Baltimore Nonattainment Area is required to prepare a State
Implementation Plan that includes the reduction strategies, modeling analyses and other evidence
demonstrating that these reduction strategies will achieve compliance with the 0.075 ppm ozone
standard in the Baltimore nonattainment area. EPA has selected 2011 as the base year for these
analyses and the Department has performed extensive analyses on data from this year. The 2011
ozone season was a fairly typical summer with 29 ozone exceedance days and the highest 8-hour
ozone average of 114 ppb. The 2013 and 2014 ozone seasons were very mild with 9 and 5
exceedance days, respectively, and the highest 8-hour ozone average of 81 ppb in 2014.
Examples of peak day emissions from Maryland coal-fired units during the summers of 2011 and
2014 are illustrated below.
NOx emissions on peak days in 2011 ranged from 43-62 tons per day. Ozone exceedances were
widespread on each of the illustrated days affecting 12-17 monitors across the state. The
maximum 2011 ozone values occurred on June 8 (114 ppb), June 9 (106 ppb), June 10 (98 ppb),
July 2 (107 ppb) and July 7 (94 ppb).
NOx emissions on peak days in 2014 ranged from 34-44 tons per day. Fewer ozone exceedance
days occurred in 2014. On each of the 2014 illustrated days only one monitor was affected. The
maximum ozone values on June 16, and June 17 were 81 ppb and 80 ppb, respectively.
Figure 3: EGU NOx Emissions (Peak Day) – Summer 2011
EGU NOx Emissions vs Ozone Action Days
16
Brandon #1
14
14
13
13
12
s 10
n
io
s
s
i 8
m
E
x 6
O
N 4
f
o
s
n 2
o
T
Brandon #2
13
12
12
12
10
9
Crane #2
9
9
9
9
Wagner #2
8
6
6
5
5
44
5
4
2
22
4
2
Crane #1
5
4
6
5
5
4
4
22
1
2
22
Wagner #3
6
5
Morgantown #1
3
Morgantown #2
211
1
1
2
1
0
Dickerson 1,2 & 3
Chalk Point 1 & 2
6/8/2011
6/9/2011
6/10/2011
7/2/2011
2011 Highest Ozone Action Days
21
7/7/2011
Figure 4: EGU NOx Emissions (Peak Day) – Summer 2014
EGU NOx Emissions vs Ozone Action Days
16
15
Brandon #1
14
Brandon #2
12
Crane #1
s
n10
o
i
s
si 8
m
E
x 6
O
N 4
f
o
s
n 2
o
T
Crane #2
9
0
Wagner #2
6
5
4
Morgantown #2
3
2 2
0
2 2
0
0
6/16/2014
Wagner #3
Morgantown #1
5
4 4
3
6
6
0
Dickerson 1,2 & 3
Chalk Point 1 & 2
6/17/2014
2014 Highest Ozone Action Days
Historical performance of 24-hour block (daily) NOx emission rates have been reviewed by the Department. (See
Appendix C – 24 Hour Block Rate) The proposed regulation requires compliance demonstrations for the 24-hour
block indicator rates as detailed under Chapter IV of this document.
Comparison of NOx emissions from example exceedance days from a typical summer, 2011, and
a much milder summer, 2014, illustrates the difference in NOx contributions from units equipped
with SCR controls and units equipped with SNCRs. The Brandon Shores units and Morgantown
units are all equipped with SCR. Wagner Unit 3 and Chalk Point Unit 1 also have SCR controls.
The other units all have SNCR controls. In the 2011 examples, all units are operating to meet
higher electricity demand. The units with the highest emissions are almost always the units
equipped with SNCR. On average, units equipped with SNCR produce half the total emissions
for peak days. Yet these units are smaller and produce only half as much electricity as those
equipped with SCR. In the examples from 2014, one Crane unit and one Wagner unit did not run.
Emissions from SNCR controlled units still contributed over 40% of the total NOx emissions.
Even though collectively the total NOx emissions from units with SCRs are similar to the total
NOx emissions from units with SNCRs, the generating capacity of the units with SNCR is only
one third the generating capacity of the units with SCR. So on high ozone days, less wellcontrolled units double local NOx emissions. During milder episodes, the less well-controlled
units contribute about 40% more NOx emissions.
During both ozone seasons, the ozone season average NOx rate for the individual units are very
close to the indicator rates established for the units in Regulation .05. Peak day NOx rates can be
very different. The NOx minimization requirements will stabilize the rates and reduce emissions
on peak days.
C. Modeling
The Department participates in regional and local modeling efforts to design and evaluate the
impacts of various policy and technology options4. The Department collaborates with University
of Maryland researchers and the Ozone Transport Commission Modeling Committee to prepare
22
screening scenarios for various NOx emission reduction strategies that can be employed in the
future. Some preliminary modeling analyses have been completed with existing inventories. The
final modeling analyses using all the latest inventories and models will be completed and more
fully described in the Attainment SIP. Various emission factors have been assumed for electric
generating units, including the coal-fired units under this regulation, as well as states upwind of
Maryland that contribute to the transport of ozone5.
Comprehensive Air Quality Model with Extensions (CAMx) modeling is used to track the
contribution of specific sources on ozone formation. Preliminary modeling results using CAMx
have shown that local emissions contribute about 30% to the ozone problem in nonattainment
areas in Maryland. These preliminary findings support the need for additional substantive NOx
reductions in Maryland.
Community Multi-Scale Air Quality Modeling System (CMAQ) modeling simulates the
formation and distribution of ozone over the Eastern U.S. The Department performed
preliminary modeling using CMAQ to estimate the impact on air quality of the operation of
existing controls. The preliminary modeling results indicated that the disbenefit of EGUs across
the eastern U.S., including those in Maryland, running without the installed controls was about 12 parts per billion (ppb) ozone. In other words, consistently operating installed controls on coalfired units could reduce ozone levels by approximately 1-2 ppb.
4
5
Appendix E Ozone Transport Commission RACT Statement
Appendix I describes Proposal for a Collaborative Solution to the Ozone Transport Problem
D. The Effectiveness of NOx Reductions
The following is a White Paper Prepared by the Maryland Department of the Environment &
University of Maryland College Park, December 2014
The Effectiveness of NOx Reductions When it Comes to Reducing
Ozone Concentrations
December 2014
This white paper presents observational evidence of the response of ambient ozone (O3) to
nitrogen oxides (NOx) emissions. In the eastern US, natural biogenic sources usually dominate
hydrocarbon reactivity, making NOx the limiting precursor to ozone. NOx emissions from the
two major categories, point sources (mostly EGUs) and mobile sources (motor vehicles), have
decreased dramatically over the past two decades. Surface concentrations of NOx have
decreased correspondingly. Surface ozone concentrations also have decreased, but more
irregularly, due the dependence of ozone formation on meteorology as well as to emissions of
precursors. From the causal relationships of ambient O3, NOx concentrations, and NOx
emissions, we can estimate the increase in ambient ozone concentrations due to not running NOx
controls (i.e., SRCs) during the summer ozone season.
Based on data obtained from the NASA DISCOVER-AQ field campaign over Maryland, it was
observed that there was 4 to 8 ppb O3 produced per ppb NOx consumed, well within the range of
23
1-20 for other observations over the continental US (Jacob, 2004). This means that for each 100
tons/d increase in NOx emissions we can expect ~0.5 to 1.0 ppb increase in ozone [He et al.,
2013a; He et al., 2013b]
Figure 1 indicates that observed ambient ozone and NOx over the Baltimore/Washington area
decreased from 1997-2010 (He et al., 2013). Interannual variability responds to a combination
of emissions and weather – the greater the number of days with a maximum temperature over
90°F the greater the number of days with an ozone exceedances – but the long-term trend is
driven by decreased NOx (and possibly to some degree VOC) emissions. Using estimates for the
three most recent years helps strengthen the statistical significance the long-term decrease in
ozone. NOx concentrations plummeted after 2003, but have shown little decrease since 2010.
In conclusion, the observations verify the predictions from chemical transport models – if NOx
emissions revert to levels seen in previous years, ozone concentrations are likely to rise. Other
factors held constant, every increase of 100 tons NOx per day will potentially lead to
approximately a 1 ppb ozone increase.
Additional UMD research indicates that from the 1970’s thru the early 2000’s Maryland‘s air
quality responded to both VOC and NOx reductions. This has now changed and it can be seen
that since the mid-2000’s that Maryland has transitioned into a NOx limited regime, NOx
reductions now provide a greater benefit in reducing ozone levels in Maryland (Hosley, et al., 18
January 2013).
Figure 1, Trends in trace gas concentrations. Taken from He et al., (2013b), these observations
show the temporal trends and relationship of O3, NOx, and CO. Measurements from 1200-1800
LT in the ozone season are shown. Data for 2011-2013 are estimates added for this report, after
the original publication in ACP. The inter-annual variability, especially for ozone, is subject to
changes in the number of hot days, but ozone and oxides of nitrogen have fallen together over
the long run.
Based on the UMD research presented it can clearly be determined that Maryland has reached a
point where continued NOx reductions will result in greater ozone reductions than has been seen
in the past.
24
References
Jacob, D.J., “Introduction to Atmospheric Chemistry” Princeton Univ. Press, ed. 2004.
http://acmg.seas.harvard.edu/people/faculty/djj/book/
He, H., L. Hembeck, K. M. Hosley, T. P. Canty, R. J. Salawitch, and R. R. Dickerson (2013a),
High ozone concentrations on hot days: The role of electric power demand and NOx
emissions, Geophysical Research Letters, 40(19), 5291-5294.
He, H., et al. (2013b), Trends in emissions and concentrations of air pollutants in the lower
troposphere in the Baltimore/Washington airshed from 1997 to 2011, Atmospheric
Chemistry and Physics, 13(15), 7859-7874.
Hosley, K, T. Canty, H. He, R. Salawitch, et al., Surface Ozone and Emission Trends Power
Point, 18 January 2013.
25
IV.
Regulation Requirement Details for Operating and Compliance
A. Affected Sources
The proposed regulation applies to the following 14 coal-fired electric generating units currently
operating in Maryland, which account for most of the State’s power plant NOx emissions:







Brandon Shores Generating Station (Units 1 and 2);
C.P. Crane Generating Station (Units 1 and 2);
H.A. Wagner Generating Station (Units 2 and 3);
Chalk Point Generating Station (Units 1 and 2);
Morgantown Generating Station (Units 1 and 2);
Dickerson Generating Station (Units 1, 2 and 3); and
Warrior Run Generating Station.
B. NOx Reduction Requirements
The proposed regulation is part of an overall strategy to significantly reduce NOx emissions from
coal fired electric generating units (EGUs) in the State by requiring owners and operators of
affected EGUs to comply with certain requirements and standards in the regulation by specific
dates. These coal-fired electric generating units remain subject to Maryland’s Healthy Air Act as
implemented in COMAR 26.11.27, as well as all applicable federal regulations.
The requirements specified in the regulation include the following: May 1, 2015 and beyond
 NOx Emission Control Technology - Operating Pollution Controls: For each operating day
during the ozone season (beginning May 1, 2015), affected units must minimize NOx
emissions by operating and optimizing the use of all installed pollution control technologies
and combustion controls consistent with the technological limitations, manufacturers’
specifications, good engineering and maintenance practices, and good air pollution control
practices for minimizing emissions (as defined in 40 C.F.R. § 60.11(d)) for such equipment
and the unit at all times the unit is in operation while burning any coal.
This is a stand-alone requirement that will require the owner or operator of a coal-fired
electric generating unit to submit a plan to MDE demonstrating how the unit will operate
installed pollution control technology as required in the regulation. The plan is due no later
than 45 after the effective date of the regulation6.
6

See Appendix H – Compliance Plan.
System-Wide NOx Emission Standard: The regulations will require owners or operators of
two or more units to demonstrate compliance by meeting a system-wide ozone season NOx
emission rate of 0.15 lbs/MMBtu as a 30-day rolling average. The rationale for the NOx
emission rate (0.15 lbs/MMBtu) was based upon data derived from the Clean Air Markets
Division (CAMD) for coal units operating in 2011 – 2013 and upon the findings that no unit
equipped with an SNCR control system in Maryland has demonstrated the ability to achieve
a 0.15 lbs/MMBtu NOx rate. Therefore the 0.15 lbs/MMBtu NOx emission rate limits the
capacity or operation of the SNCR units in the system.
26

Annual and Ozone Season NOx Reductions: The regulations will require that owners or
operators of coal-fired electric generating units continue to meet the ozone season and annual
NOx reduction requirements set forth in COMAR 26.11.27 (Emission Limitations for Power
Plants). Units with fluidized bed combustion technology must meet a NOx emission rate of
0.10 lbs/MMBtu as a 24-hour block average on an annual basis. AES Warrior Run is
currently the only unit that utilizes a fluidized bed combustion boiler which operates at lower
temperatures compared to other coal-fired boiler technology, suppressing NOx formation and
lowering NOx emissions. The plant has operated at or below the 0.10 lbs/MMBtu NOx
emission rate since it commenced operations in 2000.

Compliance Demonstration – Indictor Rates (24-Hour Block Average NOx Emission
Rate): Coal-fired electric generating units are required to submit a plan to MDE for approval
that demonstrates how the unit will operate the pollution and combustion controls. Coal-fired
electric generating units are required to submit a unit-specific report whenever the unit emits
at levels above the following unit-specific 24-Hour Block Average NOx Emission rates:
Table IV-1: Compliance Demonstration - Indicator Rates (24-Hour Block Average NOx
Emission Rate)
24‐Hour Block Average NOx Emission Rate in lbs/MMBtu Affected Coal‐Fired Electric Generating Unit Brandon Shores Unit 1 0.08 Unit 2 < 650 MWg ≥ 650 MWg 0.07 0.15 Rationale For NOx Emission Rates: Brandon Shores Units 1 and 2 are equipped with SCR control technology. The 0.08 lbs/MMBtu NOx rate for Brandon Shores Unit 1 was developed with consideration given to the technological limitation that exists with the ESP being upstream of the SCR, making it more challenging for the SCR to reach reaction temperature. Brandon Shores Unit 2 has simulated over fire air
technology and side wall burners. The 0.07 lbs/MMBtu NOx rate was based upon a comprehensive review
of literature on SCR installations and represents emission rates associated with state‐of‐the‐art SCR technology at coal units in 2013. Operation of the Brandon Shores Unit 2 boiler above 650 MWg produce
NOx at a higher rate. Considering limitations of the Unit 2 SCR reagent injection system, the NOx rate for this operating range was increased to 0.15 lbs/MMBtu.
C.P. Crane Unit 1 0.30 Unit 2 0.28
Rationale For NOx Emission Rates: C.P. Crane Units 1 and 2 are equipped with SNCR control technology. 27
The 0.30 and 0.28 lbs/MMBtu NOx rates were calculated using CEMS data from CAMD (2010, 2011, and 2012) and applying a 35% control efficiency to the 80th percentile of the NOx rates for the given years. These limits were supported by 2014 Summer Study Data.
Chalk Point Unit 1 only 0.07 Unit 2 only 0.33 Units 1 and 2 combined 0.20 Rationale for NOx Emission Rates: Chalk Point Units 1 and 2 share a common stack. Unit 1 is equipped with an SCR, with the rate set to SCR achievable rate. Unit 2 is equipped with an SACR. The 0.07 lbs/MMBtu NOx rate for Unit 1 is based upon a comprehensive review of literature on SCR installations and represents emission rates associated with state‐of‐the‐art SCR technology at coal units in 2013. The 0.33 lbs/MMBtu NOx rate for Unit 2 is based 2014 Summer Study data. The 0.20 lbs/MMBtu NOx rate for Units 1 and 2 combined was calculated by averaging the NOx emission rates of units 1 and 2. Dickerson Unit 1 only 0.24 Unit 2 only 0.24 Unit 3 only 0.24 Two or more Units combined 0.24 Rationale for NOx Emission Rates: Dickerson Units 1, 2, and 3 share a common stack. All three units are equipped with SNCR control technology. The 0.24 lbs/MMBtu NOx rates were based on 2014 Summer Study data.
H.A. Wagner Unit 2 0.34 Unit 3 0.07
Rationale for NOx Emission Rates: H. A. Wagner Unit 2 is equipped with SNCR control technology. The 0.34 lbs/MMBtu NOx rate for Unit 2 was based on 2014 Summer Study data. H. A. Wagner Unit 3 is equipped with SCR control technology. The 0.07 lbs/MMBtu NOx rate for Unit 3 is based upon a comprehensive review of literature on SCR installations and represents emission rates associated with state‐of‐the‐art SCR technology at coal units in 2013.
Morgantown 0.07 Unit 1 28
Unit 2 0.07
Rationale for NOx Emission Rates: The 0.07 lbs/MMBtu NOx rate for Units 1 and 2 is based upon a comprehensive review of literature on SCR installations and represents emission rates associated with state‐of‐the‐art SCR technology at coal units from 2013.

Unit-Specific Reporting: The regulations include a requirement for coal-fired electric
generating units to submit a report to MDE for each day that exceeds the unit-specific 24hour block average NOx emission rates in Table IV-1. Each unit specific report submitted to
MDE should include the hours of operation, the operating temperature of the control unit, the
heat input, the MW output, reagent (ammonia or urea) flow rates, NOx emission data,
malfunction data, reason for the exceedance, and a description of steps or actions taken to
return to compliance. MDE may also request additional information regarding any
exceedance of the unit-specific 24-hour block rate that it determines is necessary to evaluate
the data or ensure compliance is achieved.

Reporting Requirements: The regulation includes specific monthly reporting requirements
for owners and operators of coal-fired electric generating units to demonstrate compliance
with the requirements of the regulation.
29
V.
Economic Analysis
A. Summary of Compliance Cost Estimates
A review of factors affecting the cost of compliance is presented in this section. The new
regulation provides flexibility for affected sources. An analysis of the 2015 NOx requirements is
discussed below.
2015 NOx Emission Control Requirements (May 1, 2015).
As a result of prior regulations such as the Healthy Air Act (HAA), all of the coal-fired
generating units in the State are equipped with NOx pollution control technology – such as
SCR, SNCR, and SACR. Compliance with the 2015 NOx emission control requirements
will require all coal-fired electric generating units to operate and optimize both NOx
pollution and combustion controls during the ozone season to minimize NOx emissions.
MDE estimates that the annual cost of operating and optimizing NOx pollution controls
ranges from $430,000 to $4.3 million (2014 dollars) on a per unit basis.
B. Assumptions.
There are no new control technologies required for this action. Companies must optimize their
existing control equipment to meet the 2015 requirements. The annual operating and
maintenance cost for a single unit can range from $430,000 to $4.3 million. Optimization of the
operation of the existing controls may push annual operating and maintenance costs toward the
high end of the estimates or even add some additional costs but the exact additional cost if any
cannot be determined at this time.
30
VI.
Background Information – Ozone Pollution
A. Background
Ground-level ozone is formed when a mixture of common air pollutants react in heat and strong
sunlight. The main ozone-causing pollutants are nitrogen oxides (NOx) from fuel burning sources
like power plants and automobiles and volatile organic compounds (VOCs) from sources such as
gasoline, paints, inks and solvents. These two categories of pollutants are also referred to as
ozone precursors. The formation of ozone is dependent on weather conditions such as
temperature, the amount of sunlight, and wind direction and speed. Because sunlight and high
temperatures function as catalysts to form ozone, the problem is seasonal, with the ozone season
lasting from May through September in the Baltimore and Washington Region. Typically, ozone
levels escalate rapidly around noontime, peak in the afternoon and decline when the sun sets.
B. Effects of Ground Level Ozone
Exposure to ozone has been linked to a number of health effects, including significant decreases
in lung function, inflammation of the airways, and increased respiratory symptoms, such as
coughing and pain when taking a deep breath. Exposure can also aggravate lung diseases such as
asthma, leading to increased medication use and increased hospital admissions and emergency
room visits. Active children are the group at highest risk from ozone exposure because they often
spend a large part of the summer playing outdoors. Children are also more likely to have asthma,
which may be aggravated by ozone exposure. Other at-risk groups include adults who are active
outdoors (e.g., some outdoor workers) and individuals with lung diseases such as asthma and
chronic obstructive pulmonary disease. In addition, long-term exposure to moderate levels of
ozone may cause permanent changes in lung structure, leading to premature aging of the lungs
and worsening of chronic lung disease.
Ozone also affects vegetation and ecosystems, leading to reductions in agricultural crop and
commercial forest yields, reduced growth and survivability of tree seedlings, and increased plant
susceptibility to disease, pests, and other environmental stresses (e.g., harsh weather). In longlived species, these effects may become evident only after several years or even decades of
exposure and may result in long-term effects on forest ecosystems. Ground level ozone injury to
trees and plants can lead to a decrease in the natural beauty of our national parks and recreation
areas.
References
http://www.epa.gov/airtrends/ozone.html
31
VII.
Overview of Relevant Federal, Regional and State Standards and
Regulations
A. National Ambient Air Quality Standards (NAAQS)
NAAQS are public health and environment-based standards established by the U.S. EPA under
the CAA, developed to protect the public health from the impacts associated with various forms
of air pollution.
The CAA identifies two types of national ambient air quality standards. Primary standards
provide public health protection, including protecting the health of "sensitive" populations such
as asthmatics, children, and the elderly. Secondary standards provide public welfare protection,
including protection against decreased visibility and damage to animals, crops, vegetation, and
buildings. The Clean Air Act Amendments of 1990 (CAAA) established a process for evaluating
air quality in each region and identifying and classifying nonattainment areas according to the
severity of their air pollution problem.
In 1997, the U.S. EPA replaced the 1-hour ozone standard with an 8-hour standard of 0.08 ppm*.
This revision was developed to take into consideration the long term exposure health effects of
ozone versus the acute effects of ozone. The process of determining attainment status under the
8-hour standard was also changed. So an area would be in attainment with the 8-hour standard
when the average of the annual 4th-highest daily maximum 8-hour ozone concentration averaged
over three years is less than 0.08 ppm. In 2008, the U.S. EPA finalized a revision of the 8-hour
ozone standard which set the 8-hour ozone standard at 0.075 ppm and kept the methodology for
calculating exceedances of the 2008 ozone standard the same as the 1997 ozone standard.
*The Clean Air Act (CAA) requires the U.S. EPA to review the standards once every five years to
determine whether revisions to the standards are appropriate.
Table VII-1: Ozone NAAQS from 1971 to Present
Final
Rule/Decision
1971
36 FR 8186
Apr 30, 1971
Primary/
Secondary
Indicator
Averaging
Time
Level
(ppm)
Form
Primary and
Secondary
Total
photochemical
oxidants
1-hour
0.08 ppm
Not to be exceeded
more than one hour per
year
0.12 ppm
Attainment is defined
when the expected
number of days per
calendar year, with
maximum hourly
average concentration
greater than 0.12 ppm,
is equal to or less than 1
1979
44 FR 8202
Feb 8, 1979
Primary and
Secondary
O3
1-hour
1993
58 FR 13008
Mar 9, 1993
EPA decided that revisions to the standards were not warranted at the time
32
1997
62 FR 38856
Jul 18, 1997
2008
73 FR 16483
Mar 27, 2008
Primary and
Secondary
O3
8-hour
0.08 ppm
Primary and
Secondary
O3
8-hour
0.075 ppm
Annual fourth-highest
daily maximum 8-hr
concentration, averaged
over 3 years
Annual fourth-highest
daily maximum 8-hr
concentration, averaged
over 3 years
B. NOx SIP Call
In 1998, the U.S. EPA finalized a federal rule called the NOx SIP Call to reduce ozone transport
in the Eastern United States. The regulation required 22 states and the District of Columbia to
submit a state implementation plan (SIP) that addresses the regional transport of ground-level
ozone. States that were subject to the regulation (Fig. 1) included Alabama, Connecticut,
Delaware, Georgia, Illinois, Indiana, Kentucky, Massachusetts, Maryland, Michigan, Missouri,
North Carolina, New Jersey, New York, Ohio, Pennsylvania, Rhode Island, South Carolina,
Tennessee, Virginia, Wisconsin, and West Virginia in addition to the District of Columbia.
The regulation was designed to reduce regional NOx 28 percent from 1996 emissions levels by
2007. States subject to the rule were provided the option of either developing their own SIPs to
reduce NOx (and other precursors) or adopting EPA’s model program in the form of a Federal
Implementation Plans (FIPs).
Maryland submitted revisions to the SIP to comply with this rule in 2000. The revisions to the
SIP required adoption of two new chapters – COMAR 26.11.29 and 26.11.30 — relating to the
NOx Budget and Trading Program for stationary sources and for the State regulators. Maryland’s
budget program was based on the U.S. EPA’s model NOx Budget program, codified at 40 CFR
Part 96. The Maryland NOx Budget program establishes requirements for electric generating
units (EGUs) and non-EGU combustion sources (i.e., industrial boilers greater than 250
MMBtu/hr rated capacity). The initial Maryland program specified ozone season allowance
allocations for the years 2003 through 2007 for EGUs; Maryland subsequently revised the SIP to
include allocations for 2008 and 2009. Maryland EGUs received allocations of allowances that
were far lower than their emissions at that time. Affected sources could control or buy
allowances from those sources that over-controlled throughout the region. The U.S. EPA
approved Maryland’s SIP to comply with Phase I of the NOx SIP Call and published it in the
Federal Register on January 10, 2001. Subsequently, in November 2006, the U.S. EPA approved
a revision to the Maryland SIP to include allocations for the year 2008. Allocations for the years
2009 through 2014 were made as a part of the State’s plan to comply with the federal CAIR.
33
Fig. 5: States Covered Under the NOx SIP Call Region
Source: U.S. EPA - http://www.epa.gov/airmarkt/progsregs/nox/sip.html
C. Clean Air Interstate Rule (CAIR)
In 2005, the U.S. EPA issued CAIR, which caps emissions of SO2 and NOx in the eastern United
States. The rule which replaced the NOx SIP Call, assigns each state an emissions budget and
requires states to achieve certain emissions reductions to meet those budgets by using one of two
compliance options. The first option is to have the state meet its emissions budget by requiring
power plants to participate in an EPA administered interstate cap-and-trade program that caps
emissions in two stages. The second option is to have states meet its budget through measures
chosen by the states. CAIR sets emissions budgets for 27 eastern states and the District of
Columbia. CAIR was later vacated by the U.S. Court of Appeals in 2008. Maryland opted to
implemented the HAA in addition to CAIR, but the HAA did not allow Maryland sources to
meet their emission limitations by purchasing allowances.
34
Fig. 6: States Covered Under the Clean Air Interstate Rule (CAIR)
Source: US. EPA - http://www.epa.gov/cair/where.html
D. Maryland Healthy Air Act (HAA)
In 2006, the Maryland legislature passed the HAA, which was developed with the purpose of
bringing Maryland into attainment with the NAAQS for ozone and fine particulate matter by the
federal deadline of 2010. The act, which was widely applauded by the environmental
community, was signed into law on April 6, 2006 and established new emission limitations for
oxides of nitrogen (NOx), sulfur dioxide (SO2), and mercury (Hg) on Maryland’s largest coalfired power plants. The HAA was the most significant control program ever implemented in
Maryland.
The HAA was designed to make significant reductions in NOx emissions through the application
of mass limitations or caps on the affected coal-fired units. In addition, the HAA required that
Maryland become involved in the Regional Greenhouse Gas Initiative (RGGI) which is aimed at
reducing greenhouse gas emissions. The environmental community, electric companies,
Maryland Public Service Commission, and the Maryland Department of Natural Resources
35
(DNR) among others worked with MDE as partners to design and implement the law, which led
to almost $2.6 billion investment for clean air by Maryland power plants. This investment
included the installation of pollution controls on coal-fired electric generating units such as flue
gas desulfurizers (FGDs), baghouses, hydrated limestone injection systems, SCRS, SNCRs, and
powdered activation carbon (PAC) injection systems – within a 2-3 year window.
The requirements of the HAA were adopted as a state regulation on July 7, 2007 and codified as
COMAR 26.11.27 – Emission Limitations for Power Plants in cooperation with the owners and
operators of the State’s largest coal-fired power plants, requiring NOx reductions by May 2009
(less than 2 years) and SO2 and Hg reductions by January 2010 (less than 2½ years). The
regulation used ozone-season and annual emission caps (Fig. 7) to drive very significant
emission reductions of multiple pollutants such as NOx (by more than 75 percent) - with all
regulatory deadlines being met. See Appendix A for 2007 HAA Notice of Proposed Action.
Fig 7: Annual NOx Emissions for Coal-Fired Units under the Healthy Air Act*
* The grey dotted line represents the cap for the Healthy Air Act - 21,190 tons beginning in 2009 and 17,714 tons
beginning in 2012. The cap includes the R. Paul Smith Power Station, which was decommissioned in 2012. Source:
Maryland Department of the Environment.
References
National Ambient Air Quality Standards (NAAQS), http://www.epa.gov/air/criteria.html
Clean Air Act, http://www.epa.gov/air/caa
36
U.S EPA Acid Rain Program, http://www.epa.gov/airmarkets/progsregs/arp/basic.html
Overview of the Ozone Transport Commission (OTC) NOx Budget Program,
http://www.epa.gov/airmarkt/progsregs/nox/otc-overview.html
NOx Budget Trading Program/ NOx SIP Call, 2003-2008,
http://www.epa.gov/airmarkt/progsregs/nox/sip.html
Clean Air Interstate Rule (CAIR), http://www.epa.gov/cleanairinterstaterule
The Maryland Healthy Air Act,
http://www.mde.md.gov/programs/Air/ProgramsHome/Pages/air/md_haa.aspx
37
VIII. Maryland Electric Generating Units
A. Coal-Fired Electric Generating Units Located In Maryland
An estimated two-thirds of in-state power is generated by electric generating units that are more
than 30 years old and are approaching retirement. These electric generating units are often
costlier to maintain, less efficient, and less environmentally friendly. The proposed regulation
impacts the following coal-burning electric generating units in Maryland, which account for over
50 percent of the State’s power plant NOx emissions.
Table VIII-1: Coal-Fired Electric Generating Units Located In Maryland
ELECTRIC GENERATING UNIT
LOCATION
Raven Power
Brandon Shores Generating Station 1 & 2
Anne Arundel County
H.A. Wagner Generating Station 2 & 3
Anne Arundel County
Charles P. Crane Generating Station 1 & 2
Baltimore County
NRG
Chalk Point Generating Station 1 & 2
Prince George’s County
Dickerson Generating Station 1, 2, & 3
Montgomery County
Morgantown Generating Station 1 & 2
Charles County
AES
Warrior Run Generating Station
Alleghany County
Table VIII-2: Age of Certain Coal-Fired Electric Generating Units
Facility
Commenced Operations
(Age of Unit)
H.A. Wagner*
Unit 2: 1959 (55 yrs old)
Unit 3: 1966 (48 yrs old)
Charles P. Crane* Unit 1: 1961 (53 yrs old)
Unit 2: 1963 (51 yrs old)
Chalk Point †
Unit 2: 1965 (49 yrs old)
Dickerson†
Unit 1: 1959 (55 yrs old)
Unit 2: 1960 (54 yrs old)
Unit 3: 1962 (52 yrs old)
* Facilities operated by Raven Power
† Facilities operated by NRG
38
B. Brandon Shores Generating Station:
Plant profile: The Brandon Shores Generating Station is located in Northern Anne Arundel
County, MD on a site adjacent to the Patapsco River. The facility which is operated by Raven
Power and part of the Fort Smallwood Complex (which includes the H.A. Wagner Generating
Station) is comprised of two 680 MW Babcock & Wilcox wall fired units with circular wall
burners: Unit 1 which began operations in 1984 and, Unit 2 which began operations in 1991.
Coal is received by barge, which is unloaded and transferred by a mile-long conveyor to onsite
coal storage piles. Coal is fed from the coal pile to the plant storage bunkers via conveyor belts,
after which the coal is pulverized and blown into the furnace.
Miscellaneous: Both units (Unit 1 and Unit 2) were designed to deliver steam to the turbine at 2400
psi and 1000 F at a flow of 4,425,000 lbs/hr.
NOx air pollution controls installed: Selective Catalytic Reduction (SCR) pollution control
systems utilizing SmartProcess SCR Optimization Technology were installed on both units
(Units 1 and 2) in 2002 at an estimated cost of approximately $100M. Both Units 1 and 2 are
equipped with hot-side electrostatic precipitators (ESPs). The hot-side ESP is upstream of the
SCR and has a cooling effect on the flue gas entering the SCR. This results in higher NOx
emission rates at low load, when the cooling effect has a higher impact on the temperature of the
gas entering the SCR. The SCR needs to reach a temperature close to 585°F to function
efficiently.
Total Coal Capacity: 1,360 MW
39
C. H.A. Wagner Generating Station:
Plant profile: The H.A. Wagner Generating Station is located in Northern Anne Arundel
County, MD on a site adjacent to the Patapsco River. The facility which is operated by Raven
Power and part of the Fort Smallwood Complex (which includes the Brandon Shores Generating
Station) consists of two coal burning Babcock & Wilcox units. Unit 2 is a coal-fired unit,
nominally rated at 136 MW, which began operations in 1959. Unit 3 is a coal-fired unit,
nominally rated at 359 MW, which began operating in 1966. Coal is received by barge, which is
unloaded and transferred by a mile-long conveyor to onsite coal storage piles. Coal is fed from
the coal pile to the plant storage bunkers via conveyor belts, after which the coal is pulverized
and blown into the furnace.
Miscellaneous: Unit 2 is a Babcock & Wilcox dry bottom wall-fired boiler burning pulverized coal
through 16 circular coal burners. The unit was designed to deliver steam to the turbine at 1800 psi
and 1000 °F at a flow of 950,000 lbs/hr. Unit 3 is a Babcock & Wilcox supercritical, once through,
cell burner boiler firing pulverized coal in 36 cell type coal burners in a three cell design. The unit
was designed to deliver steam to the turbine at 3500 psi and 1050°F at a flow of 2,133,000 lbs/hr.
NOx air pollution controls installed: Low NOx burners are installed on both units. Unit 3
currently has an SCR (installed in 2003) for the control of NOx emissions during the ozone
season while Unit 2 utilizes a selective non-catalytic reduction system for the same purpose.
Total Coal Capacity: 495 MW
40
D. Charles P. Crane Generating Station:
Plant profile: The Charles P. Crane Generating Station is located in Bowleys Quarters, MD
(Baltimore County) on the Middle River Neck Peninsula. The facility which is operated by
Raven Power is comprised of two coal burning Babcock and Wilcox cyclone units: Unit 1, which
is rated at 190 MW and began operations in 1961; and Unit 2, which is rated at 209 MW and
began operations in 1963. Coal is supplied to the plant via dedicated rail and is stored adjacent to
the plant. The coal is prepared for use by four crushers (per boiler) and is gravity-fed into the
combustion chamber via mechanical conveyor.
Miscellaneous: Both Units 1 and 2 are fired by four cyclone burners with two cyclones located
on the front and two located directly opposite on the rear side of the boiler (opposite fired).
NOx air pollution controls installed: Both units are equipped with overfire air and selective noncatalytic reduction (SNCR) in the form of urea injection to control NOx emissions, which was
completed in 2009.
Total Coal Capacity: 399 MW
41
E. Morgantown Generating Station:
Plant profile: The Morgantown Generating Station is located in Newburg, MD (Charles County)
on a site adjacent to the Potomac River. The facility which is owned and operated by NRG
Energy is comprised of two 640 MW coal-fired T-fired units designed and manufactured by
Combustion Engineering Inc. The two coal-fired units (Units 1 and 2) are base-loaded
supercritical, combined circulation, tangentially-fired, twin furnace, balanced draft steam
generators which went into operation in 1970 and 1971. Coal is currently delivered to
Morgantown by CSX Transportation Corporation (CSXT) unit trains.
Miscellaneous: Each boiler has a steam flow rated at 4,250,000 lbs/hr and a pressure of 3500 psig.
The rated steam flow has main and reheat steam temperatures of approximately 1000F. There are
five levels of coal burners and igniters at each of the eight corners for a total of forty burners and
igniters per unit. In addition to the coal burners, there are four elevations of load-carrying oil
burners or thirty two total per unit.
NOx air pollution controls installed: The coal-fired units were retrofitted in the mid-1990s with
low-NOx burners (Low NOx Concentric Firing System II in 1994) and an updated distributed
control system (DCS). Both units are equipped with SCR pollution control systems to control
NOx emissions.
Total Coal Capacity: 1,280 MW
42
F. Chalk Point Generating Station:
Plant profile: The Chalk Point Generating Station is located in Eagle Harbor, MD (Prince
Georges County) on a site adjacent to the Patuxent River. The facility which is owned and
operated by NRG Energy is comprised of Units 1 and 2, which are coal-fired dry-bottom, wallfired steam generating boilers rated at 364 MW each. The units were put into service in 1964
(Unit 1) and 1965 (Unit 2). Coal is delivered to the Chalk Point generating station by CSX
Transportation trains via the Herbert Subdivision, a former Pennsylvania Railroad (PRR) line.
Miscellaneous:
Boiler emissions from Units 1 and 2 exit through a combined single 729-foot stack.
NOx air pollution controls installed: A SCR control system on was installed on Unit 1 in 2008
and a Selective Auto Catalytic Reduction (SACR) control system was installed on Unit 2 in
2006.
Total Coal Capacity: 728 MW
*On December 2, 2013, PJM received a request to deactivate the coal-fired units by May, 2017.
43
G. Dickerson Generating Station:
Plant profile: The Dickerson Generating Station is located in Montgomery County, MD (near
Dickerson, MD) on a site adjacent to the Potomac River. The facility which is owned and
operated by NRG Energy has three coal-fired 190-MW units (Units 1, 2 and 3) that were
constructed in 1959, 1960, and 1962. Each boiler is tangentially fired, with a superheater, reheat
and economizer. The primary fuel for these boilers is coal with No.2 fuel oil used for ignition
warm-up and flame stabilization purposes. All boiler emissions are directed to the common 700foot stack during normal operations. Coal is delivered to the Dickerson Generating Station by
CSX Transportation train.
Miscellaneous: Each boiler has four levels of burners with eight burners on each level for a total
of 32 burners per boiler. Gases exiting the pollution control devices are collected in a common
duct that exits through a 600 ft high common stack. When the common stack is out of service
Units 1 and 2 use a common bypass stack while Unit 3 has its own bypass stack.
NOx air pollution controls installed: Low-NOx burners and separated overfire air (SOFA) have
been installed on Units 1, 2, and 3 to reduce emissions of nitrogen oxides (NOx). In addition,
SNCR control systems were installed on Units 1, 2, and 3 in 2009.
Total Coal Capacity: 570 MW
*On December 2, 2013, PJM received a request to deactivate the coal-fired units by May, 2017.
44
H. Warrior Run Generating Station:
Plant profile: Warrior Run Generating Station is an electric cogeneration plant located Alleghany
County, MD just south of Cumberland, MD. The facility which is owned by AES Corporation
and commenced operations in 2000 is comprised of a 180 MW coal-fired circulating fluidized
bed (CFB) boiler manufactured by ABB Combustion Engineering and a 150 ton per day food
grade carbon dioxide production plant. The unit uses coal from nearby mines in Maryland and
diesel oil as a backup and startup fuel.
NOx air pollution controls installed: The plant features a type of boiler which is inherently wellcontrolled and low emitting design of fluidized bed boiler. The injection of ammonia and a
selective non-catalytic reduction system are also used to remove nitrogen oxides.
Total Coal Capacity: 180 MW
I. NOx Emissions Control Equipment on Affected Electric Generating Units
Nitrogen oxides (NOx) are an acid rain precursor and a contributor to the formation of groundlevel ozone, which is a major component of smog. In 2008, power plants accounted for 18
percent of the national NOx emissions inventory (see Pg. 14 of NESCAUM report cited below).
Most of the NOx formed during the combustion process is the result of two oxidation
mechanisms: (1) reaction of nitrogen in the combustion air with excess oxygen at elevated
temperatures, referred to as thermal NOx; and (2) oxidation of nitrogen that is chemically bound
in the coal, referred to as fuel NOx. Controlling NOx emissions is achieved by controlling the
formation of NOx through combustion controls or by reducing NOx after it has formed through
post-combustion controls. The number of installations of post-combustion NOx controls such as
Selective Catalytic Reduction (SCR) and Selective Non-Catalytic Reduction (SNCR) systems
increased between the periods of 1999 to 2009. This increase was largely driven by federal and
state regulations. The following table summarizes the NOx control equipment installed on coalfired electric generating units in Maryland:
45
Table VIII-3: Summary of NOx Control Equipment Installed on Coal-Fired EGU’s in Maryland
Facility
Raven Power
Brandon Shores
Commenced
Operations
Rated
Capacity
(MW)
Unit 1: 1984
Unit 2: 1991
Unit 1: 680
Unit 2: 680
H.A. Wagner
Unit 2: 1959
Unit 3: 1966
Unit 2: 136
Unit 3: 359
Charles P. Crane
Unit 1: 1961
Unit 2: 1963
Unit 1: 190
Unit 2: 209
Unit 1: 1964
Unit 2: 1965
Unit 1: 364
Unit 2: 364
Unit 1: 1959
Unit 2: 1960
Unit 3: 1962
Unit 1: 1970
Unit 2: 1971
Unit 1: 190
Unit 2: 190
Unit 3: 190
Unit 1: 640
Unit 2: 640
2000
180
NRG
Chalk Point
Dickerson
Morgantown
AES
Warrior Run
Existing NOx Controls
Both units equipped with Selective
Catalytic Reduction (SCR) utilizing
SmartProcess SCR Optimization
Technology.
Both units equipped with low NOx
burners installed on both units; Unit 3
equipped with SCR; Unit 2 equipped
with Selective Non-Catalytic Reduction
(SNCR).
Both units equipped with overfire air and
SNCR.
Unit 1 equipped with SCR; Unit 2
equipped with Selective Auto Catalytic
Reduction (SACR) pollution control
technology.
All units equipped with low-NOx burners,
separated overfire air (SOFA), and SNCR
pollution control technology.
Both units equipped with low-NOx
burners and Selective Catalytic
Reduction (SCR)
Unit features state-of-the-art fluidized
bed boiler with low emissions; equipped
with SNCR.
References
“NOx SIP Call Rule ― Impacts on Maryland and Surrounding States”, January 2009. Maryland Power
Plant Research Program.
“Control Technologies to Reduce Conventional and Hazardous Air Pollutants from Coal-Fired Power
Plants”, March 31, 2011. NESCAUM.
46
IX.
Overview of NOx Control Technologies for Coal-Fired Electric
Generating Units
Combustion control is the initial method utilized for reducing NOx emissions from boilers
burning coal, oil, or natural gas. These control systems include low-NOx burners and dry lowNOx combustors, with the technology selected for a particular plant dependent on the required
NOx emissions limits and the specific fuel to be fired. To achieve greater NOx emission
reductions from fossil-fueled boilers, post combustion control technologies such as selective
catalytic reduction (SCR) systems, selective non-catalytic reduction (SNCR) systems and
selective autocatalytic reduction (SACR) systems are installed at coal-fired power plants. The
following provides an overview of the various post combustion control technologies.
A. Selective Catalytic Reduction (SCR) Technology
Overview: Selective catalytic reduction (SCR) is a process for controlling emissions of nitrogen
oxides from stationary sources. The basic principle behind the technology is the reduction of
NOx to nitrogen (N2) and water (H2O) by the reaction of NOx and a reagent such as ammonia
(NH3) (or urea) within a catalyst reactor or chamber at operating temperatures ranging from 450800°F. The stoichiometric reaction using either anhydrous or aqueous ammonia for a selective
catalytic reduction process is:
4 NO + 4 NH3 + O24 N2 + 6 H2O
2 NO2 + 4 NH3 + O23 N2 + 6 H2O
NO + NO2 + 2 NH3→ 2 N2 + 3 H2O
Fig 8: Illustration of the SCR Process
While the stoichiometric reaction for the use of urea instead of either anhydrous or aqueous
ammonia is:
4NO + 2(NH2)2CO + O2 → 4N2 + 4H2O + 2CO2
The technology, which was developed and patented by Engelhard Corporation in 1959, is used as
a post-combustion system on utility and industrial boilers, gas turbines, process heaters, internal
47
combustion engines, chemical plants, and steel mills worldwide - capable of NOx removal
efficiencies between 75- 90 percent. The largest application of SCR technology is on coal-fired
power plants with more than 300 coal-fired power plants having installed the technology over the
last 15 years.The U.S. EPA estimates that between 2001 and 2005, the electric generation
industry installed more than 96 GW (gigawatts) of SCR systems in response to the NOx SIP Call.
Coal-fired power plant operators installed an additional 20 GW of SCR systems from 2008
through 2010 in response to the Clean Air Interstate Rule (CAIR).
Table IX-1: Summary of Emission Control Technology Retrofit Options in EPA Base Case
v4.10
Control Performance Options Unit Type Percent Removal Size Applicability Selective Catalytic Reduction (SCR) Coal 90% down to 0.06 lb/MMBtu Oil/Gas
Units ≥ 25MW Units ≥ 25MW 80% Selective Non‐Catalytic Reduction (SNCR) Coal Pulverized Coal: 35% Fluidized Bed: 50% Units ≥ 25MW Source: U.S. EPA IPM Base Case v.4.10 - http://www.epa.gov/airmarkets/progsregs/epaipm/docs/v410/Chapter5.pdf
The catalyst reactor or chamber is installed at a point where the temperature is in the range of
about 600°F-700°F, normally placing it after the economizer and before the air-preheater of the
boiler. Multiple layers of catalysts are generally used to increase the reaction surface and the
catalyst is typically replaced every two to three years.
Advantages of Selective Catalytic Reduction (SCR) NOx Pollution Control Technology:
 Higher NOx reductions than other post-combustion NOx pollution control technologies
 Applicable to sources with low NOx concentrations
 Reactions occur at a lower and broader temperature range than selective non-catalytic
reduction (SNCR).
 Does not require modifications to the combustion unit.
Disadvantages of Selective Catalytic Reduction (SCR) NOx Pollution Control Technology:
 Significantly higher capital and operating costs than post-combustion NOx pollution
control technologies.
 Specific temperatures are required for selective catalytic reduction technology to function
efficiently. Because of this, SCR does not operate at all times while electric generating
units are in operation.
 Retrofitting certain industrial boilers with SCR may prove to be difficult and costly.
 Large volume of reagent and catalyst required.
 Selective catalytic reduction systems may require downstream equipment cleaning.
 May result in ammonia in the waste gas stream.
48
B. Selective Non-Catalytic Reduction (SNCR) Technology
Overview: Selective non-catalytic reduction (SNCR) is a chemical process for removing
nitrogen oxides (NOx) from flue gas. The process involves a reagent, typically urea or ammonia,
which is injected into the hot flue gas – reacting with the NOx, converting it to nitrogen gas and
water vapor. Unlike selective catalytic reduction, no catalyst is required for this process. Instead,
it is driven by the high temperatures, typically ranging from 1400 - 2100F. SNCR performance
depends on factors specific to each source, including flue gas temperature, available residence
time for the reagent and flue gas to mix and react, amount of reagent injected, reagent
distribution, uncontrolled NOx level, and CO and O2 concentrations. Coal-fired electric
generating units in Maryland that are equipped with SNCR have experienced NOx emissions
reductions around 30 percent.
Fig. 9: Reaction Mechanism for the SNCR Process
Fig. 10: Illustration of the SNCR Process
Advantages of Selective Non-Catalytic Reduction (SNCR) NOx Pollution Control
Technology:
 Capital and operating costs are among the lowest of all NOx pollution control methods.
 Retrofitting units for SNCR is relatively simple and requires little downtime for large
and medium size units.
 Cost effective for seasonal or variable load applications.
 Can be combined with other post-combustion controls to provide higher NOx
reductions.
49
Disadvantages of Selective Non-Catalytic Reduction (SNCR) NOx Pollution Control
Technology:
 The waste gas stream must be within a specified temperature range (1400-2100F).
 Not feasible for units to operate SNCR if the temperature of the waste stream is below the
specified temperature range (1400 - 2100F).
 Not applicable to sources with low NOx concentrations such as gas turbines.
 Lower NOx emission reductions than selective catalytic reduction (SCR).
 May require downstream equipment cleaning.
 Results in ammonia in the waste gas stream which may impact plume visibility.
C. Selective Autocatalytic Reduction (SACR) Technology
Overview: Selective autocatalytic reduction (SACR) is a gas phase NOx reduction process
suitable for installation in a new boiler plant or retrofitting existing equipment. The process can
be implemented as stand-alone or in combination with in-furnace NOx reduction technologies,
and is comprised of the autocatalytic reaction zone and injection grid. The NOx removal
efficiencies for units equipped with SACR are comparable to those attained by many SCR
systems.
The key feature of the SACR process is the injection of ammonia based reagent and a
hydrocarbon (e.g. natural gas, propane, etc) into the flue gas containing NOx and some O2. At
elevated temperatures the hydrocarbon auto ignites, forming plasma and creating radicals.
The radicals catalyze the NOx reduction reactions – with the resulting flue gas containing
reduced amounts of NOx and a small amount of ammonia slip.
References
U.S. EPA – CICA Fact Sheet, “Air Pollution Control Technology Fact Sheet; Selective Catalytic
Reduction (SCR).”
U.S. EPA – CICA Fact Sheet, “Air Pollution Control Technology Fact Sheet; Selective Non-Catalytic
Reduction (SNCR).”
NESCAUM, “Control Technologies to Reduce Conventional and Hazardous Air Pollutants from CoalFired Power Plants”, March 31, 2011.
U.S. EPA “Control Technologies Cost and Performance”.
Institute of Clean Air Companies; White Paper - “Selective Non-Catalytic Reduction for Controlling NOx
Emissions”, February 2008.
Institute of Clean Air Companies; White Paper - “Selective Catalytic Reduction Control of NOx
Emissions from Fossil-Fuel Fired Electric Power Plants”, May 2009.
The National Energy Technology Laboratory (NETL) – “Selective Autocatalytic NOx Reduction (SACR)”
50
X.
APPENDICES
APPENDIXA‐HEALTHYAIRACTNOTICEOFPROPOSEDACTION2007
APPENDIXB‐MARYLANDUNITSWITHSCRANDSNCRRATESANDTONS
APPENDIXC‐MARYLANDNOXRATE24HOURBLOCK
APPENDIXD‐NOXRATESFORSCRANDSNCR
APPENDIXE‐OTCRACTPRINCIPALSSTATEMENT
APPENDIXF‐SUMMERSTUDY
APPENDIXG‐EMISSIONREDUCTIONCALCULATIONS
APPENDIXH‐COMPLIANCEPLAN
APPENDIXI‐COLLABORATIVESOLUTIONTOTHEOZONETRANSPORTPROBLEM
51
Appendix A Maryland Healthy Air Act Notice of Proposed Action (Fact Sheet) PROPOSED ACTION ON REGULATIONS
26.11.27
Plants
Subtitle 11 AIR QUALITY
Emission Limitations for Power
717
Affected Sources.
These regulations affect the following fossil-fuel-fired
electric generating units:
Electric Generating Unit Jurisdiction
Authority: Environment Article, §§1-101, 1-404, 2-101 — 2-103,
2-301 — 2-303, 10-102, and 10-103,
Annotated Code of Maryland;
Ch. 23, Acts of 2006
Notice of Proposed Action
[07-048-P]
The Secretary of the Environment proposes to adopt new
Regulations .01 — .06 under a new chapter, COMAR
26.11.27 Emission Limitations for Power Plants.
Statement of Purpose
The purpose of this action is to adopt regulations to
implement the requirements of the Healthy Air Act (Ch. 23,
Acts of 2006), which was signed into law on April 6, 2006
and which establishes emission limitations and related requirements for oxides of nitrogen (NOx), sulfur dioxide
(SO2), and mercury. These emission limitations will apply to
15 coal-fired electric generating units.
Regulations .01 — .03C, .03E, .05, and .06 related to the
reduction NOx and SO2 emissions will be submitted to the
U.S. EPA as a revision to Maryland’s State Implementation
Plan. Regulations .03D, .04, .05 and .06 related to the reduction of mercury emissions will be submitted to the U.S. EPA
as a revision to Maryland’s 111(d) Plan.
Summary of Regulatory Requirements.
These regulations implement the foregoing provisions of
The Healthy Air Act (HAA), (Ch. 23, Acts of 2006), which,
among other things, establishes Statewide tonnage caps for
emissions of NOx and SO2 from 15 coal-fired electric generating units in Maryland effective in 2009 and 2012, and
2010 and 2013, respectively. The HAA further requires the
same coal-fired units to achieve a mercury emissions removal efficiency of 80 percent in 2010 and 90 percent in
2013. In addition, the HAA establishes monitoring and reporting requirements, authorizes the Department to reduce
or waive penalties for noncompliance under certain conditions, and provides for judicial review of decisions by the
Department to grant a reduction or waiver of penalties. The
HAA specifically vests the Department with regulatory authority to allocate the Statewide NOx and SO2 tonnage caps
among the affected units, establish procedures for determining the mercury baseline, and generally implement the
HAA’s provisions through the adoption of regulations by:
(1) Allocating NOx and SO2 Statewide tonnage caps
among the individual electric generating units that are subject to the HAA;
(2) Establishing procedures for determining the uncontrolled mercury flue gas baseline and options for compliance
with the mercury removal efficiency requirements of the
law; and
(3) Establishing procedures to govern judicial review of
determinations by the Department to grant a reduction or
waiver of penalties.
In addition, for ease of reference and completeness, the
regulations restate the monitoring and reporting requirements set forth in the law.
Constellation Energy Group System
Brandon Shores 1 and 2, Anne Arundel County
H. A. Wagner 2 and 3, Anne Arundel County
C. P. Crane 1 and 2, Baltimore County
Mirant System
Chalk Point 1 and 2, Prince George’s County
Dickerson 1, 2, and 3, Montgomery County
Morgantown 1 and 2, Charles County
Allegheny Energy
R. Paul Smith 3 and 4, Washington County
Comparison to Federal Standards
In compliance with Executive Order 01.01.1996.03, this
proposed action is more restrictive or stringent than corresponding federal standards as follows:
(1) Regulation citation and manner in which it is more
restrictive than the applicable federal standard:
COMAR 26.11.27
Federal CAIR: 70 FR 25162
Federal CAMR: 70 FR 28606
The HAA is more restrictive than corresponding federal
standards insofar as it establishes specific NOx, SO2, and
mercury limitations for the 15 coal-fired electric generating
units that are subject to the HAA. Unlike the federal Clean
Air Interstate Rule (CAIR) and Clean Air Mercury Rule
(CAMR), the HAA does not permit compliance through the
surrender of allowances.
(2) Benefit to the public health, safety or welfare, or the
environment: All of the coal-fired units that are subject to
the HAA and these regulations are located in ozone or PM2.5
nonattainment areas, in which approximately 90 percent of
the Maryland citizens reside.
The HAA, and by necessity these implementing regulations, will require installation of on-site pollution controls at
many of the electric generating units subject to the HAA.
This will ensure reductions of NOx and SO2 emissions from
Maryland’s coal-fired electric generating units necessary to
attain the federal National Ambient Air Quality Standards
for ozone and PM2.5 by the 2010 attainment deadlines.
Reductions of NOx emissions will also reduce nitrogen
deposition to the Chesapeake Bay and assist with fulfilling
Maryland’s 2010 nitrogen reduction goal for the Chesapeake Bay.
The HAA requires affected facilities to achieve an 80 percent mercury emission removal efficiency by 2010 and a 90
percent mercury emission removal efficiency by 2013. Reduction of mercury emissions from Maryland coal-fired electric generating units will reduce mercury levels in the environment and in recreational fish species and will contribute
to reductions of methyl mercury levels in 14 water bodies
currently listed as impaired due to elevated mercury levels
in fish.
The HAA, and these implementing regulations, will reduce adverse ozone-related and fine-particulate-matterrelated health effects and health care costs as they reduce
the quantity of pollutants emitted into Maryland’s ambient
air.
MARYLAND REGISTER, VOL. 34, ISSUE 7 FRIDAY, MARCH 30, 2007
718
PROPOSED ACTION ON REGULATIONS
The U.S. Environmental Protection Agency (EPA) performed an analysis of potential health-based costs and benefits for the CAIR. The HAA, and these implementing regulations, mirror closely the NOx and SO2 emission reductions
EPA estimated in Maryland from implementation of the
CAIR, provided that pollution controls are installed as EPA
projects in its CAIR modeling analysis, which is discussed
in more detail below. Thus, the HAA, and these implementing regulations, ensure that the benefits to Maryland forecasted by the EPA assessment of implementing the CAIR
will actually be achieved.
The HAA, and these implementing regulations, will result in an estimated reduction of more than 300,000 incidents in which Marylanders experience adverse health effects, including hospitalizations, illnesses, restricted
activity days, and other effects as defined by EPA, caused by
air pollution and save Maryland over $2,000,000,000 in associated health care costs in 2010.
To conservatively estimate these benefits, the Maryland
Department of the Environment (MDE) staff relied on the
regulatory impact analysis (RIA) EPA performed for the 28state CAIR control region in 2010. Based on Maryland’s proportional population, the HAA, and these regulations, will
annually reduce premature mortality by approximately 400
cases, nonfatal heart attacks by approximately 550 cases,
chronic bronchitis by approximately 200 cases, acute bronchitis by approximately 500 cases, and hospital admissions
and emergency room visits by approximately 600 cases.
EPA also conservatively estimates that nationally, every $1
spent on power plant controls produces $10 in annual
health benefits.
(3) Analysis of additional burden or cost on the regulated person: The CAIR implements the federal cap-andtrade program for NOx and SO2 reductions on the same
timetable as the reductions required by the HAA and these
regulations, that is, 2009 for NOx reductions and 2010 for
SO2 reductions. In its analysis accompanying promulgation
of the CAIR, EPA projected that to comply with the CAIR,
most of the electric generating units subject to these regulations would elect to install selective catalytic reduction
(SCR) and flue gas desulfurization (FGD) control technology, rather than acquire and surrender allowances. In this
regard, Constellation Energy Group, Inc. has recently announced its intention to install FGD control technology on
its two fossil-fuel-fired units at Brandon Shores by 2009. In
addition, Mirant Mid-Atlantic, LLC is presently commencing installation of SCR controls on both of its fossil-fuelfired units at Morgantown.
The capital and operating costs associated with installation of these controls on four of the largest coal-fired electric
generating units in Maryland will be incurred, notwithstanding enactment of the HAA and adoption of these regulations. If EPA’s projections with respect to installation of
controls are similarly accurate for most or all of the remaining units subject to these regulations, a significant portion
of the cost to affected sources of installing and operating the
pollution control equipment that would otherwise be necessary to comply with the HAA and these regulations will be
incurred to achieve compliance with the CAIR, even in the
absence of the HAA.
Equipment to reduce SO2, NOx, and mercury emissions,
primarily through the installation of SCR and FGD controls
at most of the affected units, has been estimated to cost between $1,800,000,000 to $2,100,000,000. Operating costs for
that equipment will be $150,000,000 to $200,000,000 annually. Installing on-site controls will either eliminate or
greatly reduce the need for affected units to purchase allowances for NOx and SO2 to comply with the CAIR, generating
potential annual savings for all affected sources in the
range of $150,000,000 to $400,000,000. Compliance with the
mercury provisions of the HAA and these implementing
regulations can be achieved though the cobenefits of both
SCR and FGD controls or add-on controls specific for mercury. Capital costs for add-on mercury controls could be another $150,000,000, with additional operating costs of
$30,000,000 to $70,000,000. Precise estimates of the costs
associated with implementation of the HAA remain difficult
because MDE does not have full knowledge of exactly what
pollution controls or other strategies owners and operators
of the electric generating units subject to the HAA intend to
implement to achieve compliance.
(4) Justification for the need for more restrictive standards: State law, the HAA (Ch. 23, Acts of 2006), requires
adoption of more restrictive standards.
Estimate of Economic Impact
I. Summary of Economic Impact. The HAA establishes Statewide NOx and SO2 emission tonnage caps and mercury emission
removal rates in two phases that will require installation of pollution controls on most of the electric generating units subject to the
HAA. These implementing regulations merely allocate the Statewide caps among the affected electric generating units and establish procedures for determining the mercury baseline and options
for compliance with the applicable mercury removal efficiency.
While some portion of the costs to regulated entities may be attributable to the ozone season tonnage caps, the individual tonnage allocations, and the mercury limitation compliance procedures established by these regulations, the capital costs and the majority of the
operating costs incurred by the affected facilities are largely attributable to the HAA, which establishes the emissions limitations and
the compliance deadlines. Therefore, this economic impact analysis
primarily focuses on an estimate of the overall cost to implement
the HAA and the broad health and environmental benefits implementation of the HAA will produce. A number of economic analyses
have been considered in developing this estimate, including an
analysis of an early version of the HAA by the Public Service Commission (PSC), an analysis prepared by the Center for Energy and
Economic Development, Inc. (CEED), the EPA’s analysis performed
to support the Clean Air Interstate Rule (CAIR), and other economic analyses by private consultants. Each of these cost analyses
reflects the particular viewpoint of the organization that performed
or commissioned that particular analysis.
MDE relied most heavily on the EPA analysis of the costs and
benefits associated with implementation of CAIR primarily for two
reasons. First, with the NOx SIP Call cap-and-trade program, a
forerunner of CAIR, EPA gained significant experience analyzing
the costs and projecting the benefits of a cap and trade air quality
control program. Achieving compliance with CAIR will require installation of some of the same pollution control equipment, utilize
the same labor force, and generate a similar demand for design and
construction resources in a limited time frame as did the NOx SIP
Call. Drawing on its experience with the NOx SIP Call, the EPA’s
RIA for CAIR included extensive documentation on availability of
the labor force, estimated costs to regulated entities and estimated
lead times necessary to complete installation of pollution controls.
The CAIR analysis is particularly relevant to analysis of the HAA
and its implementing regulations because achieving compliance
with the HAA will require installation of the same NOx and SO2
pollution controls EPA projects electric generating units in Maryland would install to comply with CAIR in the absence of the HAA.
In contrast, the CEED study is a limited analysis based on a hypothetical CAIR Plus regulatory program that is still under development at this time. The PSC study was based on an early version of
the HAA as it was introduced in the General Assembly, with the
first phase 2010 annual SO2 cap of approximately 39,000 tons per
year, which is significantly lower than the 48,618 ton cap in the bill
as enacted.
MARYLAND REGISTER, VOL. 34, ISSUE 7 FRIDAY, MARCH 30, 2007
PROPOSED ACTION ON REGULATIONS
Second, the CAIR cost analysis was based on the same assumed
emission levels as 2010 emission limitations required by the HAA.
In assessing the costs and benefits of CAIR, EPA utilized an economic model, the Integrated Planning Model (IPM), which predicts
which facilities are likely to install pollution controls to comply
with CAIR. The IPM model predicted that nearly all the coal-fired
electric generating units in Maryland would install state-of-the-art
NOx and SO2 pollution controls to comply with CAIR. EPA’s photochemical modeling, performed to analyze the air quality benefits of
CAIR, projected that with the controls predicted by the IPM model,
Maryland would attain the PM2.5 standard by the 2010 deadline.
Accordingly, the CAIR analysis is directly applicable to implementation of the HAA. Therefore, in light of MDE’s limited expertise
and resources in the area of economic analysis and the fact that the
Phase I SO2 caps in the HAA are consistent with the SO2 caps in
EPA’s attainment scenario, MDE’s reliance on EPA’s comprehensive analysis for CAIR to develop a cost estimate for implementation of the HAA was both reasonable and prudent. Since the 2013
Phase II SO2 emission levels are more stringent than the 2010
Phase I levels, this analysis differentiates between the costs for
2009/2010 level controls and the 2012/2013 level controls.
Costs of Installing and Operating NOx and SO2 Pollution
Controls.
Equipment to reduce NOx and SO2 emissions to the 2009 and
2010 emission limitations, primarily through the installation of
SCR and FGD controls at most of the affected units, has been conservatively estimated to cost between $1,800,000,000 to
$2,100,000,000. Annual operating costs for that equipment have
been estimated to range from $150,000,000 to $200,000,000. These
costs will be offset in part by the reduced need to purchase NOx and
SO2 allowances to comply with CAIR. MDE expects installation and
operation of on-site controls to eliminate or greatly reduce the need
for affected units to purchase allowances for NOx and SO2, generating potential annual savings for all affected sources in the range of
$150,000,000 to $400,000,000.
MDE concluded that meeting the more stringent Phase II emission limitations is possible by running the controls installed to
achieve compliance with the Phase I limitations with greater efficiency. MDE estimates that electric generating units subject to the
HAA will incur additional total annual operating costs of between
$150,000,000 and $200,000,000 to achieve compliance with Phase
II limitations.
Mercury Control Costs.
The mercury emission limitations introduce significant variables,
given the variation of mercury content in fuels and the flexible control options available. Affected units that have installed SO2 and
NOx controls may achieve compliance with the HAA Phase I mercury emission removal efficiency requirement and possibly the
Phase II requirement entirely through the cobenefits of these controls. Units without SO2 and NOx controls will require other means
to control mercury. Such reduction measures might include fuelswitching or installation of activated carbon injection (ACI) systems or other add-on control equipment. The capital costs of installing ACI systems FGD or SCR controls units could be approximately
$150,000,000.
Additional operating costs may be incurred to achieve compliance
with the HAA mercury standards such as the cost of operation of
control equipment and fuel switching (assuming coals with specific
sulfur or mercury content are more expensive). Operating costs of
ACI systems at units without SCR or FGD would range from
$30,000,000 to $70,000,000.
Electricity Rate Increases.
Commercial and consumer electricity rates are influenced by
many factors. The costs associated with implementation of the HAA
may be one factor that influences these rates, but the magnitude of
that influence is difficult to quantify when added to other factors
that significantly affect electric rates. The current increases in energy prices driven by increases in oil and natural gas prices and
factors other than costs associated with meeting environmental obligations are responsible for the recent significant increase in consumer electric rates. In its RIA for CAIR, the EPA projected that
719
electricity rates would increase in Maryland by 0.17 to 0.26 cents
per kilowatt. In contrast, the PSC estimated that rates would increase by 0.63 to 0.83 cents per kilowatt, in part based on the PSC’s
prediction that implementation of the HAA could result in shutdown of several plants. However, the PSC analysis was based on
the HAA as introduced with a 2010 SO2 emissions cap of approximately 39,000 tons per year, which was significantly more stringent
than the 2010 SO2 emissions cap in the HAA as enacted.
Health Benefits.
MDE estimates that implementation of the HAA will lead to a
reduction of over 300,000 incidents of adverse health effects and
save Maryland more than $2,000,000,000 in health costs in 2010.
The EPA also conservatively estimates that each $1 spent nationally on power plant controls results in $10 worth of annual health
benefits. These benefits of implementing the HAA are not in addition to benefits resulting from implementation of CAIR because the
Healthy Air Act simply ensures that the reductions projected by
EPA for the CAIR will be realized in Maryland.
II. Types of
Economic Impacts
A. On issuing agency:
B. On other State agencies:
C. On local governments:
Electricity rates
Revenue
(R+/R⫺)
(E+)
(E+)
Indeterminate
Indeterminate
(E+)
Indeterminate
Benefit (+)
Cost (–)
D. On regulated industries or
trade groups:
(1) Capital costs
(–)
Magnitude
(2) Annual operating costs
(–)
(3) Annually avoided allowances
E. On other industries or trade
groups:
(1) MD contractors
(2) Electricity rates
F. Direct and indirect effects on
public:
(1) Health benefits
(+)
$1,800,000,000 —
$2,100,000,000
$180,000,000 —
$270,000,000
$150,000,000
(+)
(–)
Indeterminate
Indeterminate
$2,160,000,000
in 2010
(2) Electricity rates
(–)
Indeterminate
III. Assumptions. (Identified by Impact Letter and Number
from Section II.)
A, B, C. These controls may result in an increase in commercial
or consumer electricity rates, however, the magnitude of any increase that may result is indeterminate. (See electricity rate discussion above.) In general, commodity pricing is the prerogative of the
vendor and is influenced by the vendor’s assessment of which costs
to pass along to the consumer and which costs to absorb. MDE does
not possess expertise in energy marketing practices and is unable
to predict electricity rates.
D(1). It is difficult to determine the precise costs to regulated entities associated with implementation of these regulations because
of a number of site-specific requirements and variables associated
with the cost of installation and operation of pollution control
equipment necessary to comply with these regulations at specific
Maryland plants. Additionally, the regulations do not dictate compliance strategies. MDE has examined a number of cost analyses in
developing cost range estimates for the HAA and these implementing regulations. EPA’s economic impact analysis for CAIR estimates that the capital costs to control these units will be approximately $1,300,000,000. Using other cost analyses available, the
Department conservatively estimates total capital costs for control
of SO2 and NOx by 2010 could range from about $1,800,000,000 to
$2,100,000,000, with variation dependent on many factors, including assumptions regarding equipment cost factors, firms’ compli-
MARYLAND REGISTER, VOL. 34, ISSUE 7 FRIDAY, MARCH 30, 2007
(+)
720
PROPOSED ACTION ON REGULATIONS
ance strategies, fuels used or available during the compliance period, future demand growth, and utilization of units. The estimated
capital costs cited here do not include costs associated with installation of NOx controls to comply with other regulatory requirements.
An important variable in assessing the cost of the proposed rule
is whether or not the controls at a particular facility will be installed as a compliance strategy for the CAIR. For example, Constellation Energy Group, Inc. reports that its consultants estimate
the installation of FGD technology on two units at one affected
plant to cost $500,000,000. The company has stated that it had
planned these controls prior to passage of the HAA as a means of
complying with the CAIR. Excluding this equipment from the
analysis as a measure not specifically driven by the State regulations would reduce the cost estimate by a third.
The mercury limits introduce significant variables, given the
variation in the mercury content in fuels and the flexibility of control strategy choice. Compliance with the 2010 mercury limits in
the regulations could be achieved at affected units through the installation of SO2 and NOx controls that provide mercury cobenefits.
Units without SO2 and NOx controls would require other means to
control mercury. Such reduction measures might include add-on
control equipment or fuel switching. For example, the capital costs
of ACI systems to units without FGD or SCR could be approximately $150,000,000.
D(2). Annual operating costs to comply with the SO2 and NOx
provisions of the regulations are estimated to range from
$150,000,000 to $200,000,000 annually. Additional operating costs
may be incurred to comply with the mercury standards in the regulations. Such costs might include operation of control equipment
and fuel switching (assuming coals with specific sulfur or mercury
content are more expensive). Operating costs of ACI systems at
units without SCR or FGD would range from $30,000,000 to
$70,000,000.
D(3). Other considerations in estimating the cost of controls to
comply with these regulations include the elimination of the need
to purchase allowances and the possibility of using less expensive,
higher sulfur coal. In complying with these proposed regulations,
affected sources avoid the cost of purchasing allowances for SO2
and NOx otherwise needed to comply with federal CAIR budgets.
The annual savings in sulfur dioxide allowance costs for all affected
sources is estimated to be approximately $150,000,000 to
$400,000,000 from 2010 through 2014, relative to current emission
rates; savings starting in 2015 could be 50 percent higher. NOx reductions beyond the federal allocation could result in avoided allowance costs of about $10,000,000. Actual savings would depend on
growth rates, actual level of emission reductions, the market price
of allowances, and firms’ compliance strategies.
E(1). Contractors will construct control systems including supports, housing, storage and mix tanks, piping, and duct work. The
percentage of work that will be performed by Maryland contractors
is indeterminate because of the specificity of the labor force required for these installations.
E(2), F(2). These controls may result in an increase in commercial or consumer electricity rates, however, the magnitude of any
increase that may result is indeterminate. (See electricity rate discussion above.) In general, commodity pricing is the prerogative of
the vendor and is influenced by the vendor’s assessment of which
costs to pass along to the consumer and which costs to absorb. MDE
does not possess expertise in energy marketing practices and is unable to predict electricity rates.
F(1). The $2,160,000,000 dollars is a conservative estimate and
based on the benefits estimated by EPA from CAIR for 2010 and
proportioned based on Maryland’s population as a portion of the
CAIR region population. This is a conservative estimate because
Maryland’s rule is more stringent than CAIR and will reap benefits
sooner through requiring on-site controls and prohibiting the surrender of allowances as a means of achieving compliance.
The estimated $2,160,000,000 total benefit in 2010 accrues from
approximate reductions in premature mortality ($2,000,000,000),
chronic bronchitis ($75,600,000), nonfatal heart attacks
($42,600,000), minor restricted activity days ($12,700,000), lost
work days ($5,400,000), and hospital admissions for respiratory
and cardiovascular problems ($4,000,000). All of the monetary benefits are in constant-year 1999 dollars.
Economic Impact on Small Businesses
The proposed action has minimal or no economic impact
on small businesses.
Impact on Individuals with Disabilities
The proposed action has an impact on individuals with
disabilities as follows: These regulations will have a positive
impact on individuals with disabilities by reducing air pollutants that contribute to numerous respiratory and cardiovascular diseases. The regulations will also reduce mercury
emissions that can be harmful to unborn babies and young
children through consumption of fish and shellfish.
Opportunity for Public Comment
Comments may be sent to Deborah Rabin, Regulations
Coordinator, Air and Radiation Management Administration, Department of the Environment, 1800 Washington
Boulevard, Baltimore, MD 21230, or fax to 410-537-4223, or
call 410-537-3249, or email to [email protected]
Comments must be received not later than May 1, 2007, or
be submitted at the hearing. For more information, call
Deborah Rabin at 410-537-3240. The Department of the Environment will hold a public hearing on the proposed action
on May 1, 2007 at 10 a.m. at 1800 Washington Boulevard,
1st Floor Aeris Conference Room, Baltimore, MD 21230. Interested persons are invited to attend and express their
views.
Copies of the proposed action and supporting documents
are available for review at the following locations: the Air
and Radiation Management Administration, regional offices
of MDE in Cumberland and Salisbury, all local air quality
control offices, and local health departments in those counties not having separate air quality control offices.
Anyone needing special accommodations at the public
hearing should contact MDE’s Fair Practices Office at (410)
537-3964. TTY users may contact MDE through the Maryland Relay Service at 711.
Editor’s Note: The text of this document will not be printed
here because it appeared as a Notice of Emergency Action in
34:3 Md. R. 291 — 296 (February 2, 2007), referenced as
[07-048-E].
SHARI T. WILSON
Secretary of the Environment
Subtitle 11 AIR QUALITY
26.11.32 Control of Emissions of Volatile Organic Compounds from Consumer Products
Authority: Environment Article, §§1-101, 1-404, 2-101 — 2-103,
2-301 — 2-303, 10-102, and 10-103,
Annotated Code of Maryland
Notice of Proposed Action
[07-072-P-I]
The Secretary of the Environment proposes to:
(1) Amend Regulations .01 — .04 and .06;
(2) Adopt new Regulations .08 — .10;
(3) Amend and recodify existing Regulations .10 — .15
and .18 — .22 to be Regulations .13 — .18 and .21 — .25;
and
MARYLAND REGISTER, VOL. 34, ISSUE 7 FRIDAY, MARCH 30, 2007
Appendix B Maryland Coal‐Fired EGUs Ozone Season Performance Rates Coal‐Fired Units with SCRs and SNCRs, 2007‐2013 July 2012 Ozone Season NOx Reductions at Lowest OS Rate Coal‐Fired EGU vs Other Fuel EGU 2011 CAMD OS Report 2014 CAMD OS Report Maryland Coal-Fired EGUs
Ozone Season Performance
NOx Emission Rate
Purpose
The data used in this analysis includes:
 CEMS data, downloaded from CAMD
 Emissions and projection data from ERTAC
Average ozone season NOx emission rate for operating coal-fired EGUs in Maryland was graphed. A visual evaluation of
the data was performed to judge the continuous and effective operation of post combustion controls, specifically SCR and
SNCR. In general, it was judged that an increase in the average ozone season NOx emission rate suggests a
discontinued, or at a minimum, less effective operation of post combustion controls.
The same data analysis was performed for 10 other States with ozone transport contributions to Maryland. These results
are available upon request.
The Maryland graphs are attached.
Average Ozone Season Emission
Rates at Specific Units by Year
0.5000
Maryland Coal Fired EGUs, SCR
Example: Specific units consistently running controls
consistently running controls 0.4500
NOx Emis
ssion Rate, lbs/MMBtu
0.4000
0.3500
0.3000
0.2500
0.2000
0.1500
0.1000
0.0500
0.0000
2002
Brandon Shores 1
2004
2006
Brandon Shores 2
2008
Herbert A Wagner 3
2010
Chalk Point 1
2012
Morgantown 1
2014
Morgantown 2
1
DRAFT – September 18, 2014 – Requesting QA of data. For discussion purposes only.
1.00
Average Ozone Season Emission
Rates at Specific Units by Year
0.90
0.80
Maryland Coal Fired EGUs, SNCR
NOx Emission Ra
N
ate (lbs/MMBtu)
0.70
0.60
Example: Specific units consistently running controls i t tl
i
t l
0.50
0.40
0.30
0.20
0.10
0.00
2003
2004
2005
2006
Dickerson 1
2007
Dickerson 2
2008
Dickerson 3
2009
2010
2011
2012
Chalk Point 2
2
DRAFT – September 18, 2014 – Requesting QA of data. For discussion purposes only.
1.00
Average Ozone Season Emission
Rates at Specific Units by Year
0.90
0.80
Maryland Coal Fired EGUs, SNCR
NOx Emission Ra
N
ate (lbs/MMBtu)
0.70
Example: Specific units not running controls in later years
0.60
0.50
0.40
0.30
0.20
0.10
0.00
2003
2004
2005
2006
Crane 1
2007
Crane 2
2008
Wagner 2
2009
2010
2011
2012
Warrior Run 1
3
DRAFT – September 18, 2014 – Requesting QA of data. For discussion purposes only.
Tons of NOx Per Day By Control Status
45
Maryland, Coal EGUs, July 1-10, 2012
40
35
NOx Emissions, tons
30
25
20
15
10
5
0
07/01/12
07/02/12
SCR operating
07/03/12
SCR not operating
07/04/12
SNCR
07/05/12
07/06/12
07/07/12
without SCR/SNCR, under 3000 MMBtu
DRAFT – September 18, 2014 – Requesting QA of data. For discussion purposes only.
07/08/12
07/09/12
without SCR/SNCR, over 3000 MMBtu
07/10/12
1
18
MD – Tons of NOx Per Unit By Control Status, July 2, 2012
Shutdown by 2017
Per ERTAC- EGU Version 2.2
Unit Availability File (updated 5/8/2014)
MD iis retiring
ti i allll off itits uncontrolled
t ll d units.
it N
No ffuell
switches are scheduled at this time. No controls are
scheduled to be installed at this time.
*Note MD received credit for updating controls which
is indicative in the growth in the SNCR category.
16
14
Controls/Fuel Switches by 2019
Per ERTAC- EGU Version 2.2
Controls File (updated 5/6/2014)
Optimistic Shutdown by 2018
Per a variety of media sources
Optimistic Controls/Fuel Switches by 2016
Per a variety of media sources
NOx Emission
ns, tons
12
10
8
6
4
R. Paul Smith 11
R. Paul Smith
h 9
Warrior Run
n 1
Dickerson
n 3
Dickerson
n 2
C P Cranee 2
Dickerson
n 1
C P Cranee 1
H A Wagner 2
Chalk Pointt 2
H A Wagner 3
Morgantown
n 2
Brandon
n 2
Morgantown
n 1
Chalk Pointt 1
0
Brandon
n 1
2
2
DRAFT – September 18, 2014 – Requesting QA of data. For discussion purposes only.
DRAFT – September 18, 2014 – Requesting QA of data. For discussion purposes only.
3
DRAFT – September 18, 2014 – Requesting QA of data. For discussion purposes only.
4
Tons of NOx per Day, Actual vs. Lowest OS
Average
g Emission Rate
100
90
Maryland Coal EGUs, SCR, July 1 - 10, 2012
80
NOx Emissions
s, tons
70
60
50
40
30
20
10
0
7/1/2012
7/2/2012
7/3/2012
7/4/2012
NOx, Actual (tons)
7/5/2012
7/6/2012
7/7/2012
7/8/2012
7/9/2012
7/10/2012
NOx at lowest OS avg. emission rate (tons)
5
DRAFT – September 18, 2014 – Requesting QA of data. For discussion purposes only.
20
18
Tons of NOx per Unit, Actual vs. Lowest OS
Average
g Emission Rate
Maryland Coal EGUs, SCR, July 2, 2012
16
NOx Emissio
ons, tons
14
12
10
8
6
4
NOx, Actual (tons)
H A Wag
gner 3
Morganto
own 2
Brandon 2
Morganto
own 1
Chalk Point 1
0
Brandon 1
2
NOx at lowest OS avg. emission rate (tons)
6
DRAFT – September 18, 2014 – Requesting QA of data. For discussion purposes only.
Tons of NOx per Day, Actual vs.
Lowest OS Average
g Emission Rate
100
90
Maryland Coal Fired EGUs, SNCR, July 1 - 10, 2012
80
NOx Emiss
sions, tons
70
60
50
40
30
20
10
0
7/1/2012
7/2/2012
7/3/2012
7/4/2012
NOx, Actual (tons)
7/5/2012
7/6/2012
7/7/2012
7/8/2012
7/9/2012
7/10/2012
NOx at lowest OS avg. emission rate (tons)
7
DRAFT – September 18, 2014 – Requesting QA of data. For discussion purposes only.
Tons of NOx per Unit, Actual vs.
Lowest OS Average
g Emission Rate
40
35
Maryland Coal Fired EGUs, SNCR, July 2, 2012
NOx Emissio
ons, tons
30
25
20
15
10
NOx, Actual (tons)
Warrior R
Run 1
Dickerrson 3
Dickerrson 2
Dickerrson 1
Chalk P
Point 2
Wag
gner 2
Crrane 2
0
Crrane 1
5
NOx at lowest OS avg. emission rate (tons)
8
DRAFT – September 18, 2014 – Requesting QA of data. For discussion purposes only.
PERCENT
ALL FOSSIL FUELS
COAL
year
2008
2009
2010
2011
2012
2013
2014
2008
2009
2010
2011
2012
2013
2014
2008
2009
2010
2011
2012
2013
2014
Number of units
16
16
16
16
16
14
14
48
48
48
48
48
46
46
Gross Load (MW‐h) 12,394,695
10,525,704
11,758,399
10,341,743
8,788,792
7,601,684
7,352,403
13,350,285
11,289,002
13,875,563
11,927,589
11,507,048
9,056,415
8,086,009
92.84%
93.24%
84.74%
86.70%
76.38%
83.94%
90.93%
NOx (tons) 8,682
6,843
8,138
7,158
5,894
4,591
3,498
9,395
7,160
9,428
8,201
7,494
5,303
3,934
92.41%
95.58%
86.31%
87.28%
78.65%
86.56%
88.92%
Heat Input (MMBtu) 118,951,883
99,302,435
117,814,269
105,001,348
88,160,267
74,401,348
74,375,274
130,224,098
107,180,675
141,086,263
122,277,216
118,928,324
89,279,250
82,087,413
91.34%
92.65%
83.51%
85.87%
74.13%
83.34%
90.60%
KW 10‐22‐14
Calculate the % of Nox emissions from coal‐fired EGUS compared to all EGUS
Use CAMD downloads for 48 units (over 25MW) from 2008 ‐ 2014
Ozone season
State
MD
MD
MD
MD
MD
MD
MD
MD
MD
MD
MD
MD
MD
MD
MD
MD
MD
MD
MD
MD
MD
MD
MD
MD
MD
MD
MD
MD
MD
MD
MD
MD
MD
MD
MD
MD
MD
MD
MD
MD
MD
MD
MD
MD
MD
MD
MD
MD
Facility ID Facility Name
(ORISPL) Unit ID
Year
Brandon Shores
602
1
2011
Brandon Shores
602
2
2011
C P Crane
1552
1
2011
C P Crane
1552
2
2011
Herbert A Wagner
1554
2
2011
Herbert A Wagner
1554
3
2011
R. Paul Smith Power Sta
1570
9
2011
R. Paul Smith Power Sta
1570
11
2011
Chalk Point
1571
1
2011
Chalk Point
1571
2
2011
Dickerson
1572
1
2011
Dickerson
1572
2
2011
Dickerson
1572
3
2011
Morgantown
1573
1
2011
Morgantown
1573
2
2011
AES Warrior Run
10678
1
2011
Perryman
1556 CT1
2011
Perryman
1556 CT2
2011
Perryman
1556 CT3
2011
Perryman
1556 CT4
2011
Chalk Point
1571 GT2
2011
Morgantown
1573 GT3
2011
Morgantown
1573 GT4
2011
Morgantown
1573 GT5
2011
Morgantown
1573 GT6
2011
Herbert A Wagner
1554
1
2011
Herbert A Wagner
1554
4
2011
Gould Street
1553
3
2011
Perryman
1556 **51
2011
Riverside
1559
4
2011
Riverside
1559 CT6
2011
Westport
1560 CT5
2011
Chalk Point
1571 **GT3
2011
Chalk Point
1571 **GT4
2011
Chalk Point
1571 **GT5
2011
Chalk Point
1571 **GT6
2011
Chalk Point
1571 SMECO
2011
Dickerson
1572 GT2
2011
Dickerson
1572 GT3
2011
Rock Springs Generatin
7835
1
2011
Rock Springs Generatin
7835
2
2011
Rock Springs Generatin
7835
3
2011
Rock Springs Generatin
7835
4
2011
Brandywine Power Fac
54832
1
2011
Brandywine Power Fac
54832
2
2011
Vienna
1564
8
2011
Chalk Point
1571
3
2011
Chalk Point
1571
4
2011
48
# of Gross Avg. NOx Associate Program(s Operating Months Load (MW‐ SO2 Rate NOx d Stacks )
Time
Reported h)
(tons)
(lb/MMBtu) (tons)
CAIROS
3151
5 1366348 728.249
0.1057
613.82
CAIROS
3627.26
5 1635409
868.51
0.1076 762.214
CAIROS
2515.34
5 329215.9 1678.577
0.4185 688.918
CAIROS
2870.88
5 332467.1 2164.385
0.386 810.969
CAIROS
3582.35
5 223820.3 1638.788
0.3582 516.031
CAIROS
3084.33
5 670009.8 3384.78
0.0697 204.236
MS9A, MS9CAIROS
483.01
5 8691.34
86.311
0.3699
27.865
CAIROS
868.41
5 50898.01 305.527
0.2607
71.602
CSE12, CSECAIROS
2431.84
5 665109.4 521.211
0.1695 529.192
CSE12, CSECAIROS
3141.63
5 911321.1 1356.642
0.2261 988.383
CSDW13, CCAIROS
2229.21
5 231829.1 164.488
0.2552 273.148
CSDW13, CCAIROS
2445.43
5 261951.5 181.484
0.2533 312.279
CSDW13, CCAIROS
2714
5 291002.2 195.872
0.2497 344.765
MSFW1, MCAIROS
2927.4
5 1175298 2019.031
0.0419 244.741
MSFW2, MCAIROS
3488.45
5 1563780 816.005
0.0309 233.309
CAIROS
3660.81
5 624593.3
817.43
0.1426 536.844
CAIROS
106.73
5 4136.14
1.008
0.7612
26.285
CAIROS
106.7
5 3994.91
1.616
0.6872
23.395
CAIROS
66.67
5 2356.24
1.003
0.7498
16.602
CAIROS
46.61
5 1470.27
0.646
1.2
14.68
CAIROS
30.42
5
567.45
2.994
0.868
4.091
CAIROS
50.12
5 1752.26
2.347
0.6603
11.4
CAIROS
52.88
5
1995.5
2.376
0.6221
11.004
CAIROS
45.9
5 1698.83
2.002
0.6531
9.813
CAIROS
44.98
5 1513.36
1.86
0.5179
7.253
CAIROS
727.77
5 33584.39
0.132
0.1004
36.934
CAIROS
194.23
5 26986.69 105.718
0.2395
49.528
CAIROS
557.44
5 26874.75
0.093
0.0856
15.589
CAIROS
224.04
5 29632.73
0.11
0.0531
8.431
CAIROS
482.8
5 17898.33
0.067
0.2141
25.589
CAIROS
21.28
5
688.71
0.004
0.216
1.365
CAIROS
8.63
5
300.19
0.002
0.216
0.745
CAIROS
159.03
5 10893.78
1.613
0.0873
6.472
CAIROS
115.19
5 7571.02
0.126
0.0711
3.622
CAIROS
160.4
5 12962.27
2.672
0.0876
7.622
CAIROS
181.74
5 14774.97
1.631
0.0632
6.01
CAIROS
99
5
6251
2.291
0.7607
35.599
CAIROS
117.34
5 12539.01
0.141
0.1017
5.275
CAIROS
124.18
5 12110.28
0.034
0.1144
6.452
CAIROS
357.72
5 54520.68
0.171
0.0355
7.781
CAIROS
364.73
5 55755.87
0.173
0.0417
9.141
CAIROS
503.13
5 76567.01
0.241
0.0432
13.729
CAIROS
489.44
5 74577.91
0.236
0.0422
13.344
CAIROS
1746.66
5 183109.5
0.433
0.0351
21.119
CAIROS
1714.7
5 178705.6
0.414
0.0327
18.585
CAIROS
293
5
16093 158.783
0.31
34.547
CAIROS
818.77
5 345136.7
38.69
0.11 263.932
CAIROS
942.15
5 368826.3
41.714
0.1041 327.161
11927589
8201.411
CO2 (short tons)
1495425
1621222
343414.5
409147.3
284019
663333.6
14754.78
53105.69
649889.5
887535.5
224612.4
257253
286624.5
1301549
1549851
746822.7
5093.457
4967.008
3083.239
1985.576
697.102
2672.516
2705.31
2280.094
2117.871
26220.62
28190.18
18499.38
21716.42
13289.41
750.874
410.185
9225.668
6164.644
9475.441
11466.65
5817.7
6205.247
6642.288
33809.1
34341.05
47742.46
46838.36
85718.25
82070.76
17346.25
226093.5
286330.7
Heat Input EPA (MMBtu) Region County
1.46E+07
3 Anne Arundel
1.58E+07
3 Anne Arundel
3274370
3 Baltimore
3901106
3 Baltimore
2768220
3 Anne Arundel
6465261
3 Anne Arundel
143823.2
3 Washington
517595.7
3 Washington
6335676
3 Prince George's
8651989
3 Prince George's
2189204
3 Montgomery
2507343
3 Montgomery
2793619
3 Montgomery
1.27E+07
3 Charles
1.51E+07
3 Charles
7284122
3 Allegany
62773.53
3 Harford
61212.91
3 Harford
37996.09
3 Harford
24465.91
3 Harford
8589.831
3 Prince George's
32938.63
3 Charles
33340.34
3 Charles
28096.97
3 Charles
26101.14
3 Charles
441204.5
3 Anne Arundel
348684.1
3 Anne Arundel
311300.9
3 Baltimore (City)
365417.9
3 Harford
223627.1
3 Baltimore
12637.11
3 Baltimore
6901.316
3 Baltimore (City)
147354.7
3 Prince George's
103259.2
3 Prince George's
146237.6
3 Prince George's
185031.5
3 Prince George's
95240.7
3 Prince George's
104323.8
3 Montgomery
111765.8
3 Montgomery
568895.5
3 Cecil
577843.4
3 Cecil
803366.2
3 Cecil
788135.7
3 Cecil
1442378
3 Prince George's
1380996
3 Prince George's
213766.9
3 Dorchester
3784164
3 Prince George's
4797821
3 Prince George's
1.22E+08
Source Category
Electric Utility
Electric Utility
Electric Utility
Electric Utility
Electric Utility
Electric Utility
Electric Utility
Electric Utility
Electric Utility
Electric Utility
Electric Utility
Electric Utility
Electric Utility
Electric Utility
Electric Utility
Cogeneration
Electric Utility
Electric Utility
Electric Utility
Electric Utility
Electric Utility
Electric Utility
Electric Utility
Electric Utility
Electric Utility
Electric Utility
Electric Utility
Electric Utility
Electric Utility
Electric Utility
Electric Utility
Electric Utility
Electric Utility
Electric Utility
Electric Utility
Electric Utility
Electric Utility
Electric Utility
Electric Utility
Electric Utility
Electric Utility
Electric Utility
Electric Utility
Cogeneration
Cogeneration
Electric Utility
Electric Utility
Electric Utility
Owner
Constellation Power Sourc
Constellation Power Sourc
Constellation Power Sourc
Constellation Power Sourc
Constellation Power Sourc
Constellation Power Sourc
Allegheny Energy
Allegheny Energy
GenOn Chalk Point, LLC
GenOn Chalk Point, LLC
GenOn Mid‐Atlantic, LLC
GenOn Mid‐Atlantic, LLC
GenOn Mid‐Atlantic, LLC
GenOn Mid‐Atlantic, LLC
GenOn Mid‐Atlantic, LLC
AES Corporation
Constellation Power Sourc
Constellation Power Sourc
Constellation Power Sourc
Constellation Power Sourc
GenOn Mid‐Atlantic, LLC
GenOn Mid‐Atlantic, LLC
GenOn Mid‐Atlantic, LLC
GenOn Mid‐Atlantic, LLC
GenOn Mid‐Atlantic, LLC
Constellation Power Sourc
Constellation Power Sourc
Constellation Power Sourc
Constellation Power Sourc
Constellation Power Sourc
Constellation Power Sourc
Constellation Energy Comm
GenOn Chalk Point, LLC
GenOn Chalk Point, LLC
GenOn Chalk Point, LLC
GenOn Chalk Point, LLC
South Maryland Electric Co
GenOn Mid‐Atlantic, LLC
GenOn Mid‐Atlantic, LLC
Old Dominion Electric Coop
Old Dominion Electric Coop
North American Energy All
North American Energy All
Panda Brandywine, LP
Panda Brandywine, LP
Vienna Power, LLC
GenOn Chalk Point, LLC
GenOn Chalk Point, LLC
Represent
Representative ative SO2 NOx Operating (Primary)
(Secondar Phase
Phase
Status
Facility Name
ARP : Morrison, Q ARP : TracePhase 2
Phase II GroOperating
Brandon Shores
TRNOX : Haught, DTRNOX : M Phase 2
Brandon Shores
Phase II GroOperating
C P Crane
TRNOXOS : Butler,TRNOXOS : Table 1
Group 2 Operating
C P Crane
CAIRNOX : Butler, CAIRNOX : Table 1
Group 2 Operating
Herbert A Wagner
ARP : Morrison, Q ARP : TracePhase 2
Phase II GroOperating
Herbert A Wagner
CAIROS : MorrisonCAIROS : TrPhase 2
Phase 2
Operating
R. Paul Smith Power StaARP : Cannon, DavARP : Cain, Phase 2
Phase 1 GroOperating
R. Paul Smith Power StaARP : Cannon, DavARP : Cain, Phase 2
Phase 1 GroOperating
Chalk Point
RGGI : Garlick, JamRGGI : Gau Table 1
Phase 1 GroOperating
Chalk Point
ARP : Garlick, JameARP : Gaud Table 1
Phase 1 GroOperating
Dickerson
TRSO2G1 : Gouvei TRSO2G1 : Phase 2
Phase II GroOperating
Dickerson
TRNOXOS : Gouve TRNOXOS : Phase 2
Phase II GroOperating
Dickerson
TRNOXOS : Gouve TRNOXOS : Phase 2
Phase II GroOperating
Morgantown
ARP : Garlick, JameARP : Gaud Table 1
Phase 1 GroOperating
Morgantown
ARP : Garlick, JameARP : Gaud Table 1
Phase 1 GroOperating
AES Warrior Run
RGGI : Leaf, Jeff (6RGGI : Braun, Wilma L (3185),CAIROperating
Perryman
ARP : Blair, Scott MARP : Tracey, Edward F (2683) (EndOperating
Perryman
ARP : Blair, Scott MARP : Tracey, Edward F (2683) (EndOperating
Perryman
CAIRNOX : Blair, ScCAIRNOX : Tracey, Edward F (2683Operating
Perryman
ARP : Blair, Scott MARP : Tracey, Edward F (2683) (EndOperating
Chalk Point
CAIROS : Garlick, J CAIROS : Gaudette, Robert (60548Operating
Morgantown
ARP : Garlick, JameARP : Gaudette, Robert (605481) Operating
Morgantown
ARP : Garlick, JameARP : Gaudette, Robert (605481) Operating
Morgantown
ARP : Garlick, JameARP : Gaudette, Robert (605481) Operating
Morgantown
ARP : Garlick, JameARP : Gaudette, Robert (605481) Operating
Herbert A Wagner
TRNOX : Haught, DTRNOX : M Phase 2
Operating
Herbert A Wagner
RGGI : Morrison, QRGGI : Trac Phase 2
Operating
Gould Street
ARP : Blair, Scott MARP : TracePhase 2
Operating
Perryman
ARP : Blair, Scott MARP : TracePhase 2
Operating
Riverside
ARP : Blair, Scott MARP : TracePhase 2
Operating
Riverside
ARP : Blair, Scott MARP : Tracey, Edward F (2683) (EndOperating
Westport
CAIROS : Blair, ScoCAIROS : Tracey, Edward F (2683) Operating
Chalk Point
CAIRNOX : Garlick,CAIRNOX : Phase 2
Operating
Chalk Point
ARP : Garlick, JameARP : Gaud Phase 2
Operating
Chalk Point
ARP : Garlick, JameARP : Gaud Phase 2
Operating
Chalk Point
ARP : Garlick, JameARP : Gaud Phase 2
Operating
Chalk Point
ARP : Garlick, JameARP : Gaudette, Robert (605481) Operating
Dickerson
CAIRNOX : Garlick,CAIRNOX : Phase 2
Operating
Dickerson
CAIRSO2 : Garlick, CAIRSO2 : GPhase 2
Operating
Rock Springs Generatin ARP : Peach, Jame ARP : Doug Phase 2
Operating
Rock Springs Generatin ARP : Peach, Jame ARP : Doug Phase 2
Operating
Rock Springs Generatin ARP : Peach, Jame ARP : Doug Phase 2
Operating
Rock Springs Generatin ARP : Peach, Jame ARP : Doug Phase 2
Operating
Brandywine Power Fac ARP : Martin, JohnARP : Brigg Phase 2
Operating
Brandywine Power Fac ARP : Martin, JohnARP : Brigg Phase 2
Operating
Vienna
ARP : Grant, Jack ARP : Sulliv Phase 2
Operating
Chalk Point
ARP : Garlick, JameARP : Gaud Phase 2
Operating
Chalk Point
CAIRSO2 : Garlick, CAIRSO2 : GPhase 2
Operating
Unit Type
Fuel Type (Primary)
Dry bottom wall‐fired boile Coal
Dry bottom wall‐fired boile Coal
Cyclone boiler
Coal
Cyclone boiler
Coal
Dry bottom wall‐fired boile Coal
Dry bottom wall‐fired boile Coal
Dry bottom wall‐fired boile Coal
Tangentially‐fired
Coal
Dry bottom wall‐fired boile Coal
Dry bottom wall‐fired boile Coal
Tangentially‐fired
Coal
Tangentially‐fired
Coal
Tangentially‐fired
Coal
Tangentially‐fired
Coal
Tangentially‐fired
Coal
Circulating fluidized bed boCoal
Combustion turbine
Diesel Oil
Combustion turbine
Diesel Oil
Combustion turbine
Diesel Oil
Combustion turbine
Diesel Oil
Combustion turbine
Diesel Oil
Combustion turbine
Diesel Oil
Combustion turbine
Diesel Oil
Combustion turbine
Diesel Oil
Combustion turbine
Diesel Oil
Dry bottom wall‐fired boile Other Oil
Dry bottom wall‐fired boile Other Oil
Dry bottom wall‐fired boile Pipeline Natural Gas
Combustion turbine
Pipeline Natural Gas
Dry bottom wall‐fired boile Pipeline Natural Gas
Combustion turbine
Pipeline Natural Gas
Combustion turbine
Pipeline Natural Gas
Combustion turbine
Pipeline Natural Gas
Combustion turbine
Pipeline Natural Gas
Combustion turbine
Pipeline Natural Gas
Combustion turbine
Pipeline Natural Gas
Combustion turbine
Pipeline Natural Gas
Combustion turbine
Pipeline Natural Gas
Combustion turbine
Pipeline Natural Gas
Combustion turbine
Pipeline Natural Gas
Combustion turbine
Pipeline Natural Gas
Combustion turbine
Pipeline Natural Gas
Combustion turbine
Pipeline Natural Gas
Combined cycle
Pipeline Natural Gas
Combined cycle
Pipeline Natural Gas
Tangentially‐fired
Residual Oil
Tangentially‐fired
Residual Oil
Tangentially‐fired
Residual Oil
Fuel Type (Secondar
y)
SO2 Control(s)
Wet Lime FGD
Wet Limestone
NOx Control(s)
PM Control(s)
Low NOx Burner Technology w/ Overfire Air<br>Sel Cyclone<br>Baghouse
Low NOx Burner Technology w/ Overfire Air<br>Sel Cyclone<br>Baghouse
Overfire Air<br>Combustion Modification/Fuel Reb Baghouse
Overfire Air<br>Combustion Modification/Fuel Reb Baghouse
Low NOx Burner Technology (Dry Bottom only)<br> Electrostatic Precipitator
Low NOx Burner Technology w/ Overfire Air<br>Sel Electrostatic Precipitator
Low NOx Burner Technology (Dry Bottom only)
Electrostatic Precipitator
Low NOx Burner Technology w/ Closed‐coupled/SepElectrostatic Precipitator<b
Pipeline NaWet Limestone
Low NOx Burner Technology (Dry Bottom only)<br> Electrostatic Precipitator
Pipeline NaWet Limestone
Low NOx Burner Technology (Dry Bottom only)<br> Electrostatic Precipitator
Wet Limestone
Low NOx Burner Technology w/ Separated OFA<br>Baghouse<br>Electrostatic
Wet Limestone
Low NOx Burner Technology w/ Separated OFA<br>Baghouse<br>Electrostatic
Wet Limestone
Low NOx Burner Technology w/ Separated OFA<br>Baghouse<br>Electrostatic
Residual Oi Wet Limestone
Low NOx Burner Technology w/ Closed‐coupled/SepElectrostatic Precipitator
Residual Oi Wet Limestone
Low NOx Burner Technology w/ Closed‐coupled/SepElectrostatic Precipitator
Diesel Oil Fluidized Bed LimestAmmonia Injection<br>Selective Non‐catalytic ReduBaghouse
Pipeline Natural Gas
Pipeline Natural Gas
Diesel Oil
Electrostatic Precipitator
Electrostatic Precipitator
Water Injection
Diesel Oil
Diesel Oil
Diesel Oil
Diesel Oil
Diesel Oil
Diesel Oil
Diesel Oil
Diesel Oil
Diesel Oil
Diesel Oil
Water Injection
Water Injection
Water Injection
Water Injection
Water Injection
Water Injection
Water Injection
Dry Low NOx Burners
Dry Low NOx Burners
Dry Low NOx Burners
Dry Low NOx Burners
Water Injection<br>Other
Water Injection<br>Other
Pipeline Natural Gas
Pipeline Natural Gas
Overfire Air
Overfire Air
State
MD
MD
MD
MD
MD
MD
MD
MD
MD
MD
MD
MD
MD
MD
MD
MD
MD
MD
MD
MD
MD
MD
MD
MD
MD
MD
MD
MD
MD
MD
MD
MD
MD
MD
MD
MD
MD
MD
MD
MD
MD
MD
MD
MD
MD
MD
Facility ID Facility Name
(ORISPL) Unit ID
Brandon Shores
602
Brandon Shores
602
C P Crane
1552
C P Crane
1552
Herbert A Wagner
1554
Herbert A Wagner
1554
Chalk Point
1571
Chalk Point
1571
Dickerson
1572
Dickerson
1572
Dickerson
1572
Morgantown
1573
Morgantown
1573
AES Warrior Run
10678
Perryman
1556 CT1
Perryman
1556 CT2
Perryman
1556 CT3
Perryman
1556 CT4
Chalk Point
1571 GT2
Morgantown
1573 GT3
Morgantown
1573 GT4
Morgantown
1573 GT5
Morgantown
1573 GT6
Herbert A Wagner
1554
Herbert A Wagner
1554
Gould Street
1553
Perryman
1556 **51
Riverside
1559
Riverside
1559 CT6
Westport
1560 CT5
Chalk Point
1571 **GT3
Chalk Point
1571 **GT4
Chalk Point
1571 **GT5
Chalk Point
1571 **GT6
Chalk Point
1571 SMECO
Dickerson
1572 GT2
Dickerson
1572 GT3
Rock Springs Generati
7835
Rock Springs Generati
7835
Rock Springs Generati
7835
Rock Springs Generati
7835
Brandywine Power Fac
54832
Brandywine Power Fac
54832
Vienna
1564
Chalk Point
1571
Chalk Point
1571
46
1
2
1
2
2
3
1
2
1
2
3
1
2
1
1
4
3
4
1
2
3
4
1
2
8
3
4
Year
2014
2014
2014
2014
2014
2014
2014
2014
2014
2014
2014
2014
2014
2014
2014
2014
2014
2014
2014
2014
2014
2014
2014
2014
2014
2014
2014
2014
2014
2014
2014
2014
2014
2014
2014
2014
2014
2014
2014
2014
2014
2014
2014
2014
2014
2014
# of Associate Program(s Operating Months d Stacks )
Time
Reported
CAIROS
2694.56
5
CAIROS
2915.68
5
CAIROS
116.15
5
CAIROS
1354.74
5
CAIROS
1064.15
5
CAIROS
1217.45
5
CSE12, CSECAIROS
2701.03
5
CSE12, CSECAIROS
1881.16
5
CSDW13, CCAIROS
1516.53
5
CSDW13, CCAIROS
1362.51
5
CSDW13, CCAIROS
1258.92
5
MSFW1, MCAIROS
3374.05
5
MSFW2, MCAIROS
3143.93
5
CAIROS
3118.22
5
CAIROS
27.01
2
CAIROS
7.51
2
CAIROS
9.56
2
CAIROS
16.05
2
CAIROS
5.5
5
CAIROS
7.83
5
CAIROS
10.18
5
CAIROS
8.7
5
CAIROS
5.86
5
CAIROS
583.61
5
CAIROS
17.67
5
CAIROS
150.62
2
CAIROS
136.73
2
CAIROS
188.36
2
CAIROS
0
2
CAIROS
15.88
2
CAIROS
5.35
5
CAIROS
44.23
5
CAIROS
9.34
5
CAIROS
17.77
5
CAIROS
22
5
CAIROS
36.03
5
CAIROS
268.18
5
CAIROS
49.62
2
CAIROS
50.99
2
CAIROS
151.29
2
CAIROS
136.27
2
CAIROS
650.56
2
CAIROS
579.95
2
CAIROS
52.77
5
CAIROS
651.39
5
CAIROS
568.85
5
Avg. NOx Rate Gross (lb/MMBt NOx Load (MW‐ SO2 h)
(tons)
u)
(tons)
1118773 714.035
0.0923 481.504
1185928 721.138
0.0823 520.367
6127.12
15.283
0.3478
14.004
128047.3 395.237
0.2584 232.107
64494.9 619.378
0.2702 123.189
243107.3 1939.889
0.0744
77.046
663037
674.04
0.104 336.469
444415.3 475.359
0.2758 643.567
153946.7
88.577
0.2353 168.696
135311.6
75.303
0.2368 151.326
122786.5
78.383
0.2353 135.847
1281962 582.357
0.0343 197.265
1322639 610.815
0.0379 230.094
481828.2 443.273
0.0676 186.291
1108.46
0.083
0.7706
6.905
213.39
0.019
0.6071
1.293
235.62
0.112
0.592
1.515
553.3
0.045
1.2
5.154
98.9
0.369
1.2007
1.462
198.17
0.545
0.5935
1.045
368
0.808
0.5725
1.519
299.39
0.685
0.5582
1.264
194.26
0.437
0.5782
0.831
10635.97
0.053
0.051
11.759
1916
10.085
0.1336
2.958
5235.64
0.019
0.0951
5.192
18877.62
0.068
0.0819
7.974
6750.58
0.025
0.1587
7.871
1760.56
316.67
2856.99
760.02
1462.07
1315
4457.72
35533.37
7880.39
7928.24
23886.2
21930.9
67241.48
58351.43
1476.84
248428.9
201333.7
8086009
0.008
0.266
0.315
0.003
0.005
0.005
0.016
0.126
0.024
0.024
0.074
0.067
0.159
0.132
16.926
8.395
2.75
0.216
0.1015
0.0837
0.0755
0.0761
0.1219
0.1151
0.126
0.0428
0.0529
0.0402
0.0383
0.0361
0.0337
0.1747
0.0977
0.09
2.966
0.251
1.525
0.344
0.648
1.01
3.071
26.724
1.286
1.743
3.802
3.762
7.477
5.798
4.31
172.288
142.261
3933.78
CO2 (short tons)
1185612
1350937
6958.253
178263.2
82900.89
247198.4
694170.6
458810.7
146402
130102
118103.6
1200504
1266327
572658.7
1291.478
302.296
351.285
696.948
197.6
291.3
432.2
366.4
233.4
10439.08
2764.859
3672.144
13468.51
4866.306
1631.787
334.2
2298.3
533.7
1005.8
977.4
3151.6
25027.2
4845.472
4842.781
14643.02
13370.36
31434.3
26168.12
2491.453
152326.4
135556.3
Heat Input EPA (MMBtu) Region
1.16E+07
1.32E+07
66345.82
1699679
808015.2
2356974
6771596
4476799
1426936
1268059
1151128
1.17E+07
1.23E+07
5583672
15916.41
3724.498
4328.383
8590.53
2435.9
3596.1
5335.8
4523.9
2882.1
175654.8
34076.12
61784.47
226628.5
81874.57
27461.05
4682.1
37823.4
9042.1
17044.9
16565.3
53409.1
424246
81535.67
81488.43
246397.8
224983.3
528935.9
440325.9
30702.41
2569483
2286660
82087413
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
County
Anne Arundel
Anne Arundel
Baltimore
Baltimore
Anne Arundel
Anne Arundel
Prince George's
Prince George's
Montgomery
Montgomery
Montgomery
Charles
Charles
Allegany
Harford
Harford
Harford
Harford
Prince George's
Charles
Charles
Charles
Charles
Anne Arundel
Anne Arundel
Baltimore (City)
Harford
Baltimore
Baltimore
Baltimore (City)
Prince George's
Prince George's
Prince George's
Prince George's
Prince George's
Montgomery
Montgomery
Cecil
Cecil
Cecil
Cecil
Prince George's
Prince George's
Dorchester
Prince George's
Prince George's
Source Category
Electric Utility
Electric Utility
Electric Utility
Electric Utility
Electric Utility
Electric Utility
Electric Utility
Electric Utility
Electric Utility
Electric Utility
Electric Utility
Electric Utility
Electric Utility
Cogeneration
Electric Utility
Electric Utility
Electric Utility
Electric Utility
Electric Utility
Electric Utility
Electric Utility
Electric Utility
Electric Utility
Electric Utility
Electric Utility
Electric Utility
Electric Utility
Electric Utility
Electric Utility
Electric Utility
Electric Utility
Electric Utility
Electric Utility
Electric Utility
Electric Utility
Electric Utility
Electric Utility
Electric Utility
Electric Utility
Electric Utility
Electric Utility
Cogeneration
Cogeneration
Electric Utility
Electric Utility
Electric Utility
Owner
Raven Power Fort Smallw
Raven Power Fort Smallw
C.P. Crane LLC
C.P. Crane LLC
Raven Power Fort Smallw
Raven Power Fort Smallw
GenOn Chalk Point, LLC
GenOn Chalk Point, LLC
GenOn Mid‐Atlantic, LLC
GenOn Mid‐Atlantic, LLC
GenOn Mid‐Atlantic, LLC
GenOn Mid‐Atlantic, LLC
GenOn Mid‐Atlantic, LLC
AES Corporation
Constellation Power Sour
Constellation Power Sour
Constellation Power Sour
Constellation Power Sour
GenOn Mid‐Atlantic, LLC
GenOn Mid‐Atlantic, LLC
GenOn Mid‐Atlantic, LLC
GenOn Mid‐Atlantic, LLC
GenOn Mid‐Atlantic, LLC
Raven Power Fort Smallw
Raven Power Fort Smallw
Constellation Power Sour
Constellation Power Sour
Constellation Power Sour
Constellation Power Sour
Constellation Energy Com
GenOn Chalk Point, LLC
GenOn Chalk Point, LLC
GenOn Chalk Point, LLC
GenOn Chalk Point, LLC
South Maryland Electric C
GenOn Mid‐Atlantic, LLC
GenOn Mid‐Atlantic, LLC
Old Dominion Electric Co
Old Dominion Electric Co
EP Rock Springs, LLC
EP Rock Springs, LLC
Panda Brandywine, LP
Panda Brandywine, LP
Vienna Power, LLC
GenOn Chalk Point, LLC
GenOn Chalk Point, LLC
SO2 NOx Operating Phase
Phase
Status
Unit Type
Fuel Type (Primary)
Facility Name
Phase 2
Phase II GroOperating
Brandon Shores
Dry bottom wall‐fired boileCoal
Brandon Shores
Phase 2
Phase II GroOperating
Dry bottom wall‐fired boileCoal
C P Crane
Table 1
Group 2 Operating
Cyclone boiler
Coal
C P Crane
Table 1
Group 2 Operating
Cyclone boiler
Coal
Herbert A Wagner
Phase 2
Phase II GroOperating
Dry bottom wall‐fired boileCoal
Herbert A Wagner
Phase 2
Phase 2
Operating
Dry bottom wall‐fired boileCoal
Chalk Point
Table 1
Phase 1 GroOperating
Dry bottom wall‐fired boileCoal
Chalk Point
Table 1
Phase 1 GroOperating
Dry bottom wall‐fired boileCoal
Dickerson
Phase 2
Phase II GroOperating
Tangentially‐fired
Coal
Dickerson
Phase 2
Phase II GroOperating
Tangentially‐fired
Coal
Dickerson
Phase 2
Phase II GroOperating
Tangentially‐fired
Coal
Morgantown
Table 1
Phase 1 GroOperating
Tangentially‐fired
Coal
Morgantown
Table 1
Phase 1 GroOperating
Tangentially‐fired
Coal
AES Warrior Run
Operating
Circulating fluidized bed boCoal
Perryman
rce Generation Inc.
Operating
Combustion turbine
Diesel Oil
Perryman
rce Generation Inc.
Operating
Combustion turbine
Diesel Oil
Perryman
rce Generation Inc.
Operating
Combustion turbine
Diesel Oil
Perryman
rce Generation Inc.
Operating
Combustion turbine
Diesel Oil
Chalk Point
Operating
Combustion turbine
Diesel Oil
Morgantown
Operating
Combustion turbine
Diesel Oil
Morgantown
Operating
Combustion turbine
Diesel Oil
Morgantown
Operating
Combustion turbine
Diesel Oil
Morgantown
Operating
Combustion turbine
Diesel Oil
Herbert A Wagner
Phase 2
Operating
Dry bottom wall‐fired boileOther Oil
Herbert A Wagner
Phase 2
Operating
Dry bottom wall‐fired boileOther Oil
Gould Street
Phase 2
Operating
Dry bottom wall‐fired boilePipeline Natural Gas
Perryman
Phase 2
Operating
Combustion turbine
Pipeline Natural Gas
Riverside
Phase 2
Operating
Dry bottom wall‐fired boilePipeline Natural Gas
Riverside
rce Generation Inc.
Operating (Ret Combustion turbine
Pipeline Natural Gas
Westport
mmodities Group, Inc. Operating
Combustion turbine
Pipeline Natural Gas
Chalk Point
Phase 2
Operating
Combustion turbine
Pipeline Natural Gas
Chalk Point
Phase 2
Operating
Combustion turbine
Pipeline Natural Gas
Chalk Point
Phase 2
Operating
Combustion turbine
Pipeline Natural Gas
Chalk Point
Phase 2
Operating
Combustion turbine
Pipeline Natural Gas
Chalk Point
Cooperative
Operating
Combustion turbine
Pipeline Natural Gas
Dickerson
Phase 2
Operating
Combustion turbine
Pipeline Natural Gas
Dickerson
Phase 2
Operating
Combustion turbine
Pipeline Natural Gas
Rock Springs Generati Phase 2
Operating
Combustion turbine
Pipeline Natural Gas
Rock Springs Generati Phase 2
Operating
Combustion turbine
Pipeline Natural Gas
Rock Springs Generati Phase 2
Operating
Combustion turbine
Pipeline Natural Gas
Rock Springs Generati Phase 2
Operating
Combustion turbine
Pipeline Natural Gas
Brandywine Power FacPhase 2
Operating
Combined cycle
Pipeline Natural Gas
Operating
Combined cycle
Pipeline Natural Gas
Brandywine Power FacPhase 2
Phase 2
Operating
Tangentially‐fired
Residual Oil
Vienna
Phase 2
Operating
Tangentially‐fired
Residual Oil
Chalk Point
Phase 2
Operating
Tangentially‐fired
Residual Oil
Chalk Point
Fuel Type (Secondary)
SO2 Control(s) NOx Control(s)
PM Control(s)
Wet Lime FGD Low NOx Burner Technology w/ OvCyclone<br>Baghouse
Wet Limestone Low NOx Burner Technology w/ OvCyclone<br>Baghouse
Overfire Air<br>Combustion ModifBaghouse
Overfire Air<br>Combustion ModifBaghouse
Low NOx Burner Technology (Dry BElectrostatic Precipitator
Low NOx Burner Technology w/ OvElectrostatic Precipitator
Pipeline Natura Wet Limestone Low NOx Burner Technology (Dry BElectrostatic Precipitator
Pipeline Natura Wet Limestone Low NOx Burner Technology (Dry BElectrostatic Precipitator
Wet Limestone Low NOx Burner Technology w/ Se Baghouse<br>Electrostatic Pr
Wet Limestone Low NOx Burner Technology w/ Se Baghouse<br>Electrostatic Pr
Wet Limestone Low NOx Burner Technology w/ Se Baghouse<br>Electrostatic Pr
Residual Oil
Wet Limestone Low NOx Burner Technology w/ CloElectrostatic Precipitator
Residual Oil
Wet Limestone Low NOx Burner Technology w/ CloElectrostatic Precipitator
Diesel Oil
Fluidized Bed Li Ammonia Injection<br>Selective NBaghouse
Pipeline Natural Gas
Pipeline Natural Gas
Diesel Oil
Electrostatic Precipitator
Electrostatic Precipitator
Water Injection
Diesel Oil
Diesel Oil
Diesel Oil
Diesel Oil
Diesel Oil
Diesel Oil
Diesel Oil
Diesel Oil
Water Injection
Water Injection
Water Injection
Water Injection
Water Injection
Water Injection
Water Injection
Dry Low NOx Burners
Dry Low NOx Burners
Dry Low NOx Burners
Dry Low NOx Burners
Diesel Oil, Liquified Petroleum GWater Injection<br>Other
Diesel Oil, Liquified Petroleum GWater Injection<br>Other
Pipeline Natural Gas
Pipeline Natural Gas
Overfire Air
Overfire Air
Appendix C Maryland Coal‐Fired EGUs 24 Hour Block Data Analysis Daily ozone season data for the period of 2007 through 2013 was downloaded from Air Markets Program Data (AMPD), which is maintained by the U.S. EPA (http://ampd.epa.gov/ampd/QueryToolie.html). This data included, but was not limited to: daily NOx emission rate (lbs/MMBtu), NOx emissions per day (tons), operating time (hours), daily heat input (MMBtu), and load (MWh). For each parameter, there are a maximum 153 data points for each ozone season: May 31 days June 30 July 31 August 31 September 30 TOTAL 153 days For each ozone season, the data was sorted from the minimum to the maximum daily NOx emission rate; days which had no operation were not included. Thus, if the unit operated for 100 days, there would be 100 data points with values, and 53 with no values. This accounts for why some ozone seasons extend all the way to the right on the graph (153 data points), and others not. These sorted daily NOx emission rates were plotted along the x‐axis, with the corresponding daily NOx emission rate on the y‐axis. This was done for all coal fired units in Maryland. Currently, all coal fired units in Maryland have either SCR or SNCR post combustion controls. For each ozone season, any daily operation of less than 24 hours was identified by a black box. This was done to determine if start up or shut down (or, operation less than 24 hours per day), contributes to excessive, or, at a minimum, above average daily NOx emission rates, which has been reported by certain operators. Based on a visual examination of the distribution of the black boxes, there is a slight increase in frequency of operating less than 24 hours per day in periods of either above or below average NOx emission rates. However, these periods of operating less than 24 hours (black boxes) also occur during periods reporting average NOx emission rates. Therefore, start up and shut downs are not solely responsible for excessive, or, at a minimum, above average NOx emission rates. On each graph, there is a table reporting the total number of days the unit operated during each ozone season (maximum of 153), along with the number of days operating less than 24 hours; this number corresponds to the number of black boxes for that ozone season. The purpose for this was to first look at operating frequency in general: was the unit operating all 153 days or less, and any recent changes, specifically a reduction, in operating frequency; and secondly to see the number of times the unit was started and shut down during each ozone season, or the number of times the unit was ‘cycled’. Certain operators have reported that they are being both called on less, and ‘cycled’ more in recent years, which has contributed to the above normal average ozone season NOx emission rate during recent years. This is not supported by the data. MDE Regulations Development Division 8/15/14 AES Warrior Run (Coal, SNCR) – Daily OS NOx Emission Rate, Sorted 0.5
NOx Emission Rate (lbs/MMBtu)
0.4
0.3
0.2
0.1
0
2007
2008
2009
2010
2011
2012
2013
2007 < 24hr
2008 < 24hr
2009 < 24hr
2010 < 24hr
2011 < 24hr
2012 < 24hr
2013 < 24hr
Brandon Shores Unit 1 (Coal, SCR) – Daily OS NOx Emission Rate, Sorted 0.5
NOx Emission Rate (lbs/MMBtu)
0.4
0.3
0.2
0.1
0
2007
2008
2009
2010
2011
2012
2013
2007 < 24hr
2008 < 24hr
2009 < 24hr
2010 < 24hr
2011 < 24hr
2012 < 24hr
2013 < 24hr
Brandon Shores Unit 2 (Coal, SCR) – Daily OS NOx Emission Rate, Sorted 0.5
NOx Emission Rate (lbs/MMBtu)
0.4
0.3
0.2
0.1
0
2007
2008
2009
2010
2011
2012
2013
2007 < 24hr
2008 < 24hr
2009 < 24hr
2010 < 24hr
2011 < 24hr
2012 < 24hr
2013 < 24hr
Chalk Point Unit 1 (Coal, SCR) – Daily OS NOx Emission Rate, Sorted 0.5
NOx Emission Rate (lbs/MMBtu)
0.4
0.3
0.2
0.1
0
2007
2008
2009
2010
2011
2012
2013
2007 <24 hr
2008 <24 hr
2009 <24 hr
2010 <24 hr
2011 <24 hr
2012 <24 hr
2013 <24 hr
Chalk Point Unit 2 (Coal, SNCR) – Daily OS NOx Emission Rate, Sorted 0.5
NOx Emission Rate (lbs/MMBtu)
0.4
0.3
0.2
0.1
0
2007
2008
2009
2010
2011
2012
2013
2007 < 24 hr
2008 < 24 hr
2009 < 24 hr
2010 < 24 hr
2011 < 24 hr
2012 < 24 hr
2013 < 24 hr
C.P. Crane Unit 1 (Coal, SNCR) – Daily OS NOx Emission Rate, Sorted 0.5
NOx Emission Rate (lbs/MMBtu)
0.4
0.3
0.2
0.1
0
2007
2008
2009
2010
2011
2012
2013
2007 < 24hr
2008 < 24hr
2009 < 24hr
2010 < 24hr
2011 < 24hr
2012 < 24hr
2013 < 24hr
C.P. Crane Unit 2 (Coal, SNCR) – Daily OS NOx Emission Rate, Sorted 0.5
NOx Emission Rate (lbs/MMBtu)
0.4
0.3
0.2
0.1
0
2007
2008
2009
2010
2011
2012
2013
2007 < 24hr
2008 < 24hr
2009 < 24hr
2010 < 24hr
2011 < 24hr
2012 < 24hr
2013 < 24hr
Dickerson Unit 1 (Coal, SNCR) – Daily OS NOx Emission Rate, Sorted 0.5
NOx Emission Rate (lbs/MMBtu)
0.4
0.3
0.2
0.1
0
2007
2008
2009
2010
2011
2012
2013
2007 < 24hr
2008 < 24hr
2009 < 24hr
2010 < 24hr
2011 < 24hr
2012 < 24hr
2013 < 24hr
Dickerson Unit 2 (Coal, SNCR) – Daily OS NOx Emission Rate, Sorted 0.5
NOx Emission Rate (lbs/MMBtu)
0.4
0.3
0.2
0.1
0
2007
2008
2009
2010
2011
2012
2013
2007 < 24hr
2008 < 24hr
2009 < 24hr
2010 < 24hr
2011 < 24hr
2012 < 24hr
2013 < 24hr
Dickerson Unit 3 (Coal, SNCR) – Daily OS NOx Emission Rate, Sorted 0.5
NOx Emission Rate (lbs/MMBtu)
0.4
0.3
0.2
0.1
0
2007
2008
2009
2010
2011
2012
2013
2007 < 24hr
2008 < 24hr
2009 < 24hr
2010 < 24hr
2011 < 24hr
2012 < 24hr
2013 < 24hr
Morgantown Unit 1 (Coal, SCR) – Daily OS NOx Emission Rate, Sorted 0.5
NOx Emission Rate (lbs/MMBtu)
0.4
0.3
0.2
0.1
0
2007
2008
2009
2010
2011
2012
2013
2007 < 24hr
2008 < 24hr
2009 < 24hr
2010 < 24hr
2011 < 24hr
2012 < 24hr
2013 < 24hr
Morgantown Unit 2 (Coal, SCR) – Daily OS NOx Emission Rate, Sorted 0.5
NOx Emission Rate (lbs/MMBtu)
0.4
0.3
0.2
0.1
0
2007
2008
2009
2010
2011
2012
2013
2007 < 24hr
2008 < 24hr
2009 < 24hr
2010 < 24hr
2011 < 24hr
2012 < 24hr
2013 < 24hr
H.A. Wagner Unit 2 (Coal, SNCR) – Daily OS NOx Emission Rate, Sorted 0.5
NOx Emission Rate (lbs/MMBtu)
0.4
0.3
0.2
0.1
0
2007
2008
2009
2010
2011
2012
2013
2007 < 24hr
2008 < 24hr
2009 < 24hr
2010 < 24hr
2011 < 24hr
2012 < 24hr
2013 < 24hr
H.A. Wagner Unit 3 (Coal, SNCR) – Daily OS NOx Emission Rate, Sorted 0.5
NOx Emission Rate (lbs/MMBtu)
0.4
0.3
0.2
0.1
0
2007
2008
2009
2010
2011
2012
2013
2007 < 24hr
2008 < 24hr
2009 < 24hr
2010 < 24hr
2011 < 24hr
2012 < 24hr
2013 < 24hr
AppendixD
AndoverTechnologyPartnersReport&EPAChapter5
Report 1.
Reliability of SCR and FGD systems for high pollutant Removal
Effieciencies on Coal Fired Utility Boilers
The2004MEGASymposium.Paper#04‐A‐56‐AWMA
PreparedBy:AndoverTechnologiesandtheU.S.EPA
Report 2.
EPA for Transport Rule
Chapter 5 Emission Control Technologies
EPA Base Case v.4.10 includes a major update of emission control technology assumptions. For
this base case EPA contracted with engineering firm Sargent and Lundy to perform a complete
bottom-up engineering reassessment of the cost and performance assumptions for sulfur dioxide
(SO2) and nitrogen oxides (NOX) emission controls.
5.2.1 Combustion Controls
The EPA Base Case v.4.10 representation of combustion controls uses equations that are tailored
to the boiler type, coal type, and combustion controls already in place and allow appropriate
additional combustion controls to be exogenously applied to generating units based on the NOx
emission limits they face. Characterizations of the emission reductions provided by combustion
controls are presented in Table 3-1.3 in Appendix 3-1.
Report 3.
Control Technologies to Reduce Conventional and Hazardous Air
Pollutants from Coal-Fired Power Plants
PreparedFor:
NortheastStatesforCoordinatedAirUseManagement,89SouthStreet,Suite602
Boston,MA
PreparedBy:JamesE.Staudt,Ph.D.AndoverTechnologyPartners,M.J.Bradley&
AssociatesLLC,March31,2011
Summarizes NOx reduction capabilities of SCR and SNCR.
5 Emission Control Technologies
EPA Base Case v.4.10 includes a major update of emission control technology assumptions. For
this base case EPA contracted with engineering firm Sargent and Lundy to perform a complete
bottom-up engineering reassessment of the cost and performance assumptions for sulfur dioxide
(SO2) and nitrogen oxides (NOX) emission controls. In addition to the work by Sargent and Lundy,
Base Case v.4.10 includes two Activated Carbon Injections (ACI) options (Standard and Modified)
for mercury (Hg) control27. Capture and storage options for carbon dioxide (CO2) have also been
added in the new base case.
These emission control options are listed in Table 5-1. They are available in EPA Base Case
v.4.10 for meeting existing and potential federal, regional, and state emission limits. It is important
to note that, besides the emission control options shown in Table 5-1 and described in this
chapter, EPA Base Case v.4.10 offers other compliance options for meeting emission limits.
These include fuel switching, adjustments in the dispatching of electric generating units, and the
option to retire a unit.
Table 5-1 Summary of Emission Control Technology Retrofit Options in EPA Base Case
v.4.10
SO2 Control
NOX Control
Hg Control
CO2 Control
Technology Options Technology Options
Technology Options
Technology Options
Limestone Forced
Selective Catalytic
Standard Activated
CO2 Capture and
Oxidation (LSFO)
Reduction (SCR)
Carbon Injection (SPACSequestration
Scrubber
System
ACI) System
Selective NonModified Activated
Lime Spray Dryer
Catalytic Reduction
Carbon Injection
(LSD) Scrubber
(SNCR) System
(MPAC-ACI) System
SO2 and NOX Control
Combustion Controls
Technology Removal
Cobenefits
5.1 Sulfur Dioxide Control Technologies
Two commercially available Flue Gas Desulfurization (FGD) technology options for removing the
SO2 produced by coal-fired power plants are offered in EPA Base Case v.4.10: Limestone Forced
Oxidation (LSFO) — a wet FGD technology — and Lime Spray Dryer (LSD) — a semi-dry FGD
technology which employs a spray dryer absorber (SDA). In wet FGD systems, the polluted gas
stream is brought into contact with a liquid alkaline sorbent (typically limestone) by forcing it
through a pool of the liquid slurry or by spraying it with the liquid. In dry FGD systems the polluted
gas stream is brought into contact with the alkaline sorbent in a semi-dry state through use of a
spray dryer. The removal efficiency for SDA drops steadily for coals whose SO2 content exceeds
3lb SO2/MMBtu, so this technology is provided only to plants which have the option to burn coals
with sulfur content no greater than 3 lbs SO2/MMBtu. In EPA Base Casev.4.10 when a unit
retrofits with an LSD SO2 scrubber, it loses the option of burning BG, BH, and LG coals due to
their high sulfur content.
In EPA Base Case v.4.10 the LSFO and LSD SO2 emission control technologies are available to
existing "unscrubbed" units. They are also available to existing "scrubbed" units with reported
removal efficiencies of less than fifty percent. Such units are considered to have an injection
technology and classified as “unscrubbed” for modeling purposes in the NEEDS database of
27
The mercury emission controls options and assumptions in EPA Base Case v.4.10 do not reflect
mercury control updates that are currently under way at EPA in support of the Utility MACT
initiative and do not make use of data collected under EPA’s 2010 Information Collection Request
(ICR).
5-1
existing units which is used in setting up the EPA base case. The scrubber retrofit costs for these
units are the same as regular unscrubbed units retrofitting with a scrubber. Scrubber efficiencies
for existing units were derived from data reported in EIA Form 767. In transferring this data for
use in EPA Base Case v.4.10 the following changes were made. The maximum removal
efficiency was set at 98% for wet scrubbers and 93% for dry scrubber units. Existing units
reporting efficiencies above these levels in Form 767 were assigned the maximum removal
efficiency in NEEDS v.4.10 indicated in the previous sentence.
As shown in Table 5-2, existing units that are selected to be retrofitted by the model with
scrubbers are given the maximum removal efficiencies of 98% for LSFO and 93% for LSD. The
procedures used to derive the cost of each scrubber type are discussed in detail in the following
sections.
Table 5-2 Summary of Retrofit SO2 Emission Control Performance Assumptions
Performance
Limestone Forced
Lime Spray Dryer (LSD)
Assumptions
Oxidation (LSFO)
Percent Removal
Capacity Penalty
Heat Rate Penalty
Cost (2007$)
Applicability
Sulfur Content
Applicability
Applicable Coal Types
98%
with a floor of 0.06 lbs/MMBtu
93%
with a floor of 0.065 lbs/MMBtu
Calculated based on
characteristics of the unit:
See Table 5-4 for examples
Calculated based on
characteristics of the unit:
See Table 5-4 for examples
Units ≥ 25 MW
Units ≥ 25 MW
Coals ≤ 3 lbs SO2/MMBtu
BA, BB, BD, BE, BG, BH, SA,
SB, SD, LD, LE, and LG
BA, BB, BD, BE, SA, SB, SD,
LD, and LE
Potential (new) coal-fired units built by the model are also assumed to be constructed with a
scrubber achieving a removal efficiency of 98% for LSFO and 93% for LSD. In EPA Base Case
v.4.10 the costs of potential new coal units include the cost of scrubbers.
5.1.1 Methodology for Obtaining SO2 Controls Costs
The Sargent and Lundy update of SO2 and NOx control costs is notable on several counts. First, it
brought costs up to levels seen in the marketplace in 2009. Incorporating these costs into EPA’s
base case carries an implicit assumption, not universally accepted, that the run up in costs seen
over the preceding 5 years and largely attributed to international competition, is permanent and
will not settle back to pre-2009 levels. Second, a revised methodology, based on Sargent and
Lundy’s expert experience, was used to build up the capital, fixed and variable operating and
maintenance components of cost. That methodology, which employed an engineering build up of
each component of cost, is described here and in the following sections. Detailed example cost
calculation spreadsheets for both SO2 and NOx controls are included in Appendices 5-1 and 5-2
respectively. The Sargent and Lundy reports in which these spreadsheets appeared can be
downloaded via links to the Appendices 5-1A, 5-1B, 5-2A, and 5-2B links found at
www.epa.gov/airmarkets/progsregs/epaipm/BaseCasev410.html.
Capital Costs: In building up capital costs three separate cost modules were included for LSD and
four for LSFO: absorber island, reagent preparation, waste handling (LSFO only), and everything
else (also called “balance of plant”) with the latter constituting the largest cost module, consisting
of fans, new wet chimney, piping, ductwork, minor waste water treatment, and other costs
required for treatment. For each of the four modules the cost of foundations, buildings, electrical
equipment, installation, minor, physical and chemical wastewater treatment, and average retrofit
difficulty were taken into account.
5-2
The governing cost variables for each module are indicated in Table 5-3. The major variables
affecting capital cost are unit size and the SO2 content of the fuel with the latter having the
greatest impact on the reagent and waste handling facilities. In addition, heat rate affects the
amount of flue gas produced and consequently the size of each of the modules. The quantity of
flue gas is also a function of coal rank since different coals have different typical heating values.
Table 5-3 Capital Cost Modules and Their Governing Variables for SO2 and NOx Emission
Controls
Module
Retrofit
Difficulty
(1 =
average)
Coal Rank
Factor
(Bit = 1,
PRB = 1.05,
Lignite = 1.07)
Heat Rate
(Btu/kWh)
SO2 Rate
(lb/MMBtu)
NOx Rate
(lb/MMBtu)5
Unit
Size
(MW)
SO2 Emission Controls – Wet FGD and SDA FGD
Absorber
Island
X
Reagent
Preparation
X
X
X
X
X
X
X
X
Waste
Handling
X
X
X
X
Balance of
Plant1
X
X
X
X
NOx Emission Controls – SCR and SNCR
SCR/SNCR
Island2
X
X
X3
X
Reagent
Preparation3
X
X
Air Heater
Modification4
X
X
X
Balance of
Plant5 – SCR
X
X
X
Balance of
Plant1 –
SNCR
X
X
X
X
X
Notes:
1
“Balance of plant” costs include such cost items as ID and booster fans, new wet chimneys,
piping, ductwork, minor waste water treatment, auxiliary power modifications, and other electrical
and site upgrades.
2
The SCR island module includes the cost of inlet ductwork, reactor, and bypass. The SNCR
island module includes cost of injectors, blowers, distributed control system (DCS), and reagent
system.
3
Only applies to SCR.
4
On generating units that burn bituminous coal whose SO2 and content exceeds 3 lbs/MMBtu, air
heater modifications used to control SO3 are needed in conjunction with the operation of SCR and
SNCR.
5
For SCR, the NOx rate is frequently expressed through the calculated NOx removal efficiency.
5-3
Once the key variables that figure in the cost of the four modules are identified, they are used to
derive costs for each base module in equations developed by Sargent and Lundy based on their
experience with multiple engineering projects. The base module costs are summed to obtain total
bare module costs. This total is increased by 30% to account for additional engineering and
construction fees. The resulting value is the capital, engineering, and construction cost (CECC)
subtotal. To obtain the total project cost (TPC), the CECC subtotal is increased by 5% to account
for owner’s home office costs, i.e., owner’s engineering, management, and procurement costs.
The resulting sum is then increased by another 10% to build in an Allowance for Funds used
During Construction (AFUDC) over the 3-year engineering and construction cycle. The resulting
value, expressed in $/kW, is the capital cost factor that is used in EPA Base Case v.4.10.
Variable Operating and Maintenance Costs (VOM): These are the costs incurred in running the
emission control device. They are proportional to the electrical energy produced and are
expressed in units of $ per MWh. For FGD, Sargent and Lundy identified four components of
VOM: (a) costs for reagent usage, (b) costs for waste generation, (c) make up water costs, and
(d) cost of additional power required to run the control (often called the “parasitic load”). For a
given coal rank and a pre-specified SO2 removal efficiency, each of these components of VOM
cost is a function of the generating unit’s heat rate (Btu/kWh) and the sulfur content (lb
SO2/MMBtu) of the coal (also referred to as the SO2 feed rate). For purposes of modeling, the
total VOM includes the first three of these component costs. The last component – cost of
additional power – is factored into IPM, not in the VOM value, but through a capacity and heat rate
penalty as described in the next paragraph. Due to the differences in the removal processes, the
per MWh cost for waste handling, makeup water, and auxiliary power tend to be higher for LSFO
while reagent usage cost and total VOM (excluding parasitic load) are higher for LSD.
Capacity and Heat Rate Penalty: The amount of electrical power required to operate the FGD
device is represented through a reduction in the amount of electricity that is available for sale to
the grid. For example, if 1.6% of the unit’s electrical generation is needed to operate the scrubber,
the generating unit’s capacity is reduced by 1.6%. This is the “capacity penalty.” At the same
time, to capture the total fuel used in generation both for sale to the grid and for internal load (i.e.,
for operating the FGD device), the unit’s heat rate is scaled up such that a comparable reduction
(1.6% in the previous example) in the new higher heat rate yields the original heat rate28. The
factor used to scale up the original heat rate is called “heat rate penalty.” It is a modeling
procedure only and does not represent an increase in the unit’s actual heat rate (i.e., a decrease
in the unit’s generation efficiency). Unlike previous base cases, which assumed a generic heat
rate and capacity penalties for all installations, in EPA Base Case v.4.10 specific LSFO and LSD
heat rate and capacity penalties are calculated for each installation based on equations developed
by Sargent and Lundy that take into account the rank of coal burned, its SO2 rate, and the heat
rate of the model plant.
Fixed Operating and Maintenance Costs (FOM): These are the annual costs of maintaining a unit.
They represent expenses incurred regardless of the extent to which the emission control system
is run. They are expressed in units of $ per kW per year. In calculating FOM Sargent and Lundy
took into account labor and materials costs associated with operations, maintenance, and
administrative functions. The following assumptions were made:
28
Mathematically, the relationship of the heat rate and capacity penalties (both expressed as
positive percentage values) can be represented as follows:
⎞
⎛
⎟
⎜
1
⎜
Heat Rate Penalty =
− 1⎟ × 100
⎜ ⎛ Capacity Penalty ⎞ ⎟
⎟ ⎟
⎜ ⎜1 −
100
⎠ ⎠
⎝⎝
5-4
•
•
•
FOM for operations is based on the number of operators needed which is a function of the
size (i.e., MW capacity) of the generating unit and the type of FGD control. For LSFO 12
additional operators were assumed to be required for a 500 MW or smaller installation and 16
for a unit larger than 500 MW. For LSD 8 additional operators were assumed to be needed.
FOM for maintenance is a direct function of the FGD capital cost
FOM for administration is a function of the FOM for operations and maintenance.
Table 5-4 presents the capital, VOM, and FOM costs as well as the capacity and heat rate penalty
for the two SO2 emission control technologies (LSFO and LSD) included in EPA Base Case v.4.10
for an illustrative set of generating units with a representative range of capacities and heat rates.
5-5
Table 5-4 Illustrative Scrubber Costs (2007$) for Representative Sizes and Heat Rates under the Assumptions in EPA Base Case v.4.10
Capacity (MW)
Scrubber Type
LSFO
Minimum Cutoff:
≥ 25 MW
Maximum Cutoff:
None
Assuming 3
lb/MMBtu SO2
Content
Bituminous Coal
LSD
Minimum Cutoff:
≥ 25 MW
Maximum Cutoff:
None
Assuming 2
lb/MMBtu SO2
Content
Bituminous Coal
Heat Rate
(Btu/kWh)
Capacity
Penalty
(%)
Heat
Rate
Penalty
(%)
9,000
-1.5
1.53
10,000
-1.67
11,000
Variable
O&M
(mills/kWh)
100
300
500
700
1000
Capital
Cost
($/kW)
Fixed
O&M
($/kW-yr)
Capital
Cost
($/kW)
Fixed
O&M
($/kW-yr)
Capital
Cost
($/kW)
Fixed
O&M
($/kW-yr)
1.66
747
22.5
547
10.5
473
7.8
430
7.2
388
5.9
1.7
1.84
783
22.8
573
10.8
496
8.0
451
7.4
407
6.1
-1.84
1.87
2.03
817
23.2
598
11.0
517
8.2
470
7.6
425
6.3
9,000
-1.18
1.2
2.13
641
16.4
469
8.1
406
6.1
385
5.3
385
4.9
10,000
-1.32
1.33
2.36
670
16.7
491
8.3
424
6.3
403
5.5
403
5.1
11,000
-1.45
1.47
2.60
698
17.0
511
8.5
442
6.5
420
5.7
420
5.2
5-6
Capital
Capital
Fixed O&M
Cost
Cost
($/kW-yr)
($/kW)
($/kW)
Fixed
O&M
($/kW-yr)
5.2 Nitrogen Oxides Control Technology
The EPA Base Case v.4.10 includes two categories of NOx reduction technologies: combustion
and post-combustion controls. Combustion controls reduce NOx emissions during the combustion
process by regulating flame characteristics such as temperature and fuel-air mixing. Postcombustion controls operate downstream of the combustion process and remove NOx emissions
from the flue gas. All the specific combustion and post-combustion technologies included in EPA
Base Case v.4.10 are commercially available and currently in use in numerous power plants.
5.2.1 Combustion Controls
The EPA Base Case v.4.10 representation of combustion controls uses equations that are tailored
to the boiler type, coal type, and combustion controls already in place and allow appropriate
additional combustion controls to be exogenously applied to generating units based on the NOx
emission limits they face. Characterizations of the emission reductions provided by combustion
controls are presented in Table 3-1.3 in Appendix 3-1. The EPA Base Case v.4.10 cost
assumptions for NOx Combustion Controls are summarized in Table 5-5. Table 5-6 provides a
mapping of existing coal unit configurations and incremental combustion controls applied in EPA
Base Case v.4.10 to achieve state-of-the-art combustion control configuration.
Table 5-5 Cost (2007$) of NOx Combustion Controls for Coal Boilers (300 MW Size)
Fixed
Capital
O&M
Variable O&M
Boiler Type
Technology
($/kW)
($/kW(mills/kWh)
yr)
Low NOx Burner without Overfire Air
45
0.3
0.07
Dry Bottom Wall- (LNB without OFA)
Fired
Low NOx Burner with Overfire Air
61
0.4
0.09
(LNB with OFA)
Low NOx Coal-and-Air Nozzles with
24
0.2
0.00
Close-Coupled Overfire Air (LNC1)
Low NOx Coal-and-Air Nozzles with
Tangentially33
0.2
0.03
Separated Overfire Air (LNC2)
Fired
Low NOx Coal-and-Air Nozzles with
Close-Coupled and Separated
38
0.3
0.03
Overfire Air (LNC3)
Vertically-Fired
NOx Combustion Control
29
0.2
0.06
Scaling Factor
The following scaling factor is used to obtain the capital and fixed operating and maintenance
costs applicable to the capacity (in MW) of the unit taking on combustion controls. No scaling
factor is applied in calculating the variable operating and maintenance cost.
LNB without OFA & LNB with OFA = ($ for X MW Unit) = ($ for 300 MW Unit) x (300/X)0.359
LNC1, LNC2 and LNC3 = ($ for X MW Unit) = ($ for 300 MW Unit) x (300/X)0.359
Vertically-Fired = ($ for X MW Unit) = ($ for 300 MW Unit) x (300/X)0.553
where
($ for 300 MW Unit) is the value obtained using the factors shown in the above table and
X is the
capacity (in MW) of the unit taking on combustion controls.
5-7
Table 5-6 Incremental Combustion NOx Controls in EPA Base Case v.4.10
Existing NOx
Boiler Type
Incremental Combustional Control
Combustion Control
LNB
OFA
Cell
NGR
LNB AND OFA
Cyclone
-OFA
Stoker/SPR
-OFA
-LNC3
LA
LNC3
LNB
CONVERSION FROM LNC1 TO LNC3
LNB + OFA
CONVERSION FROM LNC1 TO LNC3
Tangential
LNC1
CONVERSION FROM LNC1 TO LNC3
LNC2
CONVERSION FROM LNC2 TO LNC3
OFA
LNC1
ROFA
LNB
Vertical
-NOx Combustion Control - Vertically Fired Units
-LNB AND OFA
LA
LNB AND OFA
LNB
OFA
Wall
LNF
OFA
OFA
LNB
5.2.2 Post-combustion Controls
The EPA Base Case v.4.10 includes two post-combustion retrofit control technologies for existing
coal units: Selective Catalytic Reduction (SCR) and Selective Non-Catalytic Reduction (SNCR). In
EPA Base Case v.4.10 oil/gas steam units are eligible for SCR only. NOx reduction in an SCR
system takes place by injecting ammonia (NH3) vapor into the flue gas stream where the NOx is
reduced to nitrogen (N2) and water H2O abetted by passing over a catalyst bed typically
containing titanium, vanadium oxides, molybdenum, and/or tungsten. As its name implies, SNCR
operates without a catalyst. In SNCR a nitrogenous reducing agent (reagent), typically ammonia
or urea, is injected into, and mixed with, hot flue gas where it reacts with the NOx in the gas
stream reducing it to nitrogen gas and water vapor. Due to the presence of a catalyst, SCR can
achieve greater NOx reductions than SNCR. However, SCR costs are higher.
Table 5-7 summarizes the performance and applicability assumptions in EPA Base Case v.4.10
for each NOx post-combustion control technology and provides a cross reference to information on
cost assumptions.
Table 5-7 Summary of Retrofit NOx Emission Control Performance Assumptions
Control
Selective Non-Catalytic
Selective Catalytic Reduction
Performance
Reduction
(SCR)
Assumptions
(SNCR)
Unit Type
Coal
Oil/Gas
Coal
Pulverized Coal: 35%
90% down to 0.06
Percent Removal
80%
lb/MMBtu
Fluidized Bed: 50%
Size Applicability
Units ≥ 25 MW
Units ≥ 25 MW
Units ≥ 25 MW
Costs (2007$)
See Table 5-8
See Table 5-9
See Table 5-8
5-8
Potential (new) coal-fired, combined cycle, and IGCC units are modeled to be constructed with
SCR systems and designed to have emission rates ranging between 0.01 and 0.06 lb
NOx/MMBtu. EPA Base Case v.4.10 cost assumptions for these units include the cost of SCR
5.2.3 Methodology for Obtaining SCR Costs for Coal Units
As with the update of SO2 control costs, Sargent and Lundy employed an engineering build-up of
the capital, fixed and variable operating and maintenance components of cost to update postcombustion NOx control costs. This section describes the approach used for SCR. The next
section treats SNCR. Detailed example cost calculation spreadsheets for both technologies can
be found in Appendix 5-2.
For cost calculation purposes the Sargent and Lundy methodology calculates plant specific NOx
removal efficiencies, i.e., the percent difference between the uncontrolled NOx rate29 for a model
plant and the cost calculation floor NOx rate corresponding to the predominant coal rank used at
the plant ( 0.07 lb/MMBtu for bituminous and 0.05 lb/MMBtu for subbitumionus and lignite coals).
For example, a plant that burns subbitumionus coal with an uncontrolled NOx rate of 0.1667
lb/MMBtu, and a cost calculation floor NOx rate of 0.05 lb/MMBtu would have a removal efficiency
of 70%, i.e., (0.1667 – 0.05)/0.1667 = 0.1167/0.1667 = .70. The NOx removal efficiency so
obtained figures in the capital, VOM, and FOM components of SCR cost.
Capital Costs: In building up SCR capital costs, four separate cost modules were included: SCR
island (e.g., inlet ductwork, reactor, and bypass), reagent preparation, air pre-heater modification,
and balance of plan (e.g., ID or booster fans, piping, and auxiliary power modification). Air preheater modification cost only applies for plants that burn bituminous coal whose SO2 content is 3
lbs/MMBtu or greater, where SO3 control is necessary. Otherwise, there is no air pre-heat cost.
For each of the four modules the cost of foundations, buildings, electrical equipment, installation,
and average retrofit difficulty were taken into account.
The governing cost variables for each module are indicated in Table 5-3. All four capital cost
modules, except reagent preparation, are functions of retrofit difficulty, coal rank, heat rate, and
unit size. NOx rate (expressed via the NOx removal efficiency) affects the SCR and reagent
preparation cost modules. Not shown in Table 5-3, heat input (in Btu/hr) also impacts reagent
preparation costs. As noted above, the SO2 rate becomes a factor in SCR cost for plants that
combust bituminous coal with 3 lbs SO2/MMBtu or greater, where air pre-heater modifications are
needed for SO3 control.
As with FGD capital costs, the base module costs for SCR are summed to obtain total bare
module costs. This total is increased by 30% to account for additional engineering and
construction fees. The resulting value is the capital, engineering, and construction cost (CECC)
subtotal. To obtain the total project cost (TPC) the CECC subtotal is increased by 5% to account
for owner’s home office costs, i.e., owner’s engineering, management, and procurement costs.
Whereas the resulting sum is then increased by another 10% for FGD, for SCR it is increased by
6% to factor in an Allowance for Funds used During Construction (AFUDC) over the 2-year
engineering and construction cycle (in contrast to the 3-year cycle assumed for FGD). The
resulting value, expressed in $/MW, is the capital cost factor that is used in EPA Base Case
v.4.10.
Variable Operating and Maintenance Costs (VOM): For SCR Sargent and Lundy identified four
components of VOM: (a) costs for the urea reagent, (b) costs of catalyst replacement and
disposal, (c) cost of required steam, and (d) cost of additional power required to run the control
29
More precisely, the uncontrolled NOX rate for a model plant in EPA Base Case v.4.10 is the
capacity weighted average of the Mode 1 NOX rates of the generating units comprising the model
plant. The meaning of “Mode 1 NOX rate” is discussed in section 3.9.2 and Appendix 3-1 (“NOX
Rate Development in EPA Base Case v.4.10).
5-9
(i.e., the “parasitic load”). As was the case for FGD, the last component – cost of additional power
– is factored into IPM, not in the VOM value, but through a capacity and heat rate penalty as
described earlier. Of the first three of these component costs, reagent cost and catalyst
replacement are predominant while steam cost is much lower in magnitude. NOx rates and heat
rates are key determinates of reagent and steam costs, while NOx rate (via removal efficiency),
capacity factor, and coal rank are key drivers of catalyst replacement costs.
Capacity and Heat Rate Penalty:
Unlike previous base cases, which assumed a generic heat rate and capacity penalties for all
installations, in EPA Base Case v.4.10 specific SCR heat rate and capacity penalties are
calculated for each installation based on equations developed by Sargent and Lundy that take into
account the rank of coal burned, its SO2 rate, and the heat rate of the model plant.
Fixed Operating and Maintenance Costs (FOM): For SCR the following assumptions were made:
•
•
•
FOM for operations is based on the assumption that one additional operator working half-time
is required.
FOM for maintenance is assumed to $193,585 (in 2007$) for generating units less than 500
MW and $290,377 (in 2007$) for generating units 500 MW or greater
There was assumed to be no FOM for administration for SCR.
Table 5-8 presents the SCR and SNCR capital, VOM, and FOM costs and capacity and heat rate
penalties for an illustrative set of coal generating units with a representative range of capacities,
heat rates, and NOx removal efficiencies. The illustrations include and identify plants that do and
do not burn bituminous coal with 3 lbs SO2/MMBtu or greater.
5-10
Table 5-8 Illustrative Post Combustion NOX Controls for Coal Plants Costs (2007$) for Representative Sizes and Heat Rates under the
Assu Assumptions in EPA Base Case v.4.10
Capacity (MW)
Control Type
SCR
Minimum Cutoff:
≥ 25 MW
Maximum Cutoff: None
Assuming Bituminous Coal
NOx rate: 0.5 lb/MMBtu
SO2 rate: 2.0 lb/MMBtu
SNCR - Non-FBC
Minimum Cutoff:
≥ 25 MW
Maximum Cutoff: None
Assuming Bituminous Coal
NOx rate: 0.5 lb/MMBtu
SO2 rate: 2.0 lb/MMBtu
SNCR - Fluidized Bed
Minimum Cutoff:
≥ 25 MW
Maximum Cutoff: None
Assuming Bituminous Coal
NOx rate: 0.5 lb/MMBtu
SO2 rate: 2.0 lb/MMBtu
Heat Rate
(Btu/kWh)
Capacity
Penalty
(%)
Heat
Rate
Penalty
(%)
9,000
-0.54
0.54
10,000
-0.56
11,000
-0.58
Variable
O&M
(mills/kWh)
100
300
Capital
Cost
($/kW)
Fixed
O&M
($/kWyr)
1.15
221
0.56
1.24
0.59
500
700
Capital
Cost
($/kW)
Fixed
O&M
($/kWyr)
2.5
177
240
2.5
1.33
258
2.5
0.88
45
1
0.98
47
1
11,000
1.08
48
1
9,000
0.88
34
0.9
18
0.4
14
0.2
0.98
35
0.9
19
0.4
14
1.08
36
0.9
19
0.4
14
9,000
10,000
10,000
11,000
-0.05
-0.05
0.05
0.05
Capital
Cost
($/kW)
Fixed
O&M
($/kWyr)
0.8
163
193
0.8
209
0.8
1000
Capital
Cost
($/kW)
Fixed
O&M
($/kWyr)
Capital
Cost
($/kW)
Fixed
O&M
($/kWyr)
0.7
155
0.5
147
0.4
178
0.7
169
0.5
162
0.4
193
0.7
184
0.5
176
0.4
11
0.2
9
0.1
0.2
12
0.2
10
0.1
0.2
12
0.2
10
0.1
Size Not Modeled
Note:
If a coal plant burns bituminous coal with a SO2 content above 3.0 lb/MMBtu then the capital costs will increase due to the required air preheater modification. For example, a 100
MW coal boiler with an SCR burning bituminous coal at a heat rate of 11,000 Btu/kWh and an SO2 rate of 4.0 lb/MMBtu will have a capital cost of 296 $/kW, a 36 $/kW increase in
capital costs from an identical boiler burning coal with an SO2 rate of 2.0 lb/MMBtu.
5-11
5.2.4 Methodology for Obtaining SCR Costs for Oil/Gas Steam units
The cost calculations for SCR described in section 5.2.3 apply to coal units. For SCR on oil/gas
steam units the cost calculation procedure employed in EPA’s most recent previous base case
was used. However, capital costs were scaled up by 2.13 to account for increases in the
component costs that had occurred since the assumptions were incorporated in that base case.
All costs were expressed in constant 2007$ for consistency with the dollar year cost basis used
throughout EPA Base Case v4.10. Table 5-9 shows that resulting capital, FOM, and VOM cost
assumptions for SCR on oil/gas steam units. The scaling factor for capital and fixed operating and
maintenance costs, described in footnote 1, applies to all size units from 25 MW and up.
Table 5-9 Post-Combustion NOX Controls for Oil/Gas Steam Units in EPA Base Case v.4.10
Post-Combustion
Capital
Fixed O&M
Variable O&M
Percent
Control Technology
($/kW)
($/kW-yr)
(mills/kWh)
Removal
SCR1
80%
75
1.08
0.12
Notes:
The “Coefficients” in the table above are multiplied by the terms below to determine costs.
“MW” in the terms below is the unit’s capacity in megawatts.
This data is used in the generation of EPA Base Case v.4.0
1
SCR Cost Equations:
SCR Capital Cost and Fixed O&M: (200/MW)0.35
The scaling factors shown above apply up to 500 MW. The cost obtained for a 500 MW
unit applies for units larger than 500 MW.
Example for 275 MW unit:
SCR Capital Cost ($/kW) = 75 * (200/275)0.35 ≈ 67 $/kW
SCR FOM Cost ($/kW-yr) = 1.08 * (200/275)0.35 ≈ 0.97 $/kW-yr
SCR VOM Cost (mills/kWh) = 0.12 mills/kWh
Reference:
Cost Estimates for Selected Applications of NOX Control Technologies on Stationary
Combustion Boilers, Bechtel Power Corporation for US EPA, June 1997
5.2.5 Methodology for Obtaining SNCR Costs
In the Sargent and Lundy cost update for SNCR a generic NOX removal efficiency of 25% is
assumed. However, the capital, fixed and variable operating and maintenance costs of SNCR on
circulating fluidized bed (CFB) units are distinguished from the corresponding costs for other boiler
types (e.g. cyclone, and wall fired).
Capital Costs: Due to the absence of a catalyst and, with it, the elimination of the need for more
extensive reagent preparation, the Sargent and Lundy engineering build up of SNCR capital costs
includes three rather than four separate cost modules: SNCR (injectors, blowers, distributive
control system, reagent system), air pre-heater modification, and balance of plan (e.g., ID or
booster fans, piping, and auxiliary power modification). For CFB units, the SNCR and balance of
plan module costs are 75% of what they are on other boiler types. The air pre-heater modification
cost module is the same as for SCR and there is no cost difference between CFB and other boiler
types. As with SCR the air heater modification cost only applies for plants that burn bituminous
coal whose SO2 content is 3 lbs/MMBtu or greater, where SO3 control is necessary. Otherwise,
there is no air pre-heat cost. For each of the three modules the cost of foundations, buildings,
electrical equipment, installation, and average retrofit difficulty were taken into account.
The governing cost variables for each module are indicated in Table 5-3. Unit size affects all
three modules. Retrofit difficulty, coal rank, and heat rate impact the SNCR and air heater
modification modules. The SO2 rate impacts the air pre-heater modification module. NOX rate
5-12
(expressed via the NOX removal efficiency) and heat input (not shown in Table 5-3) affect the
balance of plan module.
The base module costs for SNCR are summed to obtain total bare module costs. This total is
increased by 30% to account for additional engineering and construction fees. The resulting value
is the capital, engineering, and construction cost (CECC) subtotal. To obtain the total project cost
(TPC) the CECC subtotal is increased by 5% to account for owner’s home office costs, i.e.,
owner’s engineering, management, and procurement costs. Since SNCR projects are typically
completed in less than a year, there is no Allowance for Funds used During Construction
(AFUDC) in the SNCR capital cost factor that is used in EPA Base Case v.4.10.
Variable Operating and Maintenance Costs (VOM): Sargent and Lundy identified two components
of VOM for SNCR: (a) cost for the urea reagent and (b) the cost of dilution water. The magnitude
of the reagent cost predominates the VOM with the cost of dilution water at times near zero.
There is no capacity or heat rate penalty associated with SNCR since the only impact on power
are compressed air or blower required for urea injection and the reagent supply system.
Capacity and Heat Rate Penalty:
Unlike previous base cases, which assumed a generic heat rate and capacity penalties for all
installations, in EPA Base Case v.4.10 specific SNCR heat rate and capacity penalties are
calculated for each installation based on equations developed by Sargent and Lundy that take into
account the rank of coal burned, its SO2 rate, and the heat rate of the model plant.
Fixed Operating and Maintenance Costs (FOM): The assumptions for FOM for operations and
for administration are the same for SNCR as for SCR, i.e.,
•
•
FOM for operations is based on the assumption that one additional operator working half-time
is required.
There was assumed to be no FOM for administration for SCR.
FOM for maintenance materials and labor was assumed to be a direct function of base module
cost, specifically, 1.2% of those costs divided by the capacity of the generating unit expressed in
kilowatts.
Detailed example cost calculation spreadsheets for SNCR can be found in Appendix 5-2.
5.2.6 SO2 and NOx Controls for Units with Capacities from 25 MW to 100 MW (25 M ≤
capacity < 100 MW)
In EPA Base Case v.4.10 coal units with capacities between 25 MW and 100 MW are offered the
same SO2 and NOx emission control options as larger units. However, for purposes of modeling,
the costs of controls for these units are assumed to be equivalent to that of a 100 MW unit. This
assumption is based on several considerations. First, to achieve economies of scale, several
units in this size range are likely to be ducted to share a single common control, so the 100 MW
cost equivalency assumption, though generic, would be technically plausible. Second, single units
in this size range that are not grouped to achieve economies of scale are likely to have the option
of hybrid multi-pollutant controls currently under development.30 These hybrid controls achieve
cost economies by combining SO2, NOX and particulate controls into a single control unit. Singly,
the costs of the individual control would be higher for units below 100 MW than for a 100 MW unit,
30
See, for example, the Greenidge Multi-Pollutant Control Project, which was part of the U.S.
Department of Energy, National Energy Technology Lab’s Power Plant Improvement Initiative. A
joint effort of CONSOL Energy Inc. AES Greenidge LLC, and Babcock Power Environmental, Inc.,
information on the project can be found at
www.netl.doe.gov/technologies/coalpower/cctc/PPII/bibliography/demonstration/environmental/bib
_greenidge.html.
5-13
but when combined in the Multi-Pollutant Technologies (MPTs) their costs would be roughly
equivalent to the cost of individual controls on a 100 MW unit. While MPTs are not explicitly
represented in EPA Base Case v.4.10, single units in the 25-100 MW range that take on
combinations of SO2 and NOX controls in a model run can be thought of as being retrofit with an
MPT.
Illustrative scrubber, SCR, and SNCR costs for 25-100 MW coal units with a range heats rates
can be found by referring to the 100 MW “Capital Costs ($/kW)” and “Fixed O&M” columns in
Table 5-4 and Table 5-8. The Variable O&M cost component, which applies to units regardless of
size, can be found in the fifth column in these tables.
5.3 Biomass Co-firing
Under most climate policies currently being discussed, biomass is treated as “carbon neutral,” i.e.,
a zero contributor of CO2 to the atmosphere. The reasoning is that the CO2 emitted in the
combustion of biomass will be reabsorbed via photosynthesis in plants grown to replace the
biomass that was combusted. Consequently, if a power plant can co-fire biomass and thereby
replace a portion of fossil fuel, it reduces its CO2 emissions by approximately the same proportion,
although combustion efficiency losses may somewhat diminish the proportion of CO2 reduction.
Roughly speaking, by co-firing enough biomass to produce 10% of a coal plant’s power output, a
co-fired plant can realize close to an effective 10% reduction in CO2 emitted.
Biomass co-firing is provided as a fuel choice for all coal-fired power plants in EPA Base Case
v.4.10. However, logistics and boiler engineering considerations place limits on the extent of
biomass that can be fired. The logistic considerations arise because it is only economic to
transport biomass a limited distance from where it is grown. In addition, the extent of storage that
can be devoted at a power plant to this relatively low density fuel is another limiting factor. Boiler
efficiency and other engineering considerations, largely due to the relatively higher moisture
content and lower heat content of biomass compared to fossil fuel, also plays a role in limiting the
level of co-firing.
In EPA Base Case v.4.10 the limit on biomass co-firing is expressed as the percentage of the
facility level power output that is produced from biomass. Based on analysis by EPA’s power
sector engineering staff, a maximum of 10% of the facility level power output (not to exceed 50
MW) can be fired by biomass. In EPA Base Case v.4.10 “facility level” is defined as the set of
generating units which share the same ORIS code31 in NEEDS v.4.10.
The capital and FOM costs associated with biomass co-firing are summarized in Table 5-10.
Developed by EPA’s power sector engineering staff32, they are on the same cost basis as the
31
The ORIS plant locator code is a unique identifying number (originally assigned by the Office of
Regulatory Information Systems from which the acronym derived). The ORIS code is given to
power plants by EIA and remains unchanged under ownership changes.
32
Among the studies consulted in developing these costs were:
(a) Briggs, J. and J. M. Adams, Biomass Combustion Options for Steam Generation, Presented at
Power-Gen 97, Dallas, TX, December 9 – 11, 1997.
(b) Grusha, J and S. Woldehanna, K. McCarthy, and G. Heinz, Long Term Results from the First
US Low NOx Conversion of a Tangential Lignite Fired Unit, presented at 24th International
Technical Conference on Coal & Fuel Systems, Clearwater, FL., March 8 – 11, 1999.
(c) EPRI, Biomass Cofiring: Field Test Results: Summary of Results of the Bailly and Seward
Demonstrations, Palo Alto, CA, supported by U.S. Department of Energy Division of Energy
Efficiency and Renewable Energy, Washington D.C.; U.S. Department of Energy Division Federal
Energy Technology Center, Pittsburgh PA; Northern Indiana Public Service Company, Merrillville,
IN; and GPU Generation, Inc., Johnstown, PA: 1999. TR-113903.
(d) Laux S., J. Grusha, and D. Tillman, Co-firing of Biomass and Opportunity Fuels in Low NOx
5-14
costs shown in Table 4-16 which resulted from EPA’s comparative analysis of electricity sector
costs as described in Chapter 4.
Table 5-10 Biomass Cofiring for Coal Plants
Size of Biomass Unit (MW)
5
10
15
20
25
30
35
40
45
50
Capital Cost (2007$/kW From Biomass)
488
411
371
345
327
312
300
290
282
275
Fixed O&M (2007$/kW-yr)
24.2
16.2
11.7
9.4
8.0
11.1
9.9
8.9
8.1
7.5
The capital and FOM costs were implemented by ICF in EPA Base Case v.4.10 as a $/MMBtu
biomass fuel cost adder. The procedure followed to implement this was first to represent the
discrete costs shown in Table 5-10 as continuous exponential cost functions showing the FOM
and capital costs for all size coal generating units between 0 and 50 MW in size. Then, for every
coal generating unit represented in EPA Base Case 4.10, the annual payment to capital for the
biomass co-firing capability was derived by multiplying the total capital cost obtained from the
capital cost exponential function by an 11% capital charge rate. (This is the capital charge rate for
environmental retrofits found in Table 8-1 and discussed in Chapter 8.) The resulting value was
added to the annual FOM cost obtained from the FOM exponential function to obtain the total
annual cost for the biomass co-firing for each generating unit.
Then, the annual amount of fuel (in MMBtus) required for each generating unit was derived by
multiplying the size of a unit (in MW) by its heat rate (in Btu/kWh) by its capacity factor (in percent)
by 8,760 hours (i.e., the number of hours in a year). Dividing the resulting value by 1000 yielded
the annual fuel required by the generating unit in MMBtus. Dividing this number into the previously
calculated total annual cost for biomass co-firing resulted in the cost of biomass co-firing per
MMBtu of biomass combusted. This was represented in IPM as a fuel cost adder incurred when a
coal units co-fires biomass.
5.4 Mercury Control Technologies
As previously noted, the mercury emission controls options and assumptions in EPA Base Case
v.4.10 do not reflect mercury control updates that are currently under way at EPA in support of the
Utility MACT initiative and do not make use of data collected under EPA’s 2010 Information
Collection Request (ICR). The following discussion is based on EPA’s earlier work on mercury
controls.
For any power plant, mercury emissions depend on the mercury content of the fuel used, the
combustion and physical characteristics of the unit, and the emission control technologies
deployed. In the absence of emission policies that would require the installation of mercury
emission controls, mercury emission reductions below the mercury content of the fuel are strictly
due to characteristics of the combustion process and incidental removal resulting from nonmercury control technologies, i.e., the SO2, NOX, and particulate controls. While the base case
itself does not include any federal mercury control policies, it does include some State mercury
reduction requirements. IPM has the capability to model mercury controls that might be installed
in response to such State mercury control policies. These same controls come into play in model
runs that analyze possible federal mercury policies relative to the base case. The technology
specifically designated for mercury control in such policy runs is Activated Carbon Injection (ACI)
downstream of the combustion process.
Burners, PowerGen 2000 - Orlando, FL,
www.fwc.com/publications/tech_papers/powgen/pdfs/clrw_bio.pdf.
Tillman, D. A., Cofiring Biomass for Greenhouse Gas Mitigation, presented at Power-Gen 99, New
Orleans, LA, November 30 – December 1, 1999.
(e) Tillman, D. A. and P. Hus, Blending Opportunity Fuels with Coal for Efficiency and
Environmental Benefit, presented at 25th International Technical Conference on Coal Utilization &
Fuel Systems, Clearwater, FL., March 6 – 9, 2000
5-15
The following discussion is divided into three parts. Sections 5.4.1 and 5.4.2 treat the two factors
that figure into the unregulated mercury emissions resulting under EPA Base Case v.4.10.
Section 5.4.1 discusses how mercury content of fuel is modeled in EPA Base Case v.4.10.
Section 5.4.2 looks at the procedure used in the base case to capture the mercury reductions
resulting from different unit and (non-mercury) control configurations. Section 5.4.3 explains the
mercury emission control options that are available under EPA Base Case v.4.10. A major focus
is on the cost and performance features of Activated Carbon Injection. Each section indicates the
data sources and methodology used.
5.4.1 Mercury Content of Fuels
Coal: The assumptions in EPA Base Case v.4.10 on the mercury content of coal (and the majority
of emission modification factors discussed below in Section 5.4.2) are derived from EPA’s
“Information Collection Request for Electric Utility Steam Generating Unit Mercury Emissions
Information Collection Effort” (ICR).33 A two-year effort initiated in 1998 and completed in 2000,
the ICR had three main components: (1) identifying all coal-fired units owned and operated by
publicly-owned utility companies, Federal power agencies, rural electric cooperatives, and
investor-owned utility generating companies, (2) obtaining “accurate information on the amount of
mercury contained in the as-fired coal used by each electric utility steam generating unit . . . with
a capacity greater than 25 megawatts electric [MWe]), as well as accurate information on the total
amount of coal burned by each such unit,” and (3) obtaining data by coal sampling and stack
testing at selected units to characterize mercury reductions from representative unit
configurations.
The ICR second component resulted in more than 40,000 data points indicating the coal type,
sulfur content, mercury content and other characteristics of coal burned at coal-fired utility units
greater than 25 MW. To make this data usable in EPA Base Case v.4.10, these data points were
first grouped by IPM coal types and IPM coal supply regions. (IPM coal types divide bituminous,
sub-bituminous, and lignite coal into different grades based on sulfur content. See Table 5-11.)
Next, a clustering analysis was performed on the data using the SAS statistical software package.
Clustering analysis places objects into groups or clusters, such that data in a given cluster tend to
be similar to each other and dissimilar to data in other clusters. The clustering analysis involved
two steps. First, the number of clusters of mercury concentrations for each IPM coal type was
determined based on the range of mercury and SO2 concentrations for that coal type. Each coal
type used one, two or three clusters. To the greatest extent possible the total number of clusters
for each coal type was limited to keep the model size and run time within feasible limits. Second,
the clustering procedure was used to group each coal type within each IPM coal supply region into
the previously determined number of clusters and show the resulting mercury concentration for
each cluster. The average of each cluster is the mercury content of coal finally used in EPA Base
Case v.4.10 for estimating mercury emissions. IPM input files retain the mapping between
different coal type-supply region combinations and the mercury clusters. Table 5-11 below
provides a summary by coal type of the number of clusters and their mercury concentrations.
33
Data from the ICR can be found at http://www.epa.gov/ttn/atw/combust/utiltox/mercury.html.
5-16
Table 5-11 Mercury Clusters and Mercury Content of Coal by IPM Coal Types
Coal Type by Sulfur Grade
Low Sulfur Easter Bituminous (BA)
Low Sulfur Western Bituminous (BB)
Low Medium Sulfur Bituminous (BD)
Medium Sulfur Bituminous (BE)
High Sulfur Bituminous (BG)
High Sulfur Bituminous (BH)
Low Sulfur Subbituminous (SA)
Low Sulfur Subbituminous (SB)
Low Medium Sulfur Subbituminous (SD)
Low Medium Sulfur Lignite (LD)
Medium Sulfur Lignite (LE)
High Sulfur Lignite (LG)
Mercury Emission Factors by Coal Sulfur
Grades (lbs/TBtu)
Cluster #1
3.19
1.82
5.38
19.53
7.10
7.38
4.24
6.44
4.43
7.51
13.55
14.88
Cluster #2
4.37
4.86
8.94
8.42
20.04
13.93
5.61
--12.00
7.81
--
Cluster #3
--21.67
-14.31
34.71
-------
Oil, natural gas, and waste fuels: The EPA Base Case v.4.10 also includes assumptions on the
mercury content for oil, gas and waste fuels, which were based on data derived from previous
EPA analysis of mercury emissions from power plants.34 Table 5-12 provides a summary of the
assumptions on the mercury content for oil, gas and waste fuels included in EPA Base Case
v.4.10.
Table 5-12 Assumptions on Mercury Concentration in Non-Coal Fuel in EPA Base Case
v.4.10
Fuel Type
Mercury Concentration (lbs/TBtu)
Oil
0.48
Natural Gas
0.001
Petroleum Coke
23.18
Biomass
0.57
Municipal Solid
71.85
Waste
Geothermal
2.97 - 3.7
Resource
Note:
1
The values appearing in this table are rounded to two
decimal places. The zero value shown for natural gas is
based on an EPA study that found a mercury content of
0.00014 lbs/TBtu. Values for geothermal resources
represent a range.
5.4.2 Mercury Emission Modification Factors
Emission Modification Factors (EMFs) represent the mercury reductions attributable to the specific
burner type and configuration of SO2, NOX, and particulate matter control devices at an electric
generating unit. An EMF is the ratio of outlet mercury concentration to inlet mercury
concentration, and depends on the unit's burner type, particulate control device, post-combustion
NOX control and SO2 scrubber control. In other words, the mercury reduction achieved (relative to
34
“Analysis of Emission Reduction Options for the Electric Power Industry,” Office of Air and
Radiation, US EPA, March 1999.
5-17
the inlet) during combustion and flue-gas treatment process is (1-EMF). The EMF varies by the
type of coal (bituminous, sub-bituminous, and lignite) used during the combustion process.
Deriving EMFs involves obtaining mercury inlet data by coal sampling and mercury emission data
by stack testing at a representation set of coal units. As noted above, EPA's EMFs were initially
based on 1999 mercury ICR emission test data. More recent testing conducted by the EPA, DOE,
and industry participants35 has provided a better understanding of mercury emissions from electric
generating units and mercury capture in pollution control devices. Overall the 1999 ICR data
revealed higher levels of mercury capture for bituminous coal-fired plants than for subbitumionus
and lignite coal-fired plants, and significant capture of ionic Hg in wet-FGD scrubbers. Additional
mercury testing indicates that for bituminous coals, SCR systems have the ability to convert
elemental Hg into ionic Hg and thus allow easier capture in a downstream wet-FGD scrubber.
This improved understanding of mercury capture with SCRs was incorporated in EPA Base Case
v.4.10 mercury EMFs for unit configurations with SCR and wet scrubbers.
Table 5-13 below provides a summary of EMFs used in EPA Base Case v.4.10. Table 5-14
provides definitions of acronyms for existing controls that appear in Table 5-13. Table 5-15
provides a key to the burner type designations appearing in Table 5-13.
5.4.3 Mercury Control Capabilities
EPA Base Case v.4.10 offers two options for meeting mercury reduction requirements: (1)
combinations of SO2, NOX, and particulate controls which deliver mercury reductions as a cobenefit and (2) Activated Carbon Injection (ACI), a retrofit option specifically designed for mercury
control. These two options are discussed below.
35
For a detailed summary of emissions test data see Control of Emissions from Coal-Fired
Electric Utility Boilers: An Update, EPA/Office of Research and Development, February 2005.
This report can be found at www.epa.gov/ttnatw01/utility/hgwhitepaperfinal.pdf .
5-18
Table 5-13 Mercury Emission Modification Factors Used in EPA Base Case v.4.10
Cold Side ESP
Post
Combustion
Control –
NOX
SNCR
Post
Combustion
Control SO2
None
Cyclone
Cold Side ESP
SNCR
Cyclone
Cold Side ESP
SNCR
Cyclone
Cold Side ESP
Cyclone
Burner
Type
Particulate Control
Bituminous
EMF
Subbitumionus
EMF
Lignite
EMF
Cyclone
0.64
0.97
0.93
Wet FGD
0.46
0.84
0.58
Dry FGD
0.64
0.65
0.93
SCR
None
0.64
0.97
0.93
Cold Side ESP
SCR
Wet FGD
0.1
0.84
0.58
Cyclone
Cold Side ESP
SCR
Dry FGD
0.64
0.65
0.93
Cyclone
Cold Side ESP
None
Wet FGD
0.46
0.84
0.58
Cyclone
Cold Side ESP
None
Dry FGD
0.64
0.65
0.93
Cyclone
Cold Side ESP
None
None
0.64
0.97
0.93
Cyclone
Cold Side ESP + FF
SNCR
Wet FGD
0.1
0.27
0.58
Cyclone
Cold Side ESP + FF
SCR
None
0.11
0.27
1
Cyclone
Cold Side ESP + FF
SCR
Wet FGD
0.1
0.27
0.58
Cyclone
Cold Side ESP + FF
SCR
Dry FGD
0.4
0.95
0.91
Cyclone
Cold Side ESP + FF
None
Wet FGD
0.1
0.27
0.58
Cyclone
Cold Side ESP + FF
None
Dry FGD
0.4
0.95
0.91
Cyclone
Cold Side ESP + FF
None
None
0.11
0.27
1
Cyclone
Cold Side ESP + FGC
SNCR
None
0.64
0.97
0.93
Cyclone
Cold Side ESP + FGC
SNCR
Wet FGD
0.46
0.84
0.58
Cyclone
Cold Side ESP + FGC
SNCR
Dry FGD
0.64
0.65
0.93
Cyclone
Cold Side ESP + FGC
SCR
None
0.64
0.97
0.93
Cyclone
Cold Side ESP + FGC
SCR
Wet FGD
0.1
0.84
0.58
Cyclone
Cold Side ESP + FGC
SCR
Dry FGD
0.64
0.65
0.93
Cyclone
Cold Side ESP + FGC
None
Wet FGD
0.46
0.84
0.58
Cyclone
Cold Side ESP + FGC
None
Dry FGD
0.64
0.65
0.93
Cyclone
Cold Side ESP + FGC
None
None
0.64
0.97
0.93
Cyclone
Cold Side ESP + FGC + FF
SCR
None
0.11
0.27
1
Cyclone
Cold Side ESP + FGC + FF
SCR
Wet FGD
0.1
0.27
0.58
Cyclone
Cold Side ESP + FGC + FF
SCR
Dry FGD
0.4
0.95
0.91
Cyclone
Cold Side ESP + FGC + FF
None
Wet FGD
0.1
0.27
0.58
Cyclone
Cold Side ESP + FGC + FF
None
Dry FGD
0.4
0.95
0.91
Cyclone
Cold Side ESP + FGC + FF
None
None
0.11
0.27
1
Cyclone
Fabric Filter
SNCR
None
0.11
0.27
1
Cyclone
Fabric Filter
SNCR
Wet FGD
0.03
0.27
0.58
Cyclone
Fabric Filter
SNCR
Dry FGD
0.4
0.95
0.91
Cyclone
Fabric Filter
SCR
None
0.11
0.27
1
Cyclone
Fabric Filter
SCR
Wet FGD
0.1
0.27
0.58
Cyclone
Fabric Filter
SCR
Dry FGD
0.4
0.95
0.91
Cyclone
Fabric Filter
None
Wet FGD
0.1
0.27
0.58
Cyclone
Fabric Filter
None
Dry FGD
0.4
0.95
0.91
Cyclone
Fabric Filter
None
None
0.11
0.27
1
Cyclone
Hot Side ESP
SNCR
None
0.9
1
1
Cyclone
Hot Side ESP
SNCR
Wet FGD
0.58
0.6
1
Cyclone
Hot Side ESP
SNCR
Dry FGD
0.9
1
1
Cyclone
Hot Side ESP
SCR
None
0.9
1
1
Cyclone
Hot Side ESP
SCR
Wet FGD
0.1
0.8
1
Cyclone
Hot Side ESP
SCR
Dry FGD
0.9
1
1
5-19
Hot Side ESP
Post
Combustion
Control –
NOX
None
Post
Combustion
Control SO2
Wet FGD
Cyclone
Hot Side ESP
None
Cyclone
Hot Side ESP
None
Cyclone
Hot Side ESP + FF
Cyclone
Burner
Type
Particulate Control
Bituminous
EMF
Subbitumionus
EMF
Lignite
EMF
Cyclone
0.58
0.6
1
Dry FGD
0.9
1
1
None
0.9
1
1
None
None
0.11
0.27
1
Hot Side ESP + FGC
SNCR
None
0.9
1
1
Cyclone
Hot Side ESP + FGC
SNCR
Wet FGD
0.58
0.6
1
Cyclone
Hot Side ESP + FGC
SNCR
Dry FGD
0.9
1
1
Cyclone
Hot Side ESP + FGC
SCR
None
0.9
1
1
Cyclone
Hot Side ESP + FGC
SCR
Wet FGD
0.1
0.8
1
Cyclone
Hot Side ESP + FGC
SCR
Dry FGD
0.9
1
1
Cyclone
Hot Side ESP + FGC
None
Wet FGD
0.58
0.6
1
Cyclone
Hot Side ESP + FGC
None
Dry FGD
0.9
1
1
Cyclone
Hot Side ESP + FGC
None
None
0.9
1
1
Cyclone
No Control
SNCR
None
1
1
1
Cyclone
No Control
SNCR
Wet FGD
0.45
0.6
1
Cyclone
No Control
SNCR
Dry FGD
1
1
1
Cyclone
No Control
SCR
None
1
1
1
Cyclone
No Control
SCR
Wet FGD
0.1
0.7
1
Cyclone
No Control
SCR
Dry FGD
1
1
1
Cyclone
No Control
None
Wet FGD
0.45
0.6
1
Cyclone
No Control
None
Dry FGD
1
1
1
Cyclone
No Control
None
None
1
1
1
Cyclone
PM Scrubber
None
None
0.8
1
1
FBC
Cold Side ESP
SNCR
None
0.65
0.65
0.62
FBC
Cold Side ESP
SNCR
Wet FGD
0.65
0.65
0.62
FBC
Cold Side ESP
SCR
Wet FGD
0.1
0.84
0.62
FBC
Cold Side ESP
None
Wet FGD
0.65
0.65
0.62
FBC
Cold Side ESP
None
Dry FGD
0.45
0.45
1
FBC
Cold Side ESP
None
None
0.65
0.65
0.62
FBC
Cold Side ESP + FF
SNCR
None
0.05
0.43
0.43
FBC
Cold Side ESP + FF
SNCR
Dry FGD
0.05
0.43
0.43
FBC
Cold Side ESP + FF
None
Dry FGD
0.05
0.43
0.43
FBC
Cold Side ESP + FF
None
None
0.05
0.43
0.43
FBC
Cold Side ESP + FGC
SNCR
None
0.65
0.65
0.62
FBC
Cold Side ESP + FGC
SNCR
Wet FGD
0.65
0.65
0.62
FBC
Cold Side ESP + FGC
SCR
Wet FGD
0.1
0.84
0.62
FBC
Cold Side ESP + FGC
None
Wet FGD
0.65
0.65
0.62
FBC
Cold Side ESP + FGC
None
Dry FGD
0.45
0.45
1
FBC
Cold Side ESP + FGC
None
None
0.65
0.65
0.62
FBC
Cold Side ESP + FGC + FF
SNCR
None
0.05
0.43
0.43
FBC
Cold Side ESP + FGC + FF
SNCR
Dry FGD
0.05
0.43
0.43
FBC
Cold Side ESP + FGC + FF
None
Dry FGD
0.05
0.43
0.43
FBC
Cold Side ESP + FGC + FF
None
None
0.05
0.43
0.43
FBC
Fabric Filter
SNCR
None
0.05
0.43
0.43
FBC
Fabric Filter
SNCR
Wet FGD
0.05
0.43
0.43
FBC
Fabric Filter
SNCR
Dry FGD
0.05
0.43
0.43
FBC
Fabric Filter
SCR
None
0.05
0.43
0.43
5-20
Post
Combustion
Control –
NOX
SCR
Burner
Type
Particulate Control
FBC
Fabric Filter
FBC
Fabric Filter
SCR
FBC
Fabric Filter
None
FBC
Fabric Filter
None
FBC
Fabric Filter
FBC
Post
Combustion
Control SO2
Wet FGD
Bituminous
EMF
Subbitumionus
EMF
Lignite
EMF
0.05
0.27
0.43
Dry FGD
0.05
0.43
0.43
Wet FGD
0.1
0.43
0.43
Dry FGD
0.05
0.43
0.43
None
None
0.05
0.43
0.43
Hot Side ESP
SNCR
None
1
1
1
FBC
Hot Side ESP
SNCR
Dry FGD
0.45
0.45
1
FBC
Hot Side ESP
None
Dry FGD
0.45
0.45
1
FBC
Hot Side ESP
None
None
1
1
1
FBC
Hot Side ESP + FGC
SNCR
None
1
1
1
FBC
Hot Side ESP + FGC
SNCR
Dry FGD
0.45
0.45
1
FBC
Hot Side ESP + FGC
None
Dry FGD
0.45
0.45
1
FBC
Hot Side ESP + FGC
None
None
1
1
1
FBC
No Control
SNCR
None
1
1
1
FBC
No Control
SNCR
Wet FGD
1
1
1
FBC
No Control
SNCR
Dry FGD
0.45
0.45
1
FBC
No Control
SCR
None
1
1
1
FBC
No Control
SCR
Wet FGD
0.1
0.7
1
FBC
No Control
SCR
Dry FGD
0.45
0.45
1
FBC
No Control
None
Wet FGD
1
1
1
FBC
No Control
None
Dry FGD
0.45
0.45
1
1
FBC
No Control
None
None
1
1
PC
Cold Side ESP
SNCR
None
0.64
0.97
1
PC
Cold Side ESP
SNCR
Wet FGD
0.34
0.65
0.56
PC
Cold Side ESP
SNCR
Dry FGD
0.64
0.65
1
PC
Cold Side ESP
SCR
None
0.64
0.97
1
PC
Cold Side ESP
SCR
Wet FGD
0.1
0.84
0.56
PC
Cold Side ESP
SCR
Dry FGD
0.64
0.65
1
PC
Cold Side ESP
None
Wet FGD
0.34
0.84
0.56
PC
Cold Side ESP
None
Dry FGD
0.64
0.65
1
PC
Cold Side ESP
None
None
0.64
0.97
1
PC
Cold Side ESP + FF
SNCR
None
0.2
0.75
1
PC
Cold Side ESP + FF
SNCR
Wet FGD
0.1
0.3
0.56
PC
Cold Side ESP + FF
SNCR
Dry FGD
0.05
0.75
1
PC
Cold Side ESP + FF
SCR
None
0.2
0.75
1
PC
Cold Side ESP + FF
SCR
Wet FGD
0.1
0.3
0.56
PC
Cold Side ESP + FF
SCR
Dry FGD
0.05
0.75
1
PC
Cold Side ESP + FF
None
Wet FGD
0.3
0.3
0.56
PC
Cold Side ESP + FF
None
Dry FGD
0.05
0.75
1
PC
Cold Side ESP + FF
None
None
0.2
0.75
1
PC
Cold Side ESP + FGC
SNCR
None
0.64
0.97
1
PC
Cold Side ESP + FGC
SNCR
Wet FGD
0.34
0.65
0.56
PC
Cold Side ESP + FGC
SNCR
Dry FGD
0.64
0.65
1
PC
Cold Side ESP + FGC
SCR
None
0.64
0.97
1
PC
Cold Side ESP + FGC
SCR
Wet FGD
0.1
0.84
0.56
PC
Cold Side ESP + FGC
SCR
Dry FGD
0.64
0.65
1
PC
Cold Side ESP + FGC
None
Wet FGD
0.34
0.84
0.56
5-21
Burner
Type
Particulate Control
PC
Cold Side ESP + FGC
Post
Combustion
Control –
NOX
None
Post
Combustion
Control SO2
Dry FGD
Bituminous
EMF
Subbitumionus
EMF
Lignite
EMF
0.64
0.65
1
1
PC
Cold Side ESP + FGC
None
None
0.64
0.97
PC
Cold Side ESP + FGC + FF
SNCR
None
0.2
0.75
1
PC
Cold Side ESP + FGC + FF
SNCR
Wet FGD
0.1
0.3
0.56
PC
Cold Side ESP + FGC + FF
SNCR
Dry FGD
0.05
0.75
1
PC
Cold Side ESP + FGC + FF
SCR
None
0.2
0.75
1
PC
Cold Side ESP + FGC + FF
SCR
Wet FGD
0.1
0.3
0.56
PC
Cold Side ESP + FGC + FF
SCR
Dry FGD
0.05
0.75
1
PC
Cold Side ESP + FGC + FF
None
Wet FGD
0.3
0.3
0.56
PC
Cold Side ESP + FGC + FF
None
Dry FGD
0.05
0.75
1
PC
Cold Side ESP + FGC + FF
None
None
0.2
0.75
1
PC
Fabric Filter
SNCR
None
0.11
0.27
1
PC
Fabric Filter
SNCR
Wet FGD
0.03
0.27
0.56
PC
Fabric Filter
SNCR
Dry FGD
0.05
0.75
1
PC
Fabric Filter
SCR
None
0.11
0.27
1
PC
Fabric Filter
SCR
Wet FGD
0.1
0.27
0.56
PC
Fabric Filter
SCR
Dry FGD
0.05
0.75
1
PC
Fabric Filter
None
Wet FGD
0.1
0.27
0.56
PC
Fabric Filter
None
Dry FGD
0.05
0.75
1
PC
Fabric Filter
None
None
0.11
0.27
1
PC
Hot Side ESP
SNCR
None
0.9
0.9
1
PC
Hot Side ESP
SNCR
Wet FGD
0.58
0.75
1
PC
Hot Side ESP
SNCR
Dry FGD
0.6
0.85
1
PC
Hot Side ESP
SCR
None
0.9
0.9
1
PC
Hot Side ESP
SCR
Wet FGD
0.1
0.8
1
PC
Hot Side ESP
SCR
Dry FGD
0.6
0.85
1
PC
Hot Side ESP
None
Wet FGD
0.58
0.8
1
PC
Hot Side ESP
None
Dry FGD
0.6
0.85
1
PC
Hot Side ESP
None
None
0.9
0.94
1
PC
Hot Side ESP + FF
SNCR
None
0.11
0.27
1
PC
Hot Side ESP + FF
SNCR
Wet FGD
0.03
0.27
0.56
PC
Hot Side ESP + FF
SNCR
Dry FGD
0.05
0.75
1
PC
Hot Side ESP + FF
SCR
None
0.11
0.27
1
PC
Hot Side ESP + FF
SCR
Wet FGD
0.1
0.15
0.56
PC
Hot Side ESP + FF
SCR
Dry FGD
0.05
0.75
1
PC
Hot Side ESP + FF
None
Wet FGD
0.03
0.27
0.56
PC
Hot Side ESP + FF
None
Dry FGD
0.05
0.75
1
PC
Hot Side ESP + FF
None
None
0.11
0.27
1
PC
Hot Side ESP + FGC
SNCR
None
0.9
0.9
1
PC
Hot Side ESP + FGC
SNCR
Wet FGD
0.58
0.75
1
PC
Hot Side ESP + FGC
SNCR
Dry FGD
0.6
0.85
1
PC
Hot Side ESP + FGC
SCR
None
0.9
0.9
1
PC
Hot Side ESP + FGC
SCR
Wet FGD
0.1
0.8
1
PC
Hot Side ESP + FGC
SCR
Dry FGD
0.6
0.85
1
PC
Hot Side ESP + FGC
None
Wet FGD
0.58
0.8
1
PC
Hot Side ESP + FGC
None
Dry FGD
0.6
0.85
1
PC
Hot Side ESP + FGC
None
None
0.9
0.94
1
5-22
Hot Side ESP + FGC + FF
Post
Combustion
Control –
NOX
SNCR
Post
Combustion
Control SO2
None
PC
Hot Side ESP + FGC + FF
SNCR
PC
Hot Side ESP + FGC + FF
SNCR
PC
Hot Side ESP + FGC + FF
PC
Burner
Type
Particulate Control
Bituminous
EMF
Subbitumionus
EMF
Lignite
EMF
PC
0.11
0.27
1
Wet FGD
0.03
0.27
0.56
Dry FGD
0.05
0.75
1
SCR
None
0.11
0.27
1
Hot Side ESP + FGC + FF
SCR
Wet FGD
0.1
0.15
0.56
PC
Hot Side ESP + FGC + FF
SCR
Dry FGD
0.05
0.75
1
PC
Hot Side ESP + FGC + FF
None
Wet FGD
0.03
0.27
0.56
PC
Hot Side ESP + FGC + FF
None
Dry FGD
0.05
0.75
1
PC
Hot Side ESP + FGC + FF
None
None
0.11
0.27
1
PC
No Control
SNCR
None
1
1
1
PC
No Control
SNCR
Wet FGD
0.58
0.7
1
PC
No Control
SNCR
Dry FGD
0.6
0.85
1
PC
No Control
SCR
None
1
1
1
PC
No Control
SCR
Wet FGD
0.1
0.7
1
PC
No Control
SCR
Dry FGD
0.6
0.85
1
PC
No Control
None
Wet FGD
0.58
0.7
1
PC
No Control
None
Dry FGD
0.6
0.85
1
PC
No Control
None
None
1
1
1
PC
PM Scrubber
SNCR
None
0.9
0.91
1
PC
PM Scrubber
SCR
None
0.9
1
1
PC
PM Scrubber
None
None
0.9
0.91
1
Stoker
Cold Side ESP
SNCR
None
0.65
0.97
1
Stoker
Cold Side ESP
SNCR
Wet FGD
0.34
0.73
0.56
Stoker
Cold Side ESP
SNCR
Dry FGD
0.65
0.65
1
Stoker
Cold Side ESP
SCR
None
0.65
0.97
1
Stoker
Cold Side ESP
SCR
Wet FGD
0.1
0.84
0.56
Stoker
Cold Side ESP
SCR
Dry FGD
0.65
0.65
1
Stoker
Cold Side ESP
None
Wet FGD
0.34
0.84
0.56
Stoker
Cold Side ESP
None
Dry FGD
0.65
0.65
1
Stoker
Cold Side ESP
None
None
0.65
0.97
1
Stoker
Cold Side ESP + FGC
SNCR
None
0.65
0.97
1
Stoker
Cold Side ESP + FGC
SNCR
Wet FGD
0.34
0.73
0.56
Stoker
Cold Side ESP + FGC
SNCR
Dry FGD
0.65
0.65
1
Stoker
Cold Side ESP + FGC
SCR
None
0.65
0.97
1
Stoker
Cold Side ESP + FGC
SCR
Wet FGD
0.1
0.84
0.56
Stoker
Cold Side ESP + FGC
SCR
Dry FGD
0.65
0.65
1
Stoker
Cold Side ESP + FGC
None
Wet FGD
0.34
0.84
0.56
Stoker
Cold Side ESP + FGC
None
Dry FGD
0.65
0.65
1
Stoker
Cold Side ESP + FGC
None
None
0.65
0.97
1
Stoker
Fabric Filter
SNCR
None
0.11
0.27
1
Stoker
Fabric Filter
SNCR
Wet FGD
0.03
0.27
0.56
Stoker
Fabric Filter
SNCR
Dry FGD
0.1
0.75
1
Stoker
Fabric Filter
SCR
None
0.11
0.27
1
Stoker
Fabric Filter
SCR
Wet FGD
0.1
0.27
0.56
Stoker
Fabric Filter
SCR
Dry FGD
0.1
0.75
1
Stoker
Fabric Filter
None
Wet FGD
0.1
0.27
0.56
Stoker
Fabric Filter
None
Dry FGD
0.1
0.75
1
5-23
Burner
Type
Particulate Control
Stoker
Fabric Filter
Post
Combustion
Control –
NOX
None
Stoker
Hot Side ESP
SNCR
Stoker
Hot Side ESP
SNCR
Stoker
Hot Side ESP
SNCR
Stoker
Hot Side ESP
Stoker
Hot Side ESP
Stoker
Hot Side ESP
SCR
Stoker
Hot Side ESP
None
Stoker
Hot Side ESP
None
Stoker
Hot Side ESP
Stoker
Post
Combustion
Control SO2
None
Bituminous
EMF
Subbitumionus
EMF
Lignite
EMF
0.11
0.27
1
None
1
1
1
Wet FGD
0.58
1
1
Dry FGD
1
1
1
SCR
None
1
1
1
SCR
Wet FGD
0.1
0.8
1
Dry FGD
1
1
1
Wet FGD
0.58
1
1
Dry FGD
1
1
1
None
None
1
1
1
Hot Side ESP + FGC
SNCR
None
1
1
1
Stoker
Hot Side ESP + FGC
SNCR
Wet FGD
0.58
1
1
Stoker
Hot Side ESP + FGC
SNCR
Dry FGD
1
1
1
Stoker
Hot Side ESP + FGC
SCR
None
1
1
1
Stoker
Hot Side ESP + FGC
SCR
Wet FGD
0.1
0.8
1
Stoker
Hot Side ESP + FGC
SCR
Dry FGD
1
1
1
Stoker
Hot Side ESP + FGC
None
Wet FGD
0.58
1
1
Stoker
Hot Side ESP + FGC
None
Dry FGD
1
1
1
Stoker
Hot Side ESP + FGC
None
None
1
1
1
Stoker
No Control
SNCR
None
1
1
1
Stoker
No Control
SNCR
Wet FGD
0.58
1
1
Stoker
No Control
SNCR
Dry FGD
1
1
1
Stoker
No Control
SCR
None
1
1
1
Stoker
No Control
SCR
Wet FGD
0.1
0.7
1
Stoker
No Control
SCR
Dry FGD
1
1
1
Stoker
No Control
None
Wet FGD
0.58
1
1
Stoker
No Control
None
Dry FGD
1
1
1
Stoker
No Control
None
None
1
1
1
Stoker
PM Scrubber
None
None
1
1
1
Other
Cold Side ESP
SNCR
None
0.64
0.97
1
Other
Cold Side ESP
SNCR
Wet FGD
0.34
0.73
0.56
Other
Cold Side ESP
SNCR
Dry FGD
0.64
0.65
1
Other
Cold Side ESP
SCR
None
0.64
0.97
1
Other
Cold Side ESP
SCR
Wet FGD
0.1
0.84
0.56
Other
Cold Side ESP
SCR
Dry FGD
0.64
0.65
1
Other
Cold Side ESP
None
Wet FGD
0.34
0.84
0.56
Other
Cold Side ESP
None
Dry FGD
0.64
0.65
1
1
Other
Cold Side ESP
None
None
0.64
0.97
Other
Cold Side ESP + FGC
SNCR
None
0.64
0.97
1
Other
Cold Side ESP + FGC
SNCR
Wet FGD
0.34
0.73
0.56
Other
Cold Side ESP + FGC
SNCR
Dry FGD
0.64
0.65
1
Other
Cold Side ESP + FGC
SCR
None
0.64
0.97
1
Other
Cold Side ESP + FGC
SCR
Wet FGD
0.1
0.84
0.56
Other
Cold Side ESP + FGC
SCR
Dry FGD
0.64
0.65
1
Other
Cold Side ESP + FGC
None
Wet FGD
0.34
0.84
0.56
Other
Cold Side ESP + FGC
None
Dry FGD
0.64
0.65
1
Other
Cold Side ESP + FGC
None
None
0.64
0.97
1
5-24
Fabric Filter
Post
Combustion
Control –
NOX
SNCR
Post
Combustion
Control SO2
None
Other
Fabric Filter
SNCR
Other
Fabric Filter
SNCR
Other
Fabric Filter
Other
Burner
Type
Particulate Control
Bituminous
EMF
Subbitumionus
EMF
Lignite
EMF
Other
0.45
0.75
1
Wet FGD
0.03
0.27
0.56
Dry FGD
0.4
0.75
1
SCR
None
0.11
0.27
1
Fabric Filter
SCR
Wet FGD
0.1
0.27
0.56
Other
Fabric Filter
SCR
Dry FGD
0.4
0.75
1
Other
Fabric Filter
None
Wet FGD
0.1
0.27
0.56
Other
Fabric Filter
None
Dry FGD
0.4
0.75
1
Other
Fabric Filter
None
None
0.11
0.27
1
Other
Hot Side ESP
SNCR
None
1
1
1
Other
Hot Side ESP
SNCR
Wet FGD
0.58
1
1
Other
Hot Side ESP
SNCR
Dry FGD
1
1
1
Other
Hot Side ESP
SCR
None
1
1
1
Other
Hot Side ESP
SCR
Wet FGD
0.1
0.8
1
Other
Hot Side ESP
SCR
Dry FGD
1
1
1
Other
Hot Side ESP
None
Wet FGD
0.58
1
1
Other
Hot Side ESP
None
Dry FGD
1
1
1
Other
Hot Side ESP
None
None
1
1
1
Other
Hot Side ESP + FF
None
None
0.11
0.27
1
Other
Hot Side ESP + FGC
SNCR
None
1
1
1
Other
Hot Side ESP + FGC
SNCR
Wet FGD
0.58
1
1
Other
Hot Side ESP + FGC
SNCR
Dry FGD
1
1
1
Other
Hot Side ESP + FGC
SCR
None
1
1
1
Other
Hot Side ESP + FGC
SCR
Wet FGD
0.1
0.8
1
Other
Hot Side ESP + FGC
SCR
Dry FGD
1
1
1
Other
Hot Side ESP + FGC
None
Wet FGD
0.58
1
1
Other
Hot Side ESP + FGC
None
Dry FGD
1
1
1
Other
Hot Side ESP + FGC
None
None
1
1
1
Other
Hot Side ESP + FGC + FF
None
None
0.11
0.27
1
Other
No Control
SNCR
None
1
1
1
Other
No Control
SNCR
Wet FGD
0.58
0.7
1
Other
No Control
SNCR
Dry FGD
1
1
1
Other
No Control
SCR
None
1
1
1
Other
No Control
SCR
Wet FGD
0.1
0.7
1
Other
No Control
SCR
Dry FGD
1
1
1
Other
No Control
None
Wet FGD
0.58
0.7
1
Other
No Control
None
Dry FGD
1
1
1
Other
No Control
None
None
1
1
1
Other
PM Scrubber
None
None
0.9
0.91
1
5-25
Table 5-14 Definition of Acronyms for Existing Controls
Acronym
Description
ESP
Electro Static Precipitator - Cold Side
HESP
Electro Static Precipitator - Hot Side
ESP/O
Electro Static Precipitator - Other
FF
Fabric Filter
FGD
Flue Gas Desulfurization - Wet
DS
Flue Gas Desulfurization - Dry
SCR
Selective Catalytic Reduction
PMSCRUB
Particulate Matter Scrubber
Table 5-15 Key to Burner Type Designations in Table 5-13
“PC” refers to conventional pulverized coal boilers. Typical configurations include wall-fired
and tangentially fired boilers (also called T-fired boilers). In wall-fired boilers the burner’s coal
and air nozzles are mounted on a single wall or opposing walls. In tangentially fired boilers the
burner’s coal and air nozzles are mounted in each corner of the boiler.
“Cyclone” refers to cyclone boilers where air and crushed coal are injected tangentially into the
boiler through a “cyclone burner” and “cyclone barrel” which create a swirling motion allowing
smaller coal particles to be burned in suspension and larger coal particles to be captured on the
cyclone barrel wall where they are burned in molten slag.
“Stoker” refers to stoker boilers where lump coal is fed continuously onto a moving grate or
chain which moves the coal into the combustion zone in which air is drawn through the grate
and ignition takes place. The carbon gradually burns off, leaving ash which drops off at the end
into a receptacle, from which it is removed for disposal.
“FBC" refers to “fluidized bed combustion” where solid fuels are suspended on upward-blowing
jets of air, resulting in a turbulent mixing of gas and solids and a tumbling action which provides
especially effective chemical reactions and heat transfer during the combustion process.
“Other" refers to miscellaneous burner types including cell burners and arch- , roof- , and
vertically-fired burner configurations.
5-26
Mercury Control through SO2 and NOX Retrofits
In EPA Base Case v.4.10, units that install SO2, NOX, and particulate controls, reduce mercury
emissions as a byproduct of these retrofits. Section 5.4.2 described how EMFs are used in the
base case to capture the unregulated mercury emissions depending on the rank of coal burned,
the generating unit’s combustion characteristics, and the specific configuration of SO2, NOX, and
particulate controls (i.e., hot and cold-side electrostatic precipitators (ESPs), fabric filters (also
called “baghouses”) and particulate matter (PM) scrubbers). These same EMFs would be
available in mercury policy runs to characterize the mercury reductions that can be achieved by
retrofitting a unit with SCR, SNCR, SO2 scrubbers and particulate controls. The absence of a
federal mercury emission reduction policy means that these controls appear in the base case in
response to SO2, NOX, or particulate limits or state-level mercury emission requirements.
However, in future model runs where mercury limits are present these same SO2 and NOX
controls could be deliberately installed for mercury control if they provide the least cost option for
meeting mercury policy limits.
Activated Carbon Injection (ACI)
The technology specifically designated for mercury control is Activated Carbon Injection (ACI)
downstream of the combustion process in coal fired units. A comprehensive ACI update, which
will incorporate the latest field experience through 2010, is being prepared by Sargent and Lundy
(the same engineering firm that developed the SO2 and NOX control assumptions used in EPA
Base Case v.4.10). It will be incorporated in a future EPA base case. The ACI assumptions in
the current base case release are the result of a 2007 internal EPA engineering study.
Based on this study, it is assume that 90% removal from the level of mercury in the coal is
achievable with the application of one of three alternative ACI configurations: Standard Powered
Activated Carbon (SPAC), Modified Powered Activated Carbon (MPAC), or SPAC in combination
with a fabric filter. The MPAC option exploits the discovery that by converting elemental mercury
to oxidized mercury, halogens (like chlorine, iodine, and bromine) can make activated carbon
more effective in capturing the mercury at the high temperatures found in industrial processes like
power generation. In the MPAC system, a small amount of bromine is chemically bonded to the
powdered carbon which is then injected into the flue gas stream either upstream of both the
particulate control device (ESP or fabric filter) and the air pre-heater (APH), between the APH and
the particulate control device, or downstream of both the pre-existing APH and particulate control
devices but ahead of a new dedicated pulsed-jet fabric filter. (The latter is known as the
TOXECONTM approach, an air pollution control process patented by EPRI.)
Table 5-16 presents the capital, FOM, and VOM costs as well as the capacity and heat rate
penalty for the five Hg emission control technologies included in EPA Base Case v.4.10 for an
illustrative set of generating units with a representative range of capacities.
5-27
Table 5-16 Illustrative Activated Carbon Injection Costs (2007$) for Representative Sizes under the Assumptions in EPA Base Case
v.4.10
Capacity (MW)
100
Control Type
Capacit
y
Penalty
(%)
Heat
Rate
Penalty
(%)
MPAC_Baghouse
Minimum Cutoff: ≥ 25 MW
Maximum Cutoff: None
Assuming Bituminous
Coal
-0.43
0.43
3
0.1
MPAC_CESP
Minimum Cutoff: ≥ 25 MW
Maximum Cutoff: None
Assuming Bituminous
Coal
-0.43
0.43
8
SPAC_Baghouse
Minimum Cutoff: ≥ 25 MW
Maximum Cutoff: None
Assuming Bituminous
Coal
-0.43
0.43
SPAC_ESP
Minimum Cutoff: ≥ 25 MW
Maximum Cutoff: None
Assuming Bituminous
Coal
-0.43
SPAC_ESP+Toxecon
Minimum Cutoff: ≥ 25 MW
Maximum Cutoff: None
Assuming Bituminous
Coal
-0.43
300
700
Capital
Cost
($/kW)
Fixed
O&M
($/kW
-yr)
Variable
O&M cost
(mills/kWh)
Capital
Cost
($/kW)
Fixed
O&M
($/k
W-yr)
Variable
O&M cost
(mills/kWh)
Capital
Cost
($/kW)
Fixed
O&M
($/kW
-yr)
Variable
O&M cost
(mills/kWh)
0.16
2
0.05
0.17
2
0.04
0.17
2
0.03
0.16
0.1
0.57
6
0.1
0.61
5
0.1
0.61
5
0.1
0.59
5
0.1
0.22
4
0.1
0.23
3
0.1
0.23
3
0.1
0.23
0.43
27
0.5
2.29
21
0.3
2.46
18
0.3
2.44
17
0.3
2.39
0.43
269
4.3
2.44
202
2.5
2.61
176
2.1
2.59
161
2.0
2.54
Capital
Cost
($/kW)
Fixed
Variable
O&M
O&M cost
($/kW(mills/kWh)
yr)
500
5-28
The applicable ACI option depends on the coal type burned, its SO2 content, the boiler and
particulate control type and, in some instances, consideration of whether an SO2 scrubber (FGD)
system or SCR NOx post-combustion control are present. Table 5-17 shows the ACI assignment
scheme used in EPA Base Case v.4.10 to achieve 90% mercury removal.
Table 5-17 Assignment Scheme for Mercury Emissions Control Using Activated Carbon
Injection (ACI) in EPA Base Case v.4.10
Applicability of Activated Carbon Injection
Coal Type
Bit/Sub-bit/
Lig
Bit/Sub-bit/
Lig
Bit/Subbit/Lig
Bit
Bit
Sub-bit/Lig
Sub-bit/Lig
Bit/Sub-bit/
Lig
Bit/Sub-bit/
Lig
Bit/Sub-bit/
Lig
Bit/Sub-bit/
Lig
Bit/Sub-bit/
Lig
Bit/Sub-bit/
Lig
Sub-bit/ Lig
Bit/Subbit/Lig
Notes:
Legends:
ACI
BH
Bit
CFB
CS-ESP
FGC
HESP
Lig
MPAC
SPAC
Sub-bit
SO2 in Coal
(lb/MMBtu)
Boiler
Type
Particulate
Control Type
< 1.6
Non-CFB
--
Non-CFB
--
CFB
< 1.6
≥ 1.6
≥ 1.6
≥ 1.6
Non-CFB
Non-CFB
Non-CFB
Non-CFB
CS-ESP or BH
(no FGC)
CS-ESP or BH
(no FGC)
CS-ESP or BH
(no FGC)
CS-ESP
CS-ESP or BH
CS-ESP
BH
--
Non-CFB
--
--
< 1.6
Non-CFB
< 1.6
Non-CFB
--
--
No Control
< 1.6
--
< 1.6
--
FGD
System
ACI Type
SCR
Toxecon
With 90% Hg
System Required?
Reduction
--
No
No
MPAC
LSD
--
No
MPAC
--
--
No
MPAC
Non-LSD
----
Yes
----
No
No
Yes
No
SPAC
SPAC
SPAC
SPAC
HESP
--
--
Yes
SPAC
HESP or CSESP (with FGC)
--
--
Yes
SPAC
BH
No
Yes
No
MPAC
CS-ESP
(no FGC)
No
Yes
No
MPAC
--
--
Yes
SPAC
BH
Non-LSD
Yes
No
SPAC
--
CS-ESP
(no FGC)
Non-LSD
Yes
Yes
SPAC
--
Cyclone
--
--
Yes
SPAC
Activated carbon injection
Baghouse
Bituminous coal
Circulating fluidized-bed boiler
Cold side electrostatic
precipitator
Flue gas conditioning
Hot electrostatic precipitator
Lignite
Modified powdered activated
carbon
Standard powdered activated
carbon
Subbituminous coal
If the existing equipment provides 90% Hg removal, no ACI
system is required.
"--" means that the category type has no effect on the ACI
application.
5-29
Appendix 5-1 Example Cost Calculation Worksheets for SO2 Control
Technologies in EPA Base Case v.4.10
Appendix 5-1.1
Appendix 5-1.2
Appendix 5-1.3
Appendix 5-1.4
Appendix 5-2 Example Cost Calculation Worksheets for NOx PostCombustion Control Technologies in EPA Base Case v.4.10
Appendix 5-2.1
Appendix 5-2.2
Appendix 5-2.3
Appendix 5-2.4
Control Technologies to Reduce
Conventional and Hazardous Air
Pollutants from Coal-Fired Power Plants
March 31, 2011
This Page Intentionally Blank
Control Technologies to Reduce
Conventional and Hazardous Air Pollutants
from Coal-Fired Power Plants
Prepared For:
Northeast States for Coordinated Air Use Management
89 South Street, Suite 602
Boston, MA 02111
Prepared By:
James E. Staudt, Ph.D.
Andover Technology Partners
M.J. Bradley & Associates LLC
March 31, 2011
©2011 by Andover Technology Partners
All Rights Reserved
Table of Contents
Executive Summary ........................................................................................................................ 1
Introduction ..................................................................................................................................... 5
Transport Rule ........................................................................................................................ 5
Air Toxics Rule ....................................................................................................................... 7
Overview of Air Pollution Control Technologies ........................................................................... 8
Methods for Controlling SO2 Emissions......................................................................................... 8
Lower Sulfur Coal................................................................................................................... 9
Flue Gas Desulfurization (FGD) or “Scrubbing” ................................................................. 10
Wet Scrubbers ....................................................................................................................... 10
Dry Scrubbers ....................................................................................................................... 11
Upgrades to Existing Wet FGD Systems .............................................................................. 12
Dry Sorbent Injection (DSI).................................................................................................. 13
Methods for Controlling NOx Emissions ..................................................................................... 14
Combustion Controls ............................................................................................................ 15
Post-Combustion NOx Controls ........................................................................................... 16
Methods for Controlling Hazardous Air Pollutant Emissions ...................................................... 18
Control of Mercury Emissions .............................................................................................. 18
Acid Gas Control Methods ................................................................................................... 21
PM Emissions Control .......................................................................................................... 23
Control of Dioxins and Furans .............................................................................................. 25
Labor Availability ......................................................................................................................... 26
Conclusion .................................................................................................................................... 27
Executive Summary
To implement requirements adopted by Congress in the federal Clean Air Act (CAA), the U.S.
Environmental Protection Agency (EPA) is developing new rules to reduce air pollution from fossil fuel
power plants. Power plants that burn coal will bear a large responsibility for reducing their emissions
further, as the majority of air pollutants from the electric generation sector come from coal combustion.
The major rules addressing power plant pollution that EPA recently proposed are the Clean Air Transport
Rule (Transport Rule), and the National Emission Standards for Hazardous Air Pollutants from Electric
Utility Steam Generating Units (Air Toxics Rule). The Transport Rule will address the long-range
interstate transport of sulfur dioxide (SO2) and nitrogen oxides (NOx) in the eastern United States. Both
these types of pollutants contribute to formation of small particles (“fine particulates”) in the atmosphere
that can be transported long distances into downwind states. These small particles can be inhaled deep
into the lungs, causing serious adverse health impacts. Nitrogen oxides also contribute to the formation
and long-range transport of ground-level ozone, another pollutant with significant health impacts. The
Air Toxics Rule will address emissions of hazardous air pollutants (HAPs) such as mercury, lead, arsenic,
along with acid gases such as hydrogen chloride and hydrogen fluoride and organic air toxics (e.g.,
dioxins and furans). HAPs are chemical pollutants that are known or suspected to cause cancer or other
serious health effects, such as reproductive problems or birth defects, and that adversely affect the
environment.
These regulations will require coal-fired power plants that have not yet installed pollution control
equipment to do so and, in some cases, will require plants with existing control equipment to improve
performance.
Over the last several decades, state and federal clean air rules to address acid rain and ground-level smog
led to power plant owners successfully deploying a range of advanced pollution control systems at
hundreds of facilities across the country, providing valuable experience with the installation and operation
of these technologies. In addition, many states adopted mercury reduction requirements in the absence of
federal rules, leading to new controls and significant reductions of this air toxic from a number of coal
power plants over the past several years. This has provided industry with a working knowledge of a suite
of air pollution control devices and techniques that can comply with EPA’s proposed Transport Rule and
Air Toxics Rule.
This report provides an overview of well-established, commercially available emission control
technologies for SO2 and NOx, and HAPs, such as mercury, chromium, lead and arsenic; acid gases, such
as hydrogen chloride and hydrogen fluoride; dioxins and furans; and other toxic air emissions.
The key findings of the report include:
The electric power sector has a range of available technology options as well as experience
in their installation and operation that will enable the sector to comply with the Transport
Rule and the Air Toxics Rule.
o
1|Page
The electric power sector has long and successful experience installing many of the
required pollution control systems.
o
The first flue gas desulfurization (scrubber) system was installed in 1968 and more than
40 years later, the plant is still in operation and undergoing a performance upgrade.
o
To reduce SO2 emissions, about 60 percent of the nation’s coal fleet has already installed
scrubber controls, the most capital intensive of the pollution control systems used by
coal-fired power plants.
o
About half of the nation’s coal fleet has already installed advanced post-combustion NOx
controls, with the first large-scale coal-fired selective catalytic reduction (SCR) system
on a new boiler in the U.S. placed in service in 1993 and the first retrofit in the U.S.
placed in service in 1995.
Modern pollution control systems are capable of dramatically reducing air pollution
emissions from coal-fired power plants.
o
Although scrubbers installed in the 1970s and 1980s typically obtained 80-90 percent
SO2 removal, innovation has led to modern systems now capable of achieving 98 percent
or greater removal.
o
SCR can achieve greater than 90 percent NOx removal.
o
Coal-fired power plants, equipped with baghouse systems, report greater than 90 percent
removal of mercury and other heavy metals.
Pollution controls that significantly reduce mercury emissions from coal-fired power plants
have already been installed, demonstrated, and in operation at a significant number of
facilities in the United States. This experience demonstrates the feasibility of achieving the
mercury emissions limits in the proposed Air Toxics Rule.
2|Page
o
In 2001, under cooperative agreements with the Department of Energy, several coal plant
operators started full-scale testing of activated carbon injection (ACI) systems for
mercury control.
o
Since 2003, many states have led the way on mercury control regulations by enacting
statewide mercury limits for coal power plants that require mercury capture rates ranging
from 80 to 95 percent. Power plants in a number of these states have already installed
and are now successfully operating mercury controls that provide the level of mercury
reductions sought in EPA’s proposed Air Toxics Rule.
o
At present, about 25 units representing approximately 7,500 MW are using commercial
technologies for mercury control. In addition, the Institute of Clean Air Companies
(ICAC), a national association of companies providing pollution control systems for
power plants and other stationary sources, has reported about 55,000 MW of new
bookings.
A wide variety of pollution control technology solutions are available to cost-effectively control
air pollution emissions from coal-fired power plants, and many technologies can reduce more
than one type of pollutant.
o A variety of pollution control solutions are available for different plant configurations.
o
The air pollutants targeted by the Transport Rule and the Air Toxics Rule are captured to
some degree by existing air pollution controls, and, in many cases, technologies to
control one pollutant have the co-benefit of also controlling other pollutants. For
example, scrubbers, which are designed to control SO2, are also effective at controlling
particulate matter, mercury, and hydrogen chloride.
o
Dry sorbent injection (DSI) has emerged as a potential control option for smaller, coalfired generating units seeking to cost-effectively control SO2 and acid gas emissions.
o
As highlighted below in Table ES-1, because of these “co-benefits,” in many cases it may
not be necessary to add separate control technologies for some pollutants.
Table ES-1. Control Technology Emission Reduction Effect
Combustion Controls
SNCR
SCR
Particulate Matter Controls
Low Sulfur Fuel
Wet Scrubber
Dry Scrubber
DSI
ACI
SO2
NOx
Mercury (Hg)
HCl
PM
Dioxins/ Furans
N
N
N
N
Y
Y
Y
N
C
N
C
C
N
N
N
N
N
N
N
Y
Y
N
C
C
Y
Y
Y
Y
N
C
N
N
C
N
N
C
C
C
Y
C
Y
Y
Y
N
N
C
C*
N
N
N
N
N
C
Y
N = Technology has little or no emission reduction effect
Y = Technology reduces emissions
C = Technology is normally used for other pollutants, but has a co-benefit emission reduction effect
* When used in combination with a downstream particulate matter control device, such as a baghouse
The electric power sector has a demonstrated ability to install a substantial number of
controls in a short period of time, and therefore should be able to comply with the timelines
of the proposed EPA air rules.
3|Page
o
Between 2001 and 2005, the electric industry successfully installed more than
96 gigawatts (GW) of SCR systems in response to NOx requirements.
o
In response to the Clean Air Interstate Rule (CAIR), about 60 GW of scrubbers and an
additional 20 GW of SCR were brought on line from 2008 through 2010. Notably, most
companies were “early movers,” initiating the installation process before EPA finalized
its rules.
o Available technologies that are less resource and time-intensive will provide additional
compliance flexibility. For example, DSI and dry scrubbing technology design and
installation times are approximately 12 and 24 months, respectively.
The electric power sector has access to a skilled workforce to install these proven control
technologies.
o In November 2010, ICAC sent a letter to U.S. Senator Thomas Carper confirming the nation’s air
pollution control equipment companies repeatedly have successfully met more stringent NOx, SO2
and mercury emission limits with timely installations of effective controls and are well prepared to
meet new EPA requirements.
o Also in November 2010, the Building and Construction Division of the AFL-CIO sent a
letter to Senator Carper indicating that “[t]here is no evidence to suggest that the
availability of skilled manpower will constrain pollution control technology
development.”
o Actual installation of pollution control equipment far exceeded EPA’s earlier estimate of
industry capability that it made during the Clean Air Interstate Rule (CAIR) rulemaking.
o In response to CAIR, boilermakers increased their membership by 35 percent in only two
years (between 1999 and 2001) to meet peak labor demand.
In summary, a range of available and proven pollution control technologies exists to meet the
requirements of EPA’s proposed Transport Rule and Air Toxics Rule. In many cases, these technologies,
some of which have been operating for decades, have a long track record of effective performance at
many coal-fired power plants in the U.S.
The electric power sector has shown that it is capable of planning for and installing pollution controls on a
large portion of the nation’s fossil fuel generating capacity in a relatively short period of time. Suppliers
have demonstrated the ability to provide pollution control equipment in a timely manner, and the skilled
labor needed to install it should be available to meet the challenge as well. Examples of successful
pollution control retrofits are provided throughout this report.
4|Page
Introduction
The U.S. Environmental Protection Agency (EPA) is currently developing two major air quality rules
under the Clean Air Act (“CAA” or “the Act”) to reduce air pollution from power plants: (1) the
Transport Rule, and (2) the Air Toxics Rule. These regulations will require certain power plants that have
not installed pollution control equipment to do so and others to improve their performance. The
discussion that follows provides an overview of these regulations, including a discussion of the sources
regulated by the rules and the air pollutants the rules address. Both rules are being developed in response
to court decisions overturning prior EPA regulatory programs and have long been anticipated by the
electric power sector.
Transport Rule
The Transport Rule—proposed by EPA in July 2010—is designed to reduce the interstate transport of
harmful air pollution from power plants in the eastern U.S. as required by the CAA. The “good neighbor”
provisions of the Act require states to prohibit air pollution emissions that “contribute significantly” to a
downwind state’s air quality problems.1 For example, EPA found that power plants in West Virginia
significantly affect the air quality status of counties in Ohio, Indiana, Pennsylvania, Kentucky, and
Michigan—hindering these states from achieving or maintaining federal air quality standards.2
In keeping with the purpose of the “good neighbor” provisions in the Act, the Transport Rule will assist
states and cities across the eastern U.S. in complying with the national, health-based fine particulate, or
PM2.5, and 8-hour ozone standards by limiting SO2 and NOx emissions from power plants in the region.
Fine particulates can be inhaled deep into the lungs, and have been linked to increased hospital
admissions and emergency room visits for various respiratory or cardiovascular diseases, respiratory
illness and symptoms, lung function changes, and increased risk of premature death. Ground-level ozone
is a respiratory irritant that adversely affects both people with respiratory disease and healthy children and
adults. Exposure to ozone through inhalation can result in reduced lung function and inflamed airways,
aggravating asthma or other lung diseases. As with fine particulate matter, ozone exposure is also linked
to increased risk of premature death.
The Transport Rule will replace the earlier Clean Air Interstate Rule (CAIR) that EPA had issued in
March 2005.3 Under CAIR, EPA limited NOx and SO2 emissions from 28 states and the District of
Columbia, and directed each state to file a plan for meeting those limits, or emission caps. In July 2008,
however, the U.S. Court of Appeals for the District of Columbia Circuit struck down CAIR after finding
several flaws in the rule.4 In a subsequent ruling, the court determined that CAIR could remain in place
until EPA developed a replacement program.5
Table 1. The Clean Air Transport Rule
Regulated Pollutants
Sulfur dioxide (SO2)
Nitrogen oxides (NOx)
5|Page
Affected Sources
Fossil fuel-fired power
plants 25 MW and larger
in 31 eastern states and
DC
Compliance Dates
Phase 1: 2012
Phase 2: 2014
Regulatory Mechanism
EPA’s preferred approach
would allow intrastate
trading among covered
power plants with some
limited interstate trading
EPA’s proposed emissions caps for SO2 and NOx are summarized in the following figures. EPA notes in
the proposed rule that additional ozone season (May 1 to September 30) NOx reductions will likely be
needed to attain the national ozone standards.6 Therefore, the agency plans to propose a new transport
rule in 2011, to become final in 2012, to reflect the revised National Ambient Air Quality Standards
(NAAQS) for ozone when they are promulgated. While the Transport Rule only proposes to require
reductions from the power sector, EPA notes, “it is possible that reductions from other source categories
could be needed to address interstate transport requirements related to any new NAAQS.”7
EPA estimates that the proposed rule would yield $120 billion to $290 billion in annual health and
welfare benefits in 2014,8 which exceed the estimated $2.8 billion in annual costs that EPA estimates
power plants will incur to comply with the rule by a factor of more than 30.9 To meet the new
requirements, EPA expects plants will employ a wide range of strategies, including operating already
Clean Air Transport Rule: Proposed NOx Emissions Caps
EPA’s proposed Transport Rule would establish two NOx programs: (1) an annual NOx program, and (2) an ozone season
(summer time) NOx program (see map below). Annual NOx emissions would be capped at 1.4 million tons per year beginning in
2012. The 2012 cap represents a 10 percent increase over 2009 emissions levels. Ozone season NOx emissions would be
capped at 0.6 million tons beginning in 2012. The ozone season cap represents a 15 percent increase over 2009 emissions levels.
5.0
2.0
4.0
Ozone season states
1.6
Annual NOx
3.0
1.2
annual states
2.0
0.8
2012
proposed cap
2012
proposed cap
0.4
million tons
million tons
1.0
0.0
2000
Ozone
Season NOx
2001
2002
2003
2004
2005
2006
2007
2008
2009
0.0
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
Clean Air Transport Rule: Proposed SO2 Emissions Caps
EPA’s proposed Transport Rule would establish two independent trading programs for SO2: (1) group 1 states; and (2) group 2
states (see maps below). SO2 emissions from group 1 states would be capped at 3.1 million tons per year beginning in 2012 and
1.7 million tons per year beginning in 2014. The 2012 cap represents a 13 percent reduction below 2009 emissions levels. SO2
emissions from group 2 states would be capped at 0.8 million tons beginning in 2012. The 2012 cap for group 2 states represents
a 29 percent reduction below 2009 emissions levels.
8.0
2.5
SO2
SO2
2.0
6.0
1.5
Group 1 states
Group 2 states
4.0
2012
proposed phase 1 cap
1.0
proposed cap
2012
2.0
2014
0.0
2000
0.5
million tons
million tons
proposed phase 2 cap
2001
2002
6|Page
2003
2004
2005
2006
2007
2008
2009
0.0
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
installed pollution control equipment more frequently, using low sulfur coal, or installing new control
equipment.
Air Toxics Rule
The U.S. EPA’s proposed Air Toxics Rule will establish, for the first time, federal limits on hazardous air
pollutant (HAP) emissions from coal- and oil-fired power plants. The HAPs covered include mercury,
lead, arsenic, hydrogen chloride, hydrogen fluoride, dioxins/furans, and other toxic substances identified
by Congress in the 1990 amendments of the CAA. The rule establishes “maximum achievable control
technology” (MACT) limits for many of these.
The U.S. EPA’s prior effort to regulate HAP emissions from power plants was overturned by court
challenges. On February 8, 2008, a federal court held that EPA violated the CAA when it sought to
regulate mercury-emitting power plants through the Clean Air Mercury Rule (CAMR), an interstate capand-trade program issued by EPA in March 2005.10 The court concluded that EPA violated the CAA by
failing to make a specific health-based finding to remove electric generating units from regulation under
CAA section 112.a
On March 16, 2011, EPA proposed its replacement for CAMR that would establish numerical MACT
emission limits for existing and new coal-fired electric power plants that would cover mercury, particulate
matter (as the surrogate for non-mercury toxic metals), and hydrogen chloride (as the surrogate for toxic
acid gases). The proposed rule would also establish work practice standards for organic air toxics (e.g.,
dioxins and furans).11 EPA projects the proposed rule will reduce mercury emissions from covered power
plants by 91 percent, acid gas emissions by 91 percent, and SO2 emissions by 55 percent.12 The projected
mercury reductions are in the range of what a number of states already require for coal-fired power
plants.13 A consent decree with public health and environmental groups requires EPA to finalize the
standards by November 16, 2011. Table 2 summarizes elements of the proposed Air Toxics Rule.
EPA estimates that the Air Toxics Rule would yield $140 billion in annual health and welfare benefits in
2016.14 The estimated annual cost of the program is $10.9 billion.15 EPA emphasizes that the proposed
rule would cut emissions of pollutants that are of particular concern for children. Mercury and lead can
adversely affect developing brains–including effects on IQ, learning, and memory.
Table 2. The Air Toxics Rule
Regulated Pollutants
Mercury
Non-mercury metals,
such as arsenic,
chromium, cadmium,
and nickel
Affected Sources
Coal- and oil-fired power
plants 25 MW and larger
Compliance Dates
Early 2015
Note: EPA can grant a one
year extension for a source
to install controls
Regulatory Mechanism
Numerical emission limits
for mercury, other toxic
metals, and acid gases;
work practice standards for
organic air toxics (e.g.,
dioxins/furans)
Organic HAPs (e.g.,
dioxins/furans)
Acid gases (HCl, HF)
a
“EPA’s removal of these [electric generating units] from the section 112 list violates the CAA because section
112(c)(9) requires EPA to make specific findings before removing a source listed under section 112; EPA concedes
it never made such findings. Because coal-fired [electric generating units] are listed sources under section 112,
regulation of existing coal-fired [electric generating units’] mercury emissions under section 111 is prohibited,
effectively invalidating CAMR’s regulatory approach.” New Jersey v. EPA, 517 F.3d 574 (D.C. Cir. 2008).
7|Page
Overview of Air Pollution Control Technologies
There are a wide range of technologies available for controlling air pollution emissions from coal-fired
power plants. The most appropriate combination of control technologies will vary from plant-to-plant
depending on the type and size of the electric generating unit, age, fuel characteristics, and the boiler
design.
Many of the air pollutants targeted by the proposed Transport Rule and the Air Toxics Rule are captured
to some degree by existing air pollution control devices. Table 3 summarizes the various pollutants and
the technologies that are currently being applied or may be applied in the future to control them. In many
cases, technologies designed to control one pollutant will also control others. These “co-benefits” may or
may not be adequate to achieve compliance with the Transport Rule or the Air Toxics Rule. As a result,
in some cases, it may be necessary to add separate control technologies for some pollutants.
Table 3. Control Technology Emission Reduction Effect
SO2
NOx
Mercury
(Hg)
HCl
PM
Combustion Controls
N
Y
C
N
N
Selective Non-Catalytic
N
Y
N
N
N
Reduction (SNCR)
Selective Catalytic Reduction
N
Y
C
N
N
(SCR)
Particulate Matter Controls (i.e.,
N
N
C
N
Y
ESP or baghouse)
Lower Sulfur Fuel
Y
C
N
C
N
Dry Scrubber
Y
N
C
Y
C*
Wet Scrubber
Y
N
C
Y
C
Dry Sorbent Injection (DSI)
Y
C
C
Y
N
Activated Carbon Injection
N
N
Y
N
N
(ACI)
N = Technology has little or no emission reduction effect
Y = Technology reduces emissions
C = Technology is normally used for other pollutants, but has a co-benefit emission reduction effect
* When used in combination with a downstream particulate matter control device, such as a baghouse
Dioxins/ Furans
Y
N
C
C
N
N
N
C
Y
Methods for Controlling SO2 Emissions
SO2 is a highly reactive gas linked to a number of adverse effects on the human respiratory system. In
2008, power plants accounted for 66 percent of the national SO2 emissions inventory,16 with the vast
majority of this contribution (more than 98 percent) coming from coal-fired power plants.17
There are two basic options for controlling SO2 emissions from coal-fired power plants, which is formed
from the oxidation of sulfur in the fuel: (1) switching to lower sulfur fuels; and (2) SO2 capture, including
Flue Gas Desulfurization (FGD), or more commonly referred to as “scrubbing.” Table 4 shows the
various methods for controlling SO2 emissions. These methods include those that have been widely used
on power plants, such as low sulfur coal and scrubbing, as well as less costly technologies that may be
more attractive for smaller boilers, such as dry sorbent injection (DSI).
8|Page
Table 4. SO2 Emissions Control Methods
Methods of Control
Lower Sulfur Fuel
Dry Sorbent Injection
Dry Scrubber with Fabric
Filter
Wet Scrubber
Wet Scrubber Upgrades
Co-benefit Methods of Control
None
Method – Lower sulfur fuel reduces SO2 formation
Reagent – None
Typical fuel types – Powder River Basin coal and lower sulfur bituminous coal
Capital Cost – Low
Co-benefits – May reduce NOx, HCl, and HF emissions
Method – Dry Sorbent Injection captures SO2 at moderate rates, downstream PM
control device captures dry product
Reagent – Trona, sodium bicarbonate, hydrated lime
Typical Fuel Types – Most often solid fuels (i.e., coals – lignite, sub-bituminous,
bituminous)
Capital Costs- Low to moderate
Co-benefits – NOx and HCl and HF reduction, Hg reduction, removal of chlorine,
a precursor to dioxins/furans
Method – Reagent + water react to capture acid gases and dry product captured
in downstream fabric filter
Reagent – Hydrated lime
Typical Fuel Types – Coal
Capital Costs – High
Co-benefits – High SO2 and Hg capture (esp. bituminous coals), high PM and
HCl capture
Method – Reagent + water react to capture acid gases
Reagent – Limestone, lime, caustic soda
Typical Fuel Types – Coal, petroleum coke, high sulfur fuel oil
Capital Costs – High
Co-benefits –Highest SO2 capture, high oxidized Hg and high HCl capture, PM
capture
Method – Upgrade older scrubbers to provide performance approaching those of
new scrubbers
Reagent – Limestone, lime, etc.
Typical Fuel Types – Coal, petroleum coke, high sulfur fuel oil
Capital Costs – Low to moderate
Co-benefits – Same as wet scrubber
SO2 is a key pollutant that often is the major driver in emission control technology
selection
Lower Sulfur Coal
Changing to lower sulfur coal was the most widely used approach for compliance with the Acid Rain
Program (Title IV of the 1990 Clean Air Act Amendments). Certain coal types are naturally low in
sulfur, such as sub-bituminous coal mined in the Powder River Basin (PRB) of Montana and Wyoming.b
Some facilities cannot burn 100 percent PRB coal without substantial modifications to the boiler or fuel
handling systems. These facilities can blend PRB or another lower sulfur coal with a bituminous coal to
reduce emissions. Facilities that are not able to burn lower sulfur coals or facilities needing greater SO2
emissions reductions may need some form of flue gas treatment.
b
Coal is classified into four general categories, or “ranks.” They range from lignite through sub-bituminous and
bituminous to anthracite. Sub-bituminous and bituminous coals are the most widely used coal types, and the SO2
emissions from burning these fuels can vary by a factor of 10 or more, depending upon the fuel sulfur content and
the heating value of the fuel. Lignite fuels have low heating values, making them uneconomical to transport, and are
generally limited in use to mine-mouth plants. Anthracite coal is used in very few power plants.
9|Page
Co-benefits of low sulfur coal – PRB coal is relatively low in nitrogen, which results in lower NOx
emissions. It is also very low in chlorine, so hydrogen chloride (HCl) emissions are low for PRB coal.
Flue Gas Desulfurization (FGD) or “Scrubbing”
As EPA and states have further limited SO2 emissions, an increasing number of coal-fired power plants
have installed FGD systems. FGD controls enable a plant operator to use a wider variety of coals while
maintaining low SO2 emissions. There are two basic forms of FGD – wet and dry. As shown in Table 5,
nearly two-thirds of the coal-fired power plant capacity in the United States is scrubbed or is projected to
be scrubbed in the near future. Most plant operators have opted for wet FGD systems, particularly on
larger coal-fired power plants. In response to the Clean Air Interstate Rule, coal-fired power plants added
about 60 gigawatts (GW) of scrubbers in the three year period from 2008 through 2010.18
Table 5. Coal-Fired Power Plant Scrubbers19
Scrubber Type
FGD (wet)
FGD (dry)
Total Scrubbed
No scrubber
Total
Sum of Capacity (%)
170 GW (52%)
22 GW (7%)
192 GW (59%)
134 GW (41%)
326 GW
# Boilers
371
114
485
788
1,273
Average Capacity (MW)
457
196
396
171
256
Wet Scrubbers
Wet scrubbers are capable of high rates of SO2 removal. In a wet FGD system, a lime or limestone slurry
reacts with the SO2 in the flue gas within a large absorber vessel to capture the SO2, as shown in
Figure 1.20 Wet FGD systems may use lime or limestone. Lime is more reactive and offers the potential
for higher reductions with somewhat lower capital
cost; however, lime is also the more expensive
reagent. As a result, limestone-forced oxidation
(LSFO) wet scrubber technology is the most widely
used form of wet FGD and is more widely used on
coal-fired power plants than every other form of FGD
combined. State-of-the-art LSFO systems are capable
of providing very high levels of SO2 removal – on the
order of 98 percent or more.
The first wet scrubber system in the U.S. was designed
by Black & Veatch and installed in 1968 at the
Lawrence Energy Center in Kansas. More than 40
years later, the system is still in operation, and the
facility is undertaking a major upgrade to improve the
system’s performance. The facility is also adding a
pulse jet fabric filter.21
In the absorber, the gas is cooled to below the
saturation temperature, resulting in a wet gas and high
rates of capture. Modern wet scrubbers typically have
SO2 removal rates of over 95 percent and can be in the
range of 98 percent to 99 percent.22 The reacted
Figure 1. Wet Flue Gas Desulfurization
Image courtesy of Babcock and Wilcox Company
10 | P a g e
limestone and SO2 form a gypsum by-product that is often sold for the manufacturing of wallboard.
Because a wet FGD system operates at low temperatures, it is usually the last pollution control device
before the stack. The wet FGD absorber is typically located downstream of the PM control device (most
often an electrostatic precipitator though many power plants have baghouses) and immediately upstream
of the stack. Wet FGD is frequently used to treat the exhaust gas of multiple boilers with the gases being
emitted through a common stack. A single absorber can handle the equivalent of 1,000 megawatts (MW)
of flue gas.
Wet scrubber retrofits are capital intensive due to the amount of equipment needed, and recent
installations for the Clean Air Interstate Rule have been reported to have an average cost of $390/kW.23
EPA estimates a capital cost of about $500/kW ($2007) for a wet scrubber (limestone forced oxidation)
on a 500 MW coal unit.24 There can be, however, a significant variation in costs depending upon the size
of the unit and the specifics of the site. Generally, smaller boilers (under 300 MW) have been shown to
be significantly more expensive to retrofit with wet scrubbers (capital cost normalized to a $/KW basis)
than larger boilers due to economies of scale. The economies of scale become less significant as boiler
size increases.25 As a result, wet scrubbers are a less attractive alternative for controlling SO2 on small
units. Companies can sometimes offset the cost of installing wet scrubber technology by switching to less
expensive high sulfur coal supplies. Because of the high capital costs of the technology, wet scrubbers
are generally only installed on power plants where the owner expects to operate the plant for an extended
number of years.
Due to their complexity and the size of the equipment, EPA estimates that the total time needed to
complete the design, installation, and testing of a wet FGD system at a typical 500 MW power plant with
one FGD unit is 27 months, and longer if multiple boilers or multiple absorbers are necessary. Actual
installation times will vary based upon the specifics of the plant, the need to schedule outages with FGD
hook up, and other factors.
Co-benefits of wet FGD – FGDs have been shown to be
effective at removing other pollutants including particulate
matter, mercury, and hydrochloric acid. For this reason,
facilities that are equipped with wet or dry FGD systems may
avoid the need to install additional controls for hazardous air
pollutants.
Dry Scrubbers
Dry scrubber technology (dry FGD) injects hydrated lime and
water (either separately or together as a slurry) into a large
vessel to react with the SO2 in the flue gas. Figure 2 shows a
schematic of a dry scrubber.
The term “dry” refers to the fact that, although water is added
to the flue gas, the amount of water added is only just enough
to maintain the gas above the saturation (dew point)
temperature. In most cases, the reaction products and any
unreacted lime from the dry FGD process are captured in a
downstream fabric filter (baghouse), which helps provide
additional capture of SO2. Modern dry FGD systems typically
provide SO2 capture rates of 90 percent or more.
11 | P a g e
Figure 2. Dry Flue Gas Desulfurization
Image courtesy of Babcock and Wilcox Company
Historically, dry FGDs have been used primarily on low sulfur coals because the reagent, lime, is more
expensive than reagents used in wet FGD systems. Also, because the systems are designed to maintain
the flue gas temperatures above the dew point, this limits the amount of SO2 that can be treated by a spray
dryer. Another form of dry FGD, circulating dry scrubber systems (CDS), inject the water and lime
separately, and have been shown to achieve high SO2 removal rates in excess of 95 percent on higher
sulfur coals. Lime is more costly than limestone, the most commonly used reagent for wet scrubber
systems.
Case Study: Dry Scrubber
In Massachusetts, First Light’s Mt. Tom Power Plant, a 146 MW coal-fired unit that went into service in
1960, installed state-of-the-art pollution control equipment in 2009 to meet state and federal
environmental regulations. In December 2009, the plant installed a circulating dry scrubber to reduce SO2
and mercury emissions during a routine outage. A precipitator and baghouse were also installed to remove
particulate matter emissions. Total project costs were $55 million, or $377/kW. The project has reduced
the plant's SO2 emissions by approximately 70 percent, with the plant’s 2009 SO2 emission rate of 0.73 lbs
SO2/mmBtu dropping to 0.22 lbs SO2/mmBtu in 2010.
Source: U.S. Environmental Protection Agency, Clean Air Markets-Data and Maps;
http://camddataandmaps.epa.gov/gdm/index.cfm?fuseaction=emissions.wizard (accessed March 17, 2011).
Dry FGD systems tend to be less expensive than wet FGD systems because they are less complex and
generally smaller in size. They also use less water. The lower reagent cost of wet FGD and the ability to
burn lower cost, higher sulfur coals make wet FGD more attractive for large facilities. EPA estimates a
capital cost of about $420/kW ($2007) for a dry scrubber (lime spray dryer) on a 500 MW coal unit.26
The Turbosorp system installed at the AES Greenidge plant in New York cost $229/KW ($2005).27
Depending upon the specifics of the facility to be retrofit, the cost could be higher in some cases.
Dry FGD systems are less complex and generally require less time to design and install than wet FGD
systems. The Institute to Clean Air Companies (ICAC) estimates that dry scrubbers can be installed in a
time frame of 24 months.28
Co-benefits of Dry FGD – Dry FGD pollutant co-benefits include greatly enhanced capture of hazardous
air pollutants, especially PM, mercury and HCl (as discussed later in the report).
Upgrades to Existing Wet FGD Systems
Modern wet FGD systems are capable of SO2 removal rates in the range of 98 percent or more.
Limestone wet scrubber removal efficiencies have improved dramatically since the 1970s as shown in
Figure 3.29 As a result, there are opportunities to improve scrubber performance from many existing
scrubbers that were built in the 1970s and 1980s. An advantage of this approach is that substantial SO2
reductions are possible at a far lower cost than installing a new scrubber and in a much shorter period of
time. Each scrubber upgrade is unique, so cost and schedule will vary. Depending upon the scope of a
scrubber upgrade, a scrubber upgrade could be implemented in under a year as opposed to three to four
years for a new scrubber installation. All key areas of many older FGD systems (absorber, reagent
preparation, and dewatering) can benefit from modern upgrades. Because each system is unique, an
12 | P a g e
effective FGD system-wide upgrade process is most successful after an extensive system review and
diagnostics.
There have been numerous examples of FGD upgrades over the last several years that have improved SO2
removal efficiencies. For example, the Fayette Station Unit 3, a 470 MW tangentially-fired coal unit in
Texas, completed an upgrade to its 1988-vintage scrubber in 2010. The plant’s control efficiency was
increased from about 84 percent to 99 percent, higher than the guaranteed SO2 removal efficiency of 95.5
percent.30 In Kentucky, E.On’s Trimble
County Generating Station Unit 1, a 550 MW
tangentially-fired coal boiler, completed a
scrubber upgrade in 2006. Its scrubber,
installed in the 1980s, was originally designed
for 90 percent removal efficiency. The
scrubber system is now able to achieve over
99 percent SO2 removal efficiency.31 In
Indiana, NiSource upgraded the scrubbers at
Schahfer Units 17 and 18 in 2009.32 The
scrubber upgrades increased SO2 removal
efficiency from 91 percent to 97 percent.33
Dry Sorbent Injection (DSI)
Figure 3. Historical Trends in Limestone Wet Scrubber SO2
Removal Efficiency of Limestone Wet Scrubbing Systems
DSI is the injection of dry sorbent reagents that react with SO2 and other acid gases, with a downstream
PM control device to capture the reaction products.
The most common DSI reagent in use is Trona, a naturally occurring mixture of sodium carbonate and
sodium bicarbonate mined in some western states. Other reagents have also been used, such as sodium
bicarbonate and hydrated lime. Sodium bicarbonate is capable of higher SO2 removal efficiencies than
Trona because it is more reactive. Trona can achieve varying levels of SO2 reductions, from a range of
30-60 percent when injected upstream of an ESP, or up to 90 percent when injected upstream of a fabric
filter. Fabric filters allow greater contact between the gas and the injected sorbent than ESPs, enabling
better removal for any given reagent treatment rate. The level of removal will vary depending upon the
circumstances of the facility and the injection system.
DSI equipment is relatively simple and inexpensive when compared to a scrubber and can be installed
typically within 12 months.34 Unlike scrubbers that require additional reaction chambers to be installed,
in DSI the reaction occurs in the existing ductwork and air pollution control equipment. The basic
injection system with storage silo costs around $20/kW; however, in some cases additional storage and
material handling may be necessary that will add cost. But, even with the additional equipment, the
capital cost of a DSI system will be substantially less than that of a full wet or dry scrubber, which can
cost as high as $400/kW. Reagents used in DSI are more costly than those used in wet or dry scrubbers,
and the reagent is not as efficiently utilized, which can contribute to a higher cost of control in terms of
dollars per ton of SO2 reduced.
13 | P a g e
Case Study: Dry Sorbent Injection
Conectiv Energy installed a DSI Trona system at Edge Moor Units 3-4 to comply with Delaware’s multipollutant emissions control rule. The project was several years in planning and operated from 2009 to mid2010. The emission rates went from 1.2 lbs SO2/mmBtu to 0.37 lbs SO2/mmBtu with the use of Trona.
Since the purchase of the facility by Calpine in mid-2010, coal is no longer burned thus eliminating the need
for the Trona system. In New York, NRG installed a Trona system at its Dunkirk (530 MW) and Huntley
stations (380 MW). This project is the first of its kind in the U.S. in which Trona and powder-activated
carbon (PAC) are simultaneously injected into the flue gases to control both SO2 and mercury emissions.
The DSI system included several Trona storage and injection systems with equipment buildings, 6000 feet of
transport piping, Trona railcar unloading and transfer systems, and associated bulk storage silos.
Performance tests indicate that emissions of SO2 have been reduced by over 55 percent, mercury levels
have been reduced by over 90 percent, and particulate levels have been reduced to less than 0.010
lbs/mmBtu.
Source: Pietro, J. and Streit, G. (NRG Energy). “NRG Dunkirk and Huntley Environmental Retrofit Project.” Presented to Air & Waste
Management Association – Niagara Frontier Section, September 23, 2010.
Co-benefits of DSI – DSI has been shown to be very effective in the capture of the acid gases, HCl and
HF. DSI has been shown to enhance mercury capture for facilities that burn bituminous coal by removing
sulfur trioxide (SO3) that is detrimental to mercury capture through ACI. In the case of PRB coals, the
impact on mercury capture might be negative. Injection of Trona or sodium bicarbonate can also remove
NOx in the range of 10-20 percent, although NOx removal is generally not a principal objective of DSI.35
If DSI is installed at a point in the gas stream that is upstream of the dioxins/furans formation
temperature, it is expected to remove the precursor chlorine that leads to their production.
Methods for Controlling NOx Emissions
Nitrogen oxides (NOx) are an acid rain precursor and a contributor to the formation of ground-level
ozone, which is a major component of smog. In 2008, power plants accounted for 18 percent of the
national NOx emissions inventory. Most of the NOx formed during the combustion process is the result
of two oxidation mechanisms: (1) reaction of nitrogen in the combustion air with excess oxygen at
elevated temperatures, referred to as thermal NOx; and (2) oxidation of nitrogen that is chemically bound
in the coal, referred to as fuel NOx. Controlling NOx emissions is achieved by controlling the formation
of NOx through combustion controls or by reducing NOx after it has formed through post-combustion
controls. Table 6 summarizes key NOx control technologies.
14 | P a g e
Table 6. NOx Emissions Control Methods
Methods of Control
Combustion Controls
Selective Non-Catalytic
Reduction
Selective Catalytic
Reduction
Method – Reduce NOx formation in the combustion process itself for
levels of reduction that vary by application
Reagent – None
Typical fuel types – All fuels
Capital Cost – Low to moderate
Co-benefits – Potential impacts on Hg, CO and precursors of
dioxins/furans
Method – Reagent injected into furnace reacts with and reduces NOx at
moderate removal rates of about 30%
Regent – Urea or ammonia
Typical Fuel Types – Most often solid or liquid fuels
Capital Costs- Low
Co-benefits - None
Method – Reagent reacts with NOx across catalyst bed and reduces
NOx at high rates of about 90%
Reagent – Ammonia (or urea that is converted to ammonia)
Typical Fuel Types – Any fuel
Capital Costs – High
Co-benefits – Oxidation of Hg for easier downstream capture in a wet
scrubber, reduction of dioxins/furans
Co-benefit Methods of Control
Low Sulfur Coal
Conversion to PRB coal for SO2 reduction will also reduce NOx due to
lower fuel nitrogen in PRB coal
Dry Sorbent Injection
DSI with Trona can provide NOx reduction of about 10-15%
Combustion Controls
Combustion controls minimize the formation of NOx within the furnace and are frequently the first
choice for NOx control because they are usually lower in cost than post-combustion controls. For most
forms of combustion control, once installed there is little ongoing cost because there are no reagents or
catalysts to purchase. Combustion controls reside within the furnace itself, not in the exhaust gas stream,
and include such methods as low NOx burners (LNB), over-fire air (OFA), and separated over-fire air
(SOFA). Reburning technology is another combustion control option, but it chemically reduces NOx
formed in the primary combustion zone. Reburning technology may also utilize natural gas.
Most utilities have already achieved substantial reductions in NOx emissions from implementation of
combustion controls, sometimes in combination with post-combustion controls. There are some facilities
that can still benefit from combustion controls, but these are generally the smaller units where utilities
have not yet invested in NOx controls.
The capital cost of these combustion controls will vary; however, the capital cost is generally far less than
that of more costly post-combustion control options, such as Selective Catalytic Reduction (SCR). The
capital costs of combustion controls could be anywhere from about $10/kW to several times that, but
generally fall below $50/kW. Except for gas reburning, there is little or no increase in operating or fuel
costs.
Co-benefits of Combustion NOx Controls – Combustion controls may enhance mercury capture at coalfired power plants because they can increase the level of carbon in the fly ash. While higher carbon in the
15 | P a g e
fly ash is generally viewed negatively because it is the result of incomplete combustion, it does provide a
real benefit in enhancing mercury capture. Combustion controls can also have a positive impact on CO
emissions and on concentrations of organic precursors to dioxins/furans.
Post-Combustion NOx Controls
There are limits to the level of NOx control that can be achieved with combustion controls alone.
Therefore, post-combustion controls are necessary to achieve very low emissions of NOx. Combustion
NOx controls and post-combustion NOx controls can, and often are, used in combination. About half of
the nation’s coal fleet has already installed advanced post-combustion NOx controls (Table 7).
Table 7. Coal-Fired Power Plant Post-Combustion NOx Controls36
Control Type
SCR
SNCR
Total Post-Combustion NOx
No Post-Combustion NOx
Total
Sum of Capacity (%)
129 GW (40%)
29 GW (9%)
158 GW (49%)
842 GW (51%)
324 GW
# Boilers
259
172
431
842
1,273
Average Capacity (MW)
499
166
366
198
255
Selective Catalytic Reduction (SCR)
SCR technology, which has been in use at coal-fired power plants for more than 15 years in the United
States, is a post-combustion NOx control system that is capable of achieving greater than 90 percent
removal efficiency.37 The first large-scale coal-fired selective catalytic reduction (SCR) system on a new
boiler in the U.S. was placed in service in 1993 in New Jersey, and the first retrofit in the U.S. went into
service in 1995 at a power plant in New Hampshire.38 About 130 GW of the total coal-fired generating
capacity in the U.S. is now equipped with SCR, and more SCRs are planned for existing units. Between
2001 and 2005, the electric industry installed more than 96 GW of SCR systems in response to the NOx
SIP Call. Coal plant operators installed an additional 20 GW of SCR from 2008 through 2010 in response
to the Clean Air Interstate Rule.39
SCR utilizes ammonia as a reagent that reacts with NOx on the surface of a catalyst. The SCR catalyst
reactor is installed at a point where the temperature is in the range of about 600°F-700°F, normally
placing it after the economizer and before the air-preheater of the boiler. The SCR catalyst must
periodically be replaced. Typically, companies will replace a layer of catalyst every two to three years.
Multiple layers of catalysts are used to increase the reaction surface and control efficiency (Figure 4).
SCR system capital costs will vary over a wide range depending upon the difficulty of the retrofit. Some
retrofits have been reported to cost under $100/kW, while others have been reported to cost over
$200/kW.40 Operating costs include ammonia reagent, periodic catalyst replacement, parasitic power, and
fixed operating costs.
The EPA estimates that the total time needed to complete the design, installation, and testing at a
facility with one SCR unit is about 21 months, and longer for plants that have multiple units to be
retrofitted with SCR.41
16 | P a g e
Selective Non-Catalytic Reduction (SNCR)
SNCR is another post-combustion NOx control technology. It typically achieves in the range of 25-30
percent NOx reduction on units equipped with low NOx burners. SNCR reduces NOx by reacting urea or
ammonia with the NOx at temperatures around 1,800°F-2,000°F. Therefore, the urea or ammonia is
injected into the furnace post-combustion zone itself and, like SCR, reduces the NOx to nitrogen and
water.
The capital cost of SNCR is typically much less than that of SCR, falling in the range of about $10$20/KW, or about $4 million or less for a 200 MW plant. The operating cost of SNCR is primarily the
cost of the ammonia or urea reagent. SNCR is most commonly applied to smaller boilers. This is partly
because the economics of SCR
are more challenging for small
boilers. Furthermore, when
emissions regulations allow
averaging or trading of NOx
emissions among units under a
common cap, installing an SCR
on a large boiler allows utilities
to over-control the large unit and
use less costly technology, such
as SNCR or combustion controls,
for NOx control on smaller units.
SNCR systems are relatively
simple systems that can be
installed in a period of about 12
months.
Hybrid SNCR/SCR
SNCR and SCR may be
Figure 4. Selective Catalytic Reduction (Retrofit Installation)
Image courtesy of Babcock and Wilcox Company
combined in a “hybrid” manner.
In this case, a small layer of
catalyst is installed in ductwork
downstream of the SNCR
system. With the downstream catalyst, the SNCR system can be operated in a manner that provides
higher NOx removal rates while using the SCR catalyst to mitigate the undesirable ammonia slip from the
SNCR system. Although some NOx reduction occurs across the SCR catalyst, its function is primarily as
a means to reduce ammonia slip to an acceptable level. This approach has been demonstrated at the
Greenidge power plant in upstate New York, but has not been widely adopted.42 For some smaller boilers
that can accommodate the needed ductwork modifications necessary for “hybrid” SNCR/SCR, this may
be an attractive technology for reducing NOx emissions beyond what SNCR is able to achieve.
The hybrid SNCR/SCR system installed at Greenidge was part of a multi-pollutant control system
designed to demonstrate a combination of controls that could meet strict emissions standards at smaller
coal-fired power plants.43 The multi-pollutant control system was installed on AES Greenidge Unit 4, a
107 MW, 1953-vintage tangentially-fired boiler. The facility fires high sulfur eastern U.S. bituminous
coal. The multi-pollutant control system consists of a hybrid SNCR/SCR technology to control NOx, a
circulating fluidized bed dry scrubbing technology to control SO2, mercury, SO3, hydrogen chloride, and
17 | P a g e
particulate matter, and an activated carbon injection system to control mercury emissions. Total capital
cost of the system was $349/kW (2005$), about 40 percent less than the estimated cost of full SCR and
wet scrubbers—$114/kW for the hybrid SNCR/SCR system, $229/kW for the circulating dry scrubber
system and $6/kW for the activated carbon injection system. The plant has achieved 95 percent SO2
control, 98 percent mercury removal, and 95 percent SO3 and HCl removal.44
Co-benefits of post-combustion NOx controls – SNCR has no known co-benefit effects on other
pollutants. SCR, on the other hand, has the co-benefit effect of enhancing oxidation of elemental
mercury, especially for bituminous coals. The effect of mercury oxidation is to enhance mercury capture
in a downstream wet FGD because the resulting ionic mercury is extremely water soluble. Several field
and pilot studies conducted in the U.S. have found increases in oxidized ionic mercury with the use of
SCR controls.45,46,47,48 For example, testing conducted at the Mount Storm coal-fired power plant in West
Virginia evaluated the effect of the unit’s SCR system on mercury speciation and capture.49 The facility
fires a medium sulfur bituminous coal. The test program found that the presence of an SCR catalyst can
significantly affect the mercury speciation profile. Measurements showed that the SCR catalyst improved
the mercury oxidation to levels greater than 95 percent, almost all of which was captured by the
downstream wet FGD system. In the absence of the SCR catalyst, the extent of oxidation at the inlet of
the FGD system was only about 64 percent. This effect, however, is much reduced with PRB coals
because halogen content in PRB coals is low. SCR catalyst can also mitigate emissions of dioxins and
furans.50,51
Methods for Controlling Hazardous Air Pollutant Emissions
HAPs from power plants include mercury, acid gases (HCl and HF), heavy metals (nickel, chromium,
arsenic, selenium, cadmium, and others), and organic HAPs (dioxins and furans). Many HAPs emitted by
power plants are captured to some degree by existing air pollution control technologies. However, EPA’s
proposed Air Toxics Rule will establish emissions standards that will require additional controls be
installed. For each of these HAPs, the potential methods for capture are discussed below.
Control of Mercury Emissions
Mercury is found within coal, with its concentration varying widely by coal type and even within coal
types. The mercury is released during combustion and becomes entrained in a power plant’s flue gas in
one of three forms; particle-bound mercury, gaseous elemental mercury, and gaseous ionic mercury.
Table 8 lists available methods to control mercury emissions for coal units.
18 | P a g e
Table 8. Mercury Emissions Control Methods
Methods of Control
Activated Carbon
Injection (ACI)
Halogen Addition
Method – Activated carbon adsorbs gaseous Hg, converting to particle
Hg that is captured in downstream PM control device
Reagent – Powdered Activated Carbon
Typical Fuel Types – Any fuel, but downstream PM control needed
Capital Costs – Low
Co-benefits – Some capture of dioxins/furans
Method – Halogen (bromine) addition to flue gas increases oxidized Hg
that is easier to capture in a downstream scrubber or in PM
control device
Reagent – Halogen containing additive
Capital Costs – Negligible
Co-benefits – None
Co-benefit Methods of Control
PM Controls (ESP, FF,
Method – Captures particle-bound mercury
multicyclone)
Dry Sorbent Injection
Method – Increases co-benefit and ACI Hg capture by removing SO3,
which suppresses mercury capture
Dry Scrubber with Fabric
Method – Hg captured in downstream fabric filter
Filter
Wet Scrubber
Method – Oxidized mercury captured in wet scrubber
NOx Catalyst
Method – Catalyst in SCR increases oxidation of Hg that is more
effectively captured in downstream wet scrubber
Activated Carbon Injection (ACI)
Mercury is often captured using injection of powdered activated carbon (activated carbon injection –
ACI) and capture of the injected carbon on a downstream PM capture device (ESP or a baghouse). An
ACI system is relatively simple and inexpensive, consisting of storage equipment, pneumatic conveying
system, and injection hardware (“injection lances”). Under cooperative agreements with the U.S.
Department of Energy, several coal plant operators conducted full-scale testing of ACI systems in 2001.52
ACI has been used to capture mercury by effectively converting some of the gaseous ionic and elemental
mercury to a particle-bound mercury that is captured in a downstream particulate matter control device,
such as an ESP or fabric filter. ACI is very effective at removing mercury except if high sulfur coals are
used, or if SO3 is injected for flue gas conditioning for ESPs, or if the facility has a hot-side ESP and no
downstream air pollution controls. SO3 interferes with mercury capture by ACI; however, upstream
capture of SO3 by DSI, if one is in place, should enable ACI to be more effective at capturing mercury.
Fortunately, most of the installed capacity of boilers firing high sulfur fuels is scrubbed and may not need
ACI.
Since 2003, many states have led the way on mercury control regulations by enacting statewide mercury
limits for power plants that require mercury capture rates ranging from 80 to 95 percent.53 At present,
about 25 units representing about 7,500 MW are using commercial ACI technologies for mercury control.
In addition, about 55,000 MW of new bookings are reported by the Institute of Clean Air Companies
(ICAC), a national association of companies providing pollution control systems for power plants and
other stationary sources.54
ACI systems cost in the range of $5/kW and can be installed in about 12 months or less, assuming a
baghouse is installed. PSEG’s Bridgeport Harbor Generating Station completed the construction and
19 | P a g e
installation of a baghouse and ACI system in under 2 years. The final connection of the controls was
completed during a six to eight week outage.
Case Study: ACI Controls
In response to a 2006 Minnesota state mercury law, Xcel Energy agreed to install an ACI system on the
900 MW Unit 3 at its Sherburne County plant (Sherco 3). The unit, which burns low sulfur western coal
from Montana and Wyoming, already had a dry scrubber operating to reduce SO2 emissions. Once it has
been tuned to the unit’s operational specifications, the ACI system is expected to reduce the plant’s
mercury emissions by about 90 percent. The system was completed in December 2009 for a total capital
cost of $3.1 million, or $3.46/kW. Wisconsin Power and Light installed ACI controls at its Edgewater
Generating Station. The system was operational in the first quarter of 2008. Edgewater Unit 5 is a 380
MW plant that fires PRB coal and is configured with a cold-side ESP for particulate control. The total
installed costs of the Edgewater Unit 5 ACI system was approximately $8/kW, or approximately $3.04
million.
Source: Southern Minnesota Municipal Power Agency. “Sherco 3: Environmental Controls.” August 2010,
http://www.smmpa.com/upload/Sherco%203%20brochure%202010.pdf (accessed March 17, 2011).
Starns, T., Martin, C., Mooney, J., and Jaeckels, J. “Commercial Operating Experience on an Activated Carbon Injection System, Paper
#08-A-170-Mega-AWMA.” Power Plant Air Pollutant Control MEGA Symposium. Baltimore, MD. August 25-28, 2008.
Co-benefits of ACI – ACI co-benefits include the reduction of dioxins and furans.
Halogen Addition
For applications where there is inadequate halogen for conversion of elemental mercury to ionic mercury,
such as some western coals, the addition of halogen will increase mercury conversion to the ionic form
and will permit higher capture efficiency through co-benefit capture or by ACI. Addition of halogen to
PRB coals or to activated carbon injected for mercury capture has been shown to make mercury capture
from PRB fired boilers with halogen addition generally high.55
Co-Benefit Methods for Mercury Capture
Of the three mercury forms previously mentioned, particle-bound mercury is the species more readily
captured as a co-benefit in existing emission control devices, such as fabric filters (also called
“baghouses”) or electrostatic precipitators (ESPs). Ionic mercury has the advantage that it is extremely
water soluble and is relatively easy to capture in a wet FGD/scrubber. Ionic mercury is also prone to
adsorption onto fly ash or other material, and may thereby become particle-bound mercury that is
captured by an ESP or fabric filter. Elemental mercury is less water soluble and less prone to adsorption,
thus remains in the vapor phase where it is not typically captured by control devices unless first converted
to another form of mercury more readily captured.
Fabric filters generally provide much higher co-benefit mercury capture than ESPs. Bituminous coalfired boilers with fabric filters can have high rates of mercury capture based on data collected by the U.S.
EPA during its Information Collection Request (ICR) supporting the development of the Air Toxics
Rule.56
20 | P a g e
Wet scrubbers with SCR controls upstream have been shown to be very effective in removing oxidized
(ionic) mercury. Therefore, when a wet scrubber is present, it is beneficial to take measures to increase
the oxidation of mercury upstream of the wet scrubber. Catalysts in SCR systems promote oxidation of
mercury, and SCR controls upstream of a wet FGD system have been shown to provide high mercury
capture in the range of 90 percent when burning bituminous coals.57 The precise level of oxidation and
capture will vary under different conditions. In a study by the Southern Company, five of its plants with
SCR and scrubbers captured an average of 87 percent of mercury over a period of several months.58
Co-benefit capture rates of mercury in ESPs, fabric filters, scrubbers, or other devices for bituminous
coals are generally greater than that for PRB coals. This is because the higher halogen content (e.g.,
chlorine) found in eastern coals promotes formation of oxidized mercury.59
Acid Gas Control Methods
Strong acids, such as hydrogen chloride (HCl) and hydrogen fluoride (HF), result from the inherent
halogen content in the coal that is released during combustion to form acids as the flue gas cools. As with
mercury content, the concentration of halogens in the coal varies widely by coal type and even within coal
types. Chlorine is of greatest concern because it is usually present in higher concentrations than other
halogens in U.S. coals. The U.S. EPA’s proposed Air Toxics Rule for power plants sets a numerical
emission limit for HCl. The HCl limit also functions as a surrogate limit for the other acid gases, which
are not given their own individual emission limits under the proposed rule.
Table 9 shows HCl emission control methods for coal boilers. In principle, wet and dry SO2 scrubbers
can be used for the control of HCl and HF on power plant boilers; however, these are not likely to be
necessary because lower cost methods exist. For those facilities with wet or dry scrubbers for SO2
control, these units will likely provide the co-benefit of HCl capture. For those units that are unscrubbed,
these will likely be adequately controlled through retrofit with DSI systems, and a fabric filter.
21 | P a g e
Table 9. HCl Emissions Control Methods
Methods of Control
Dry Sorbent Injection
Dry Scrubber with fabric
filter
Wet Scrubber
Method – Dry sorbent captures HCl, downstream PM control device
captures dry product
Regent – Trona, sodium bicarbonate, hydrated lime
Typical Fuel Types – Most often solid fuels with PM control
Capital Costs – Low to moderate
Co-benefits – NOx and SO2 reduction, Hg reduction, removal of chlorine
precursor leading to lower dioxins/furans formation
Method – Reagent + water react to capture acid gas and dry product
captured in downstream fabric filter
Reagent – Hydrated lime
Typical Fuel Types – Solid fuels
Capital Costs – High
Co-benefits – High Hg capture (esp. bituminous coal), high SO2 capture,
high PM capture
Method – Reagent + water react to capture acid gas
Reagent – Limestone, lime, caustic soda
Typical Fuel Types – Solid fuels
Capital Costs – High
Co-benefits – Highest SO2 capture, high oxidized Hg capture, some PM
capture
Co-benefit Methods of Control
Wet or Dry Scrubbers
Method – SO2 scrubber has high HCl removal efficiency
Coal Change
Low sulfur PRB coal is also low in chlorine content
Dry Sorbent Injection
Data from DSI commercial projects or pilot testing has indicated that acid gases can be very effectively
captured by DSI using Trona, sodium bicarbonate, or hydrated lime. Although DSI is a technology that
has not yet seen the wide deployment of other technologies for acid gas controls, like wet or dry
scrubbers, data suggest that DSI is an effective technology for controlling emissions of acid gases,
including HCl and HF. For example, as shown in Table 10, HCl capture rates of 98 percent have been
measured at Mirant’s Potomac River station with sorbent injection upstream of the air preheater.60
Testing of DSI systems has shown that HCl capture is consistently well above the SO2 capture rate, and
that capture rate of HCl on an ESP was in the mid to upper 90 percent range with SO2 capture in the 60
percent range. With fabric filters, similar HCl capture efficiencies are possible but at lower sorbent
treatment rates.61 Hydrated lime has also been shown in pilot tests to potentially achieve substantial HCl
removal at low capital cost.62
Table 10. HCl and HF Capture at Mirant Potomac River Station
HCl (%)
HF (%)
Trona Injection
98.8
78.4
Sodium Bicarbonate Injection
97.8
88.0
DSI may be sufficiently effective in removing acid gases in combination with the existing PM control
device. In some cases, however, it may be necessary to modify the existing PM control device or to
install a new PM control device. If a fabric filter is installed for PM control, this will also facilitate
capture of acid gases with DSI, and mercury and dioxins/furans with ACI. Such an approach will be far
22 | P a g e
less expensive than installing a wet scrubber. As indicated above, DSI equipment is relatively simple and
inexpensive when compared to a scrubber and can be installed typically within 12 months.
PM Emissions Control
Toxic metals other than mercury are normally in the particle form and are therefore controlled through
particulate matter controls, such as ESPs and fabric filters. The proposed Air Toxics Rule for power
plants sets numerical PM emission limits as a surrogate for non-mercury toxic metal emission limits.
Table 11 lists PM emission control methods for pulverized coal units.
Table 11. PM Emissions Control Methods
Methods of Control
ESP
Baghouse
Method – Electrostatic capture of PM, high capture efficiency
Reagent – None
Typical Fuel Types – Solid fuels
Capital Costs – High
Co-benefits – Capture particle-bound mercury
Method – Filtration of PM, highest capture efficiency
Reagent – None
Typical Fuel Types – Gaseous fuels
Capital Costs – High
Co-benefits – High capture of mercury and other HAPs
Co-benefit Methods of Control
Scrubber (wet or dry)
Method – Captures PM
Electrostatic Precipitator
An electrostatic precipitator (ESP) uses an electrical charge to separate the particles in the flue gas stream
under the influence of an electric field. More than 70 percent of existing coal-fired power plants are
reported to have installed ESPs.63
In brief, an ESP works by imparting a positive or negative charge to particles in the flue gas stream. The
particles are then attracted to an oppositely charged plate or tube and removed from the collection surface
to a hopper by vibrating or rapping the collection surface. An ESP can be installed at one of two
locations. Most ESPs are installed downstream of the air heater, where the temperature of the flue gas is
between 130°C-180°C (270°F-350°F).64 An ESP installed downstream of the air heater is known as a
“cold-side” ESP. An ESP installed upstream of the air heater, where flue gas temperatures are
significantly higher, is known as a “hot-side” ESP.
The effectiveness of an ESP depends in part on the electrical resistivity of the particles in the flue gas.
Coal with a moderate to high amount of sulfur produces particles that are more readily controlled. Low
sulfur coal produces a high resistivity fly ash that is more difficult to control. The effectiveness of an ESP
also varies depending on particle size. An ESP can capture greater than 99 percent of total PM, while
capturing 80 to 95 percent of PM2.5.65
Depending upon the particular ESP and the applicable MACT standards, there may not be any need for
further controls; however, many ESPs are decades old and were built for compliance with less stringent
emission standards in mind. As a result, these facilities may need to make one or both of the following
modifications to comply with new MACT standards:
23 | P a g e
•
Upgrade of existing ESP – The existing ESP could be upgraded through addition of new electric
fields, use of new high frequency transformer rectifier technology, or other changes. The
applicability of this option will depend upon the condition and performance of the existing ESP.
•
Replacement of ESP with fabric filter – A fabric filter may be installed in place of the existing
ESP. In some cases, the existing ESP casing and support structure could be utilized for the
baghouse. A booster fan is likely to be necessary because of the increased pressure drop across
the fabric filter.
In recent years, there has been more focus on fabric filters for PM control than ESPs because of the PM
capture advantages of fabric filters. As a result, there is not a great deal of available information on
recent cost or installation time for ESPs. In general, however, an ESP will likely cost somewhat more and
take more time to construct than a fabric filter built for the same gas flow rate because ESPs are
somewhat more complex to build than a fabric filter system.
Fabric Filter or Baghouse
A fabric filter, more commonly known as a baghouse, traps particles in the flue gas before they exit the
stack. Baghouses are made of woven or felted material in the shape of a cylindrical bag or a flat,
supported envelope. The system includes a dust collection hopper and a cleaning mechanism for periodic
removal of the collected particles.
According to EPA, a fabric filter on a coal-fired power plant can capture up to 99.9 percent of total
particulate emissions and 99.0 to 99.8 percent of PM2.5.66 Thirty-five percent of coal-fired power plants in
the U.S. have installed fabric filters.67
A full baghouse retrofit would generally cost somewhat more than the addition of a downstream polishing
baghouse (discussed later); however, because the material and erection of the baghouse is only a portion
of the total retrofit cost of any baghouse, most of the costs are the same (ductwork, booster fans, dampers,
electrical system modifications, etc.). Increasing the fabric filter size by 50 percent (equivalent to a
change in air to cloth ratio of 6.0 to 4.0) would yield much less than a 50 percent impact to project cost
over the cost of retrofitting a polishing baghouse, perhaps in the range of 15-20 percent. A fabric filter
retrofit (full or polishing) would typically be achievable in 12-24 months from design to completion,
depending upon the complexity of the ductwork necessary. For example, in 2009, the Reid Gardner
generating station in Nevada completed the installation of three new pulse-jet baghouses in 17 months.
The retrofit required the replacement of the plant’s existing mechanical separators.68
Rather than replacing an ESP with a fabric filter, a power plant with an existing ESP has the option of
installing a downstream polishing baghouse (downstream of the existing ESP). This will capture
particulate matter that escapes the ESP. Retrofit of a downstream polishing fabric filter will require
addition of ductwork, a booster fan, and the fabric filter system. Costs will vary by application,
particularly by the amount of ductwork needed. For example, the polishing fabric filter installed on three
90 MW boilers at Presque Isle Power Plant in Michigan cost about $125/KW (2005$). This project,
however, had very long duct runs for each of the boilers and significant redundancy.69 For a project on a
single larger unit without the long duct runs, one would expect a lower cost.
Co-benefits of PM controls – PM controls, especially fabric filters, permit higher co-benefit mercury
capture. Also, capture of other toxic pollutants through DSI is improved with a fabric filter. This is true
24 | P a g e
with any situation where sorbent is used to capture a pollutant because a fabric filter permits capture on
the filter cake in addition to capture in-flight while ESPs permit only in-flight capture.
Control of Dioxins and Furans
Under the Air Toxics Rule, EPA has proposed a “work practice” standard for organic HAPs, including
emissions of dioxins and furans, from coal-fired power plants. Power plant operators would be required
to perform an annual tune-up, rather than meeting a specific emissions limit. EPA has proposed a work
practice standard because it found that most organic HAP emissions from coal power plants are below
current detection levels of EPA test methods. Therefore, it concluded that it is impractical to reliably
measure emissions of organic HAPs. While EPA is not proposing numerical emission limits for organic
HAPs, for completeness, we discuss below experience in controlling emissions of dioxins and furans
from incinerators that may have relevance for co-benefits with coal power plant controls.
Emissions of dioxins and furans result from: (1) their presence in the fuel being combusted; (2) the
thermal breakdown and molecular rearrangement of precursor ring compounds, chlorinated aromatic
hydrocarbons; or (3) from reactions on fly ash involving carbon, oxygen, hydrogen, chorine, and a
transition metal catalyst. Because dioxins and furans are generally not expected to be present in coal, the
second and third mechanisms are of most interest. In both of these mechanisms, formation occurs in the
post-combustion zone at temperatures over 500°C (930°F) for the second mechanism or around 250300°C (480-575°F) for the third mechanism.70 Once formed, dioxins and furans are difficult to destroy
through combustion. Therefore, it is best to prevent their formation, or alternatively, capture them once
formed.
While emissions of dioxins and furans have long been a source of concern for municipal and other waste
incinerators, their emissions have not generally been controlled from power plants. Emissions of dioxins
and furans are generally expected to be lower in coal combustion than in municipal waste combustion
because of the relatively lower chlorine levels and the higher sulfur levels of coal.50 Sulfur has been
shown to impede dioxins and furans formation.50,70,71 Table 12 lists the technologies for control of
dioxins and furans and EPA’s previously proposed institutional, commercial, and industrial boiler limits
for pulverized coal units.
The extensive experience with control of dioxins and furans at incinerators has provided insights that may
be relevant for power plants, while recognizing the important differences between power plants and
incinerators. Because dioxins and furans are formed from organic precursors, one way to avoid their
formation is to have complete combustion of organics; hence, combustion controls or oxidation catalysts
can contribute to their lower formation.70 SCR has also been shown to mitigate emissions of dioxins and
furans.50,51 Data indicate that capture of chlorine prior to the dioxins formation temperature will reduce
dioxins/furans formation from municipal waste combustors.58 Therefore, dry sorbent injection upstream
of the air preheater of a coal boiler may be a means of reducing dioxins/furans formation.
Injection of activated carbon is a means that has been used to capture dioxins and furans emitted by
municipal waste incinerators,50, 70 and has demonstrated over 95 percent capture of dioxins at a hazardous
waste incinerator.72 Currently, there are not enough available data to form a definitive conclusion about
how effective ACI will be at dioxins/furans capture from power plants because of the different conditions.
The information available, however, suggests that it is likely to be useful in reducing dioxins and furans
in the event other methods are not adequate in preventing their formation.
25 | P a g e
Table 12. Dioxins and Furans Emission Control Methods
Methods of Control
Activated Carbon
Injection (ACI)
Method – Activated carbon adsorbs gaseous dioxins/furans, and is
captured in downstream PM control device
Reagent – Powdered Activated Carbon
Typical Fuel Types – Any fuel, but downstream PM control needed
Capital Costs – Low
Co-benefits – Capture of Hg
Co-benefit Methods of Control
Combustion Controls
Method – Destruction of organic dioxins/furans precursors
Dry Sorbent Injection
Method – Captures precursor chlorine prior to dioxins/furans formation
CO or NOx Catalyst
Method – Catalyst increases oxidation of organic dioxins/furans
precursors
Labor Availability
The installation of air pollution control equipment requires the effort of engineers, managers, and skilled
laborers, and past history has shown that the industry has substantial capacity to install the necessary
controls. Between 2008 and 2010, coal-fired power plants added approximately 60 GW of FGD controls
and almost 20 GW of SCR controls with a total of 80 GW of FGD controls installed under CAIR Phase 1.
Between 2001 and 2005, the electric power industry successfully installed more than 96 GW of SCR
systems in response to the NOx SIP Call.
Based on a retrospective study of actual retrofit experience, it was determined that EPA and industry
dramatically underestimated the ability of the air pollution control industry to support the utility industry
in responding to CAIR. The study offered several reasons for why EPA and industry underestimated the
capabilities of the labor market: (1) boilermakers will work overtime during periods of high demand; (2)
boilermakers frequently travel to different locations for work, supplementing local available labor; (3)
boilermakers work in fields other than power, such as refining/petrochemical, shipbuilding, metals
industries and other construction trades, and workers can shift industry sectors with appropriate training;
and (4) new workers will enter the field—for example, in advance of the NOx SIP Call, boilermakers
increased their ranks by 35 percent, mostly by adding new members.73
In November 2010, the Institute of Clean Air Companies (ICAC), an association that represents most of
the suppliers of air pollution control technology, sent a letter to U.S. Senator Thomas Carper confirming
the nation’s air pollution control equipment companies repeatedly have successfully met more stringent
NOx, SO2, and mercury emission limits with timely installations of effective controls and are well
prepared to meet new EPA requirements. In its letter, the industry association stated, “based on a history
of successes, we are now even more resolute that labor availability will in no way constrain the industry’s
ability to fully and timely comply with the proposed interstate Transport Rule and upcoming utility
MACT rules. Contrary to any concerns or rhetoric pointing to labor shortages, we would hope that efforts
that clean the air also put Americans back to work.”74 Also in November 2010, the Building and
Construction Trades Department of the AFL-CIO issued a letter concluding that “[t]here is no evidence to
suggest that the availability of skilled manpower will constrain pollution control technology
development.”75
The electric industry has long been aware that EPA would be regulating HAPs and other pollutants from
coal-fired power plants. As a result, many companies started planning their compliance strategies before
EPA even proposed its Air Toxics Rule in March 2011. For example, companies have been evaluating
26 | P a g e
control technology options and establishing capital budgets.76 Similar advance planning occurred after
the proposed CAIR rule was released in December 2003. In 2004, when EPA was still working to
finalize the rule, companies placed orders for more than 20 GW of FGD controls (wet and dry
scrubbers).77 Southern Company, for example, had begun planning its FGD installations in 2003, well in
advance of the final rule.78
Conclusion
EPA’s clean air rules—the Transport Rule and the Air Toxics Rule—address one of the nation’s largest
sources of toxic air pollution, providing important human health protections to millions of people
throughout the country. Additionally, thousands of construction and engineering jobs will be created as
companies invest in modern control technologies.79
The electric power sector has several decades of experience controlling air pollution emissions from coalfired power plants, which should serve the industry well as it prepares to comply with the Transport Rule
and the Air Toxics Rule. Many companies have already moved ahead with the upgrades necessary to
comply with these future standards, demonstrating that better environmental performance is both
technically and economically feasible.
In most cases, the required pollution control technologies are commercially available and have a long
track record of effective performance at many coal-fired power plants in the U.S., with some operating
successfully for decades. The electric power sector has demonstrated that it is capable of installing
pollution controls on a large portion of the nation’s generating fleet in a relatively short period of time.
Also, suppliers have demonstrated the ability to deliver pollution control equipment in a timely manner,
and the skilled labor needed to install it should be available to meet the challenge as well.
27 | P a g e
Endnotes
1
Clean Air Act, section 110(a)(2)(D), often referred to as the “good neighbor” provision of the Act, requires upwind
states to prohibit certain emissions because of their impact on air quality in downwind states.
2
U.S. Environmental Protection Agency. Federal Implementation Plans to Reduce Interstate Transport of Fine
Particulate Matter and Ozone. Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010.
3
U.S. Environmental Protection Agency. Rule To Reduce Interstate Transport of Fine Particulate Matter and Ozone
(Clean Air Interstate Rule); Revisions to Acid Rain Program; Revisions to the NOx SIP Call; Final Rule.
Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005.
4
North Carolina v. EPA, 531 F.3d 896 (D.C. Cir. 2008).
5
North Carolina v. EPA, 550 F.3d 1176 (D.C. Cir. 2008).
6
U.S. Environmental Protection Agency. Federal Implementation Plans to Reduce Interstate Transport of Fine
Particulate Matter and Ozone. Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010.
7
U.S. Environmental Protection Agency. Federal Implementation Plans to Reduce Interstate Transport of Fine
Particulate Matter and Ozone, Page 45213. Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010.
8
U.S. Environmental Protection Agency. Federal Implementation Plans to Reduce Interstate Transport of Fine
Particulate Matter and Ozone, Page 45344. Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010.
9
U.S. Environmental Protection Agency. Fact Sheet: Proposed Transport Rule Would Reduce Interstate Transport
of Ozone and Fine Particle Pollution. July 6, 2010, http://www.epa.gov/airtransport/pdfs/FactsheetTR7-610.pdf (accessed March 17, 2011).
10
New Jersey v. EPA, 517 F.3d 574 (D.C. Cir. 2008).
11
U.S. Environmental Protection Agency. Reducing Air Toxics from Power Plants: Regulatory Actions. March 16,
2011, http://www.epa.gov/airquality/powerplanttoxics/actions.html (accessed March 16, 2011).
12
U.S. Environmental Protection Agency. Fact Sheet: Power Plant Mercury and Air Toxics Standards; Overview of
Proposed Rule and Impacts. March 16, 2011,
http://www.epa.gov/airquality/powerplanttoxics/pdfs/overviewfactsheet.pdf (accessed March 17, 2011).
13
National Association of Clean Air Agencies (NACAA). “State/Local Mercury/Toxics Program for Utilities.”
April 6, 2010 (updated February 8, 2011), http://www.4cleanair.org/index.asp.
14
U.S. Environmental Protection Agency. Fact Sheet: Proposed Mercury and Air Toxics Standards. March 16, 2011,
http://www.epa.gov/airquality/powerplanttoxics/pdfs/proposalfactsheet.pdf.
15
U.S. Environmental Protection Agency. Fact Sheet: Proposed Mercury and Air Toxics Standards. March 16,
2011, http://www.epa.gov/airquality/powerplanttoxics/pdfs/proposalfactsheet.pdf.
16
U.S. Environmental Protection Agency. National Emissions Inventory (NEI) Air Pollutant Emissions Trends Data
(1970 - 2008 Average annual emissions, all criteria pollutants in MS Excel). June 2009,
http://www.epa.gov/ttnchie1/trends/ (accessed March 29, 2011).
17
U.S. Environmental Protection Agency. Clean Air Markets: Emission and Compliance Data (Table 1). December
20, 2010, http://www.epa.gov/airmarkt/progress/ARP09_1.html (accessed March 29, 2011).
18
Institute of Clean Air Companies. Letter to Senator Thomas Carper, U.S. Senate. November 3, 2010,
http://www.icac.com/files/public/ICAC_Carper_Response_110310.pdf (accessed March 17, 2011).
19
This is developed from US EPA NEEDS 4.10 database.
20
Srivastava, R. “Controlling SO2 Emissions: A Review of Technologies.” U.S. Environmental Protection Agency.
EPA-600/R-00-093. October 2000.
21
Black & Veatch. “News Release: Air Quality Upgrades Coming to Lawrence Energy Center.” October 1, 2009,
http://www.bv.com/wcm/press_release/10012009_3797.aspx (accessed March 17, 2011).
28 | P a g e
22
U.S. Department of Energy, Energy Information Administration, Form 767 data.
23
Wall, Darryl, Healy, Edward, Huggins, John. Implementation Strategies for Southern Company FGD Projects.
(Undated).
24
U.S. Environmental Protection Agency. Documentation for EPA Base Case v.4.10: Chapter 5.
http://www.epa.gov/airmarkt/progsregs/epa-ipm/BaseCasev410.html (accessed March 24, 2011).
25
Sharp, G.W. “Update: What’s that Scrubber Going to Cost?” POWER Magazine. March 1, 2009,
http://www.powermag.com/issues/features/Update-Whats-That-Scrubber-Going-to-Cost_1743.html
(accessed March 17, 2011).
26
U.S. Environmental Protection Agency. Documentation for EPA Base Case v.4.10: Chapter 5.
http://www.epa.gov/airmarkt/progsregs/epa-ipm/BaseCasev410.html (accessed March 24, 2011).
27
Roll, D., Connell, D., and Huber, W. “Results from the First Year of Operation of a Circulating Fluidized Bed Dry
Scrubber with High-Sulfur Coal at AES Greenidge Unit 4.” Electric Power Conference & Exhibition.
Baltimore, MD. May 8, 2008.
28
Institute of Clean Air Companies (ICAC). Letter to Senator Thomas Carper, U.S. Senate. November 3, 2010,
http://www.icac.com/files/public/ICAC_Carper_Response_110310.pdf (accessed March 17, 2011).
29
Staudt, J. “Commercializing Technologies: The Buyer’s Perspective, Experience from the Clean Air Act.” 2009
Carbon Finance Forum. New York. September 15-16, 2009.
30
Frazer, C., Jayaprakash, A., Katzberger, S.M., Lee, Y.J., and Tielsch, B.R. “Fayette Power Project Unit 3 FGD
Upgrade: Design and Performance for More Cost-Effective SO2 Reduction.” Power Plant Air Pollutant
Control MEGA Symposium. Baltimore, MD. August 31 – September 2, 2010.
31
Erickson, C., Jasinski, M., and VanGansbeke, L. “Wet Flue Gas Desulfurization (WFGD) Upgrade at the Trimble
County Generation Station Unit 1.” EPRI-DOE-EPA-AWMA Combined Power Plant Air Pollutant Control
MEGA Symposium. Baltimore, MD. August 28-31, 2006.
32
Indiana Utility Regulatory Commission. Cause No. 43188. Filed Testimony of Barbara A. Smith - On Behalf of
the Indiana Office of Utility Consumer Counselor. Filed April 5, 2007.
33
Indiana Utility Regulatory Commission. Cause No. 43188. Proposed Order, Submitted by: Northern Indiana
Public Service Co. – Electric. Filed July 6, 2007.
34
Institute of Clean Air Companies (ICAC). Letter to Senator Thomas Carper, U.S. Senate. November 3, 2010,
http://www.icac.com/files/public/ICAC_Carper_Response_110310.pdf (accessed March 17, 2011).
35
Atwell, M. and Wood, M. “Sodium Sorbents for Dry Injection Control of SO2 and SO3.” 2009,
http://www.solvair.us/static/wma/pdf/1/6/2/9/5/SOLVAirAPC.pdf (accessed March 17, 2011).
36
This is developed from the U.S. EPA NEEDS 4.10 database.
37
LePree, J. “SCR: New and Improved.” Chemical Engineering. July 1, 2010,
http://www.che.com/environmental_health_and_safety/environmental_mgmt/air_pollution_control/SCRNew-and-Improved_5803.html (accessed March 17, 2011).
38
Cichanowicz, J.E. and Muzio, L.J. “Twenty-Five Years of SCR Evolution: Implications for US Application and
Operation.” Proceedings of the EPRI/EPA/DOE MEGA Symposium. Chicago, IL. August 2001,
http://www.ferco.com/Files/P117.pdf (accessed March 17, 2011).
39
Institute of Clean Air Companies (ICAC). Letter to Senator Thomas Carper, U.S. Senate. November 3, 2010,
http://www.icac.com/files/public/ICAC_Carper_Response_110310.pdf (accessed March 17, 2011).
40
Marano, M. and Sharp, G. “Estimating SCR Installation Costs.” POWER Magazine. February 15, 2006,
http://www.powermag.com/issues/cover_stories/Estimating-SCR-installation-costs_506.html (accessed
March 17, 2011).
41
U.S. Environmental Protection Agency. “Engineering and Economic Factors Affecting the Installation of Control
Technologies for Multipollutant Strategies.” EPA-600/R-02/073. October 2002.
29 | P a g e
42
U.S. Department of Energy Office of Fossil Energy National Energy Technology Laboratory. “Greenidge MultiPollutant Control Project: A DOE Assessment.” DOE/NETL-2011/1454. September 2010.
43
U.S. Department of Energy Office of Fossil Energy National Energy Technology Laboratory. “Greenidge MultiPollutant Control Project: A DOE Assessment.” DOE/NETL-2011/1454. September 2010.
44
Connell, D., Roll, D., Abrams, R., Beittel, R. and Huber, W. “The Greenidge Multi-Pollutant Control Project:
Demonstration Results and Deployment of Innovative Technology for Reducing Emissions from Smaller
Coal-Fired Power Plants.” 25th Annual International Pittsburgh Coal Conference. Pittsburgh, PA. October
2, 2008.
45
McDonald, D.K., Downs, W., and Kudlac, G.A. “Mercury Control for Coal-Fired Utilities - Amendment for
Mercury Speciation Testing.” The Babcock & Wilcox Company. Barberton, OH. March 15, 2001.
46
Laudal, D.L., Thompson, J.S., Pavlish, J.H., Brickett, L., Chu, P., Srivastava, R.K., Lee, C.W., and Kilgroe, J.D.
“Evaluation of Mercury Speciation at Power Plants Using SCR and SCR NOx Control Technologies.” 3rd
International Air Quality Conference. Arlington, VA. September 9-12, 2001.
47
Chu, P., Laudal, D., Brickett, L., and Lee, C.W. “Power Plant Evaluation of the Effect of SCR Technology on
Mercury.” EPRI-DOE-EPA Combined Air Pollution Control MEGA Symposium. Washington, DC. May
19-22, 2003.
48
Machalek, T., Ramavajjala, M., Richardson, M., Richardson, C., Dene, C., Goeckner, B., Anderson, H., and
Morris, E. “Pilot Evaluation of Flue Gas Mercury Reactions across an SCR Unit.” EPRI-DOE-EPA
Combined Air Pollution Control MEGA Symposium. Washington, DC. May 19-22, 2003.
49
Pritchard, S. “Predictable SCR Co-Benefits for Mercury Control.” POWER-GEN Worldwide. January 1, 2009,
http://www.powergenworldwide.com/index/display/articledisplay/349977/articles/powerengineering/volume-113/issue-1/features/predictable-scr-co-benefits-for-mercury-control.html (accessed
March 17, 2011).
50
Hartenstein, H.U. “Dioxin and Furan Reduction Technologies for Combustion and Industrial Thermal Process
Facilities.” The Handbook of Environmental Chemistry. Vol. 3, Part O, Persistent Organic Pollutants (ed.
H. Fiedler). Springer-Verlag Berlin Heidelberg. 2003.
51
Buekens, A. “Dioxin Formation and Emission Control.” Haldor-Topsoe Meeting Catalysis in New Environmental
Processes. Copenhagen. August 27-28, 2009.
52
Durham, M.D., Bustard, C.J., Schlager, R., Martin, C., Johnson, S., and Renninger, S. “Controlling Mercury
Emissions from Coal-Fired Utility Boilers: A Field Test.” EM, Air & Waste Management Association. July
2001, pp. 27-33.
53
National Association of Clean Air Agencies (NACAA). “State/Local Mercury/Toxics Program for Utilities.”
April 6, 2010 (updated February 8, 2011), http://www.4cleanair.org/index.asp.
54
Institute of Clean Air Companies (ICAC). “Updated Commercial Hg Control Technology Bookings.” June 2010,
http://www.icac.com/files/members/Commercial_Hg_Bookings_060410.pdf (accessed February 1, 2011).
55
Northeast States for Coordinated Air Use Management (NESCAUM). “Technologies for Control and
Measurement of Mercury Emissions from Coal-Fired Power Plants in the United States: A 2010 Status
Report.” NESCAUM, Boston, MA. July 2010, http://www.nescaum.org/document/hg-control-andmeasurement-techs-at-us-pps_201007.pdf/.
56
U.S. Environmental Protection Agency. “Preliminary ICR Database.” Version 3 posted November 12, 2010,
http://www.epa.gov/ttn/atw/utility/utilitypg.html.
30 | P a g e
57
U.S. Environmental Protection Agency, Air Pollution Prevention and Control Division, National Risk
Management Research Laboratory, Office of Research and Development. “Control of Mercury Emissions
from Coal Fired Electric Utility Boilers: An Update.” Research Triangle Park, NC. February 18, 2005,
http://www.epa.gov/ttn/atw/utility/ord_whtpaper_hgcontroltech_oar-2002-0056-6141.pdf (accessed March
17, 2011).
58
Tyree, C. and Allen, J. “Determining AQCS Mercury Removal Co-Benefits.” POWER Magazine. July 1, 2010,
http://www.powermag.com/issues/cover_stories/Determining-AQCS-Mercury-Removal-Co-Benefits_2825.html
(accessed March 17, 2011).
59
U.S. Environmental Protection Agency, Air Pollution Prevention and Control Division, National Risk
Management Research Laboratory, Office of Research and Development. “Control of Mercury Emissions
from Coal Fired Electric Utility Boilers: An Update,” Research Triangle Park, NC. February 18, 2005,
http://www.epa.gov/ttn/atw/utility/ord_whtpaper_hgcontroltech_oar-2002-0056-6141.pdf (accessed March
17, 2011).
60
Kong, Y., de la Hoz, J.M., Atwell, M., Wood, M., and Lindsay, T. “Dry Sorbent Injection of Sodium Bicarbonate
for SO2 Mitigation.” Power-Gen International 2008. Orlando, FL. December 2-4, 2008.
61
Davidson, H. “Dry Sorbent Injection for Multi-pollutant Control Case Study.” CIBO IECT VIII. Portland, ME.
August 2 –5, 2010.
62
Dickerman, J. and Gambin, A. “Low Capital Cost Acid Gas Emission Control Approach.” Power Plant Air
Pollution Control MEGA Symposium, Baltimore, MD. August 31-September 2, 2008.
63
Environmental Health and Engineering, Inc. “Emissions of Hazardous Air Pollutants from Coal-fired Power
Plants.” Needham, MA. March 7, 2011, http://www.lungusa.org/assets/documents/healthy-air/coal-firedplant-hazards.pdf (accessed March 17, 2011).
64
STAPPA-ALAPCO. “Controlling Fine Particulate Matter under the Clean Air Act: A Menu of Options.” March
2006, http://www.4cleanair.org/PM25Menu-Final.pdf (accessed March 17, 2011).
65
STAPPA-ALAPCO. “Controlling Fine Particulate Matter under the Clean Air Act: A Menu of Options.” March
2006, http://www.4cleanair.org/PM25Menu-Final.pdf (accessed March 17, 2011).
66
STAPPA-ALAPCO. “Controlling Fine Particulate Matter under the Clean Air Act: A Menu of Options.” March
2006, http://www.4cleanair.org/PM25Menu-Final.pdf (accessed March 17, 2011).
67
Environmental Health and Engineering. “Emissions of Hazardous Air Pollutants from Coal-fired Power Plants.”
March 7, 2011, http://www.lungusa.org/assets/documents/healthy-air/coal-fired-plant-hazards.pdf
(accessed March 17, 2011).
68
AMEC. “Environmental Baghouse Installation Completed One Year Ahead of Schedule.”
http://www.amec.com/explore_amec/projects/power/environmental_baghouse_installation_completed_one
_year_ahead_of_schedule.htm.
69
Wisconsin Electric Power Company. “TOXECON™ Retrofit for Mercury and Multi-Pollutant Control on Three
90-MW Coal-Fired Boilers - Preliminary Public Design Report.” DOE Cooperative Agreement No.: DEFC26-04NT41766. May 15, 2006, http://www.netl.doe.gov/technologies/coalpower/cctc/pubs/RP-05-0148R2%20Preliminary%20Public%20Design%20Report.pdf (accessed March 17, 2011).
70
Gullett, B. and Seeker, R. “Chlorinated Dioxin and Furan Formation, Control, and Monitoring.” ICCR Meeting.
Research Triangle Park, NC. September 17, 1997.
71
Raghunathan, K. and Gullett, B. “The Role of Sulfur in Reducing PCDD and PCDF Formation.” Environmental
Science and Technology. 1996, 30, pp. 1827-1834.
72
Roeck, D. and Sigg, A. “Carbon Injection Proves Effective in Removing Dioxins.” January 1996,
http://www.calgoncarbon.com/documents/CarbonInjection-Removesdioxins.pdf (accessed March 17,
2011).
31 | P a g e
73
Staudt, J. “Availability of Resources for Clean Air Projects.” Andover Technology Partners, North Andover, MA.
October 2010.
74
Institute of Clean Air Companies (ICAC). Letter to Senator Thomas Carper, U.S. Senate. November 3, 2010,
http://www.icac.com/files/public/ICAC_Carper_Response_110310.pdf (accessed March 17, 2011).
75
Building and Construction Trades Department, American Federation of Labor–Congress of Industrial
Organizations (AFL-CIO). Letter to Senator Thomas Carper, U.S. Senate. November 5, 2010,
http://www.supportcleanair.com/resources/letters/file/11-11-10-AFL-Letter-To-Sen-Carper.pdf (accessed
March 19, 2011).
76
See, for example: (1) NRG. Fourth Quarter and Full-Year 2010 Results Presentation. February 22, 2011; and (2)
Southern Company Mercury Research Center established in December 2005:
http://mercuryresearchcenter.com.
77
Staudt, J. “Availability of Resources for Clean Air Projects.” Andover Technology Partners, North Andover, MA.
October 2010.
78
Institute of Clean Air Companies (ICAC). Letter to Senator Thomas Carper, U.S. Senate. November 3, 2010,
http://www.icac.com/files/public/ICAC_Carper_Response_110310.pdf (accessed March 17, 2011).
79
Ceres. New Jobs-Cleaner Air: Employment Effects Under Planned Changes to the EPA’s Air Pollution Rules.
February 2011.
32 | P a g e
Appendix E OTC RACT PRINCIPALS STATEMENT APPENDIX F SUMMER STUDY ‐ 2014 Through stakeholder negotiations, MDE requested a voluntary NOx Optimization Study for coal‐fired EGUs during the summer of 2014. MDE requested Raven Power and NRG Energy to review, evaluate and optimize NOx control measures at their coal‐fired electric generating units (EGUs) and to report their findings to the Department. MDE requested that an optimization plan be developed which would describe steps to evaluate means by which NOx reduction can be optimized during the agreed‐upon time period of July 1 through at least August 31, 2014. The optimization plan is intended to evaluate optimizations in NOx emissions both by reducing NOx generation in the furnace and improving NOx reduction in the post‐combustion control device, and to evaluate these optimizations on both a 30‐day and a 24‐hour basis. MDE requested an interim monthly data report and a final report on the results and findings of the study. For the effort to minimize emissions on peak days, the Department shall identify and provide Raven Power and NRG with notification of high forecasted ozone days (High Ozone Days) no later than 10 am Eastern Standard Time the prior day. High Ozone Days shall be limited to 10 days during the study period. GenOn Mid‐Atlantic NOx Optimization Plan – Summer 2014 Raven Power NOx Optimization Plan – Summer 2014 Excel files with data available on the Departments website GenOn Mid-Atlantic NOx Optimization Plan – Summer 2014
GenOn Mid-Atlantic, LLC (“GenOn”) has worked with its three Maryland plants to establish target NOx
rates on the coal units for this summer. Each unit has a “summer-long” target rate that the units will
follow as well as a “peak day” target rate that the plants will endeavor to meet on those days when MDE
calls for additional reductions. GenOn will operate installed NOx controls at the three plants when the
units are in operation, except for periods of startup, shutdown, malfunction, or maintenance of the
control equipment. The plants will log the events that cause the NOx controls to be taken out of service
and also note when the controls are returned to service.
The bullets below describe the measures that each unit will take to control / reduce NOx and document
operational limitations this summer.
Morgantown
Summer SCR NOx Target Rate: 0.040 lb/MBtu
Peak Day SCR NOx Target Rate: 0.034 lb/MBtu (a 15% reduction from summer avg)
Units are already optimized for NOx, with SCRs achieving excellent NOx rates.
Plant is on a catalyst management program to maintain SCR performance and low ammonia slip.
Plant will keep e-logs for periods of equipment malfunction, maintenance, startups, and
shutdowns.
Peak Day rate will not be achievable if a unit is in startup or shutdown, as SCR permissive
temperature is 621 oF, which is not reached until ~325 MW (even with economizer bypass).
Dickerson
Summer SNCR NOx Target Rate: 0.30 lb/MBtu. This rate is highly dependent on what load the
units are operated at over the summer period. Long periods of operation at maximum or
minimum load raise the average rate achieved, while operation at mid loads lowers the rate
achieved.
Peak Day SNCR NOx Target Rate: __TBD__ lb/MBtu. SNCR tuning tests and other optimization
efforts have not been completed, therefore a Peak Day rate cannot been selected yet.
As of June 1, SNCR systems have been in operation whenever the units run, except during
malfunction, maintenance, startup, and shutdown periods. This will continue through August
31.
The SNCR manufacturer, FuelTech, has been on site since mid-May for boiler combustion
optimization testing, followed by SNCR NOx optimization testing on all three units. These tests
will be completed the week of July 7th.
Use of the SNCR system reduces main steam temperatures by 40-50 oF, which reduces unit load.
One of the goals of the optimization testing is to minimize generation derates while the SNCR is
in operation.
Ammonia slip from the SNCR system needs to be carefully controlled. High ammonia slip during
testing on Unit 1 in February plugged the air preheater in 3-4 days. Slip is being measured
manually during optimization testing. There is one slip monitor in place on Unit 1 currently, and
a monitor for Unit 2 will be installed in July.
The units have SOFA systems that reduce NOx from ~0.60 to 0.35 lb/MBtu. Reduction is limited
by CO emissions, windbox pressure, steam temperatures, and boiler air flow (FD fan limits). The
DCS drives NOx down until one of these limits is encountered.
Units have higher NOx rate at max and min loads. Lowest NOx is achieved at ~120 MW.
Due to a common ductwork arrangement, Unit 3 has the best boiler performance (closest to ID
fans) while Unit 1 has the worst performance (farthest from fans).
Units get ramped up and down frequently during the day, which disrupts the DCS optimization
process.
Plant will log periods of equipment malfunction and maintenance.
Peak Day measures the plant may try on Dickerson units:
o Sliding boiler pressure for improved low load NOx
o GAM, a waterwall slagging treatment to improve steam temperatures.
Chalk Point
Unit 1:
Summer SCR NOx Target Rate: 0.060 lb/MBtu, (NOx ppm set point of 33 ppm).
Peak Day SCR NOx Target Rate: 0.050 lb/MBtu, (NOx ppm set point of 27 ppm, a 18% reduction
from summer avg).
Unit 1 is optimized for NOx. Chalk also has a catalyst management system to maintain SCR
performance and low ammonia slip.
Unit 2:
Summer SACR NOx Target Rate: maximum reduction with 1.0 ppm ammonia slip. The NOx rate
at this condition varies with load and inlet NOx concentration.
Peak Day SACR NOx Target Rate: maximum reduction with 1.5 ppm ammonia slip. The NOx rate
at this condition varies with load and inlet NOx concentration.
SACR system has an artificial intelligence tuning system which runs continuously. There are 18
ammonia injection lances and 6 ammonia slip monitors across the Unit 2 boiler gas path. The
program groups the ammonia injection into 3 zones, then seeks minimum NOx emissions at a
given ammonia slip set point. Ammonia slip is the limiting factor. If ammonia slip increases to
~5 ppm, the APH will plug up (with ammonium bisulfate) within 4-5 days and force the unit off.
280 MW is the low NOx “sweet spot” for this unit.
Plant will keep e-logs for periods of equipment malfunction and maintenance.
NOX OPTIMIZATION PLAN
Summer 2014
Raven Power :
• Brandon Shores
• H.A. Wagner
• C.P. Crane
June 27, 2014
Introduction
Raven Power Finance LLC (“Raven”) is planning to voluntarily conduct a NOx Optimization Study during
the summer of 2014. The Maryland Department of Environmental Quality (“MDE”) requested this
voluntary study in an email attachment from Tad Aburn on June 24, 2014, which requests that Raven
evaluate and optimize NOx control measures at the six coal-fired electric generating units (EGUs) in
Raven’s fleet during a specified period of time (“Study”). Those units include Brandon Shores 1 and 2, C.
P. Crane 1 and 2 and H.A. Wagner 2 and 3.
MDE requested that an optimization plan (“Plan”) be developed by Raven, which would describe
Raven’s steps to evaluate means by which NOx reduction can be optimized during the agreed-upon time
period of July 1 through at least August 31, 2014. As described in the MDE’s request, the Plan is
intended to evaluate optimizations in NOx emissions both by reducing NOx generation in the furnace
and improving NOx reduction in the post-combustion control device, and to evaluate these
optimizations on both a 30-day and a 24-hour basis, as set forth herein.
Affected Unit Information
The following is a summary of the key information and data about each unit in the Raven coal fleet
subject to the Study requirements:
Brandon 1
690 – 700
Brandon 2
690 – 700
Wagner 2
146
Wagner 3
325
Crane 1
200
Crane 2
180
260
260
35
144
100
70
Bituminous
coal, various
Bituminous
coal, various
Sub-bit
coal
LNB; OFA
LNB; BOOS
OFA
OFA
Opposed Wallfired (5 sets of
burners)
Cyclones
Cyclones
NOx Control
Device
SCR after hotside ESP
Opposed
Wall-fired (5
sets of
burners + 1
opposed Sidewall set)
SCR after hotside ESP
Bituminous
coal,
various
LNB with
OFA;
Opposed
Wall-fired;
Sub-bit
coal
Boiler NOx
control
Boiler config.
Bituminou
s coal,
various
LNB
SCR
SNCR
w/multiple
injection
levels
Urea
(diluted)
SNCR
w/multiple
injection
levels
Urea
(diluted)
Max Econ.
Load (MW gross)
Min. Load
(MW-gross)
Fuel
Reagent for
NOx Control
Urea to
ammonia
conversion
(1°); aqueous
ammonia (2°)
BOOS – Burners out of service
Urea to
ammonia
conversion
(1°); aqueous
ammonia (2°)
Front
Wall-fired
SNCR;
fixed
injection
points
Urea
(diluted)
1
Urea to
ammonia
conversion
General Provisions of Study
Raven will endeavor to operate all NOx control equipment in accordance with manufacturer’s
recommended operating parameters during the Study period of July 1 through at least August 31,
except during startup, shutdown, maintenance and malfunction periods. During boiler start-up and
shutdown periods, there are times when certain operational conditions, like low temperatures, make
operating the controls (i.e., adding ammonia to the flue gas or passing flue gas through catalyst)
ineffective and potentially detrimental to the other equipment. Additionally, like all operating
equipment, the NOx controls may experience a malfunction that either causes it to stop operating
properly or curtail its effectiveness, or require maintenance to prevent more significant problems later.
However, during the Study Raven will endeavor to 1) maintain NOx controls as effective as reasonably
possible during startups and shutdowns, 2) take steps to bring NOx controls back into full service as
quickly as practicable whenever the control equipment experiences a malfunction, and 3) document
(and include in the final report) information regarding the cause of the malfunction and the steps for
bringing the controls back.
For each unit Raven will endeavor to collect hourly NOx emission rate (lb/MMBtu and lb/hr) and gross
generation (MW) data using existing monitoring devices. Raven will use this information to generate
NOx vs load curves for each unit.
During the Study Tom Weissinger, Raven Power Environmental Director, will be Raven’s point of contact.
He will coordinate any visits/observations made by MDE and he will be responsible for submitting the
monthly and final reports to MDE.
Optimization Plan
Each plant has recently or will be conducting activities to ready the boilers and the NOx controls for the
Study and for minimizing NOx during the Study period. After these preparatory and preventive
maintenance activities are complete, each unit will plan to run for approximately a week when
dispatched to establish a baseline level of NOx (and NOx-Load curve). Then, each plant will plan to test
a number of potential changes or adjustments they believe may help optimize NOx emissions. These
tests, will evaluate one change at a time to determine their individual effects on NOx. The tests will plan
to focus on lowering NOx generation in the boilers and improve the NOx control efficiency of the
SCR/SNCRs. Due to the limited time of the Study (i.e., not beginning until after July 1), and variations in
dispatch (i.e., swings in load up and down) during the summer, the evaluations may be limited in time or
scope. If Raven feels it is warranted, additional tests and data collection may be conducted beyond
August 31, especially, if a unit was not operating an adequate amount of time during the targeted Study
period.
Based on the results of these tests, Raven plans to test the effects of the most promising changes when
they are combined (i.e., implementing multiple changes simultaneously). This should be occurring late
in July or early August, depending on how much the units have been dispatched and tested.
For the last part of the test period, Raven plans to operate the units with the “best performing” changes
made, monitoring both emissions and operational conditions to determine the sustainability of the
changes. If certain changes are found to reduce NOx, but cause operational/dispatch problems after a
few days/weeks, then they may only be continued on the High Ozone Days being flagged by MDE.
2
Otherwise, Raven plans to continue them through the Study period. Raven will endeavor to implement
as much/many NOx controls as feasible on High Ozone Days to minimize the mass emission of NOx on
those days. However, 1) Raven will not adjust dispatch based on the test, and 2) the changes
implemented may be modified during the course of the Study period, based on documented results and
changes in operation.
A list of the pre-Study activities planned for each unit are included with the Plant-specific test activities
attached to this Plan.
Monitoring and Monthly Reporting
Raven will endeavor to collect, at a minimum, the following information during the Study period:
•
•
•
•
•
•
Data submitted to EPA via Emissions Collection and Monitoring Plan System (ECMPS), including
NOx emissions data (lb/MMBtu and tons/day), gross generation (MW), and heat input
(MMBtu/hr);
Ammonia and urea injection rates (lbs/hr) for each of the NOx control devices;
Some indication of ammonia slip, whether it is from an ammonia detection monitor or from a
qualitative assessment (e.g., ammonia in the ash or scrubber wastewater);
NOx emissions prior to the SCRs, if CEMS are in place;
Differential pressure across the SCR catalysts, where existing monitors are functional; and
Flue gas temperature at the SCR inlet.
Raven will endeavor to summarize this data (hourly averages where available) within approximately 15
calendar days of the end of each month in the Study period and send it to MDE. Raven will endeavor to
identify which days were identified as High Ozone Days.
By October 31, 2014 Raven will endeavor to submit a final report discussing the results of the NOx
reduction Study. The report is anticipated to include the summarized data from above with NOx
expressed in both units of rate (lb/MMBtu) and mass (tons). It should also include the following:
•
•
•
•
summarized results of the evaluations each plant performed for NOx improvements during the
Study period;
a list of High Ozone Days as identified by MDE, and the NOx emissions from each plant for each
day;
NOx vs Generation curves for the Study period; and
Explanations of operational challenges encountered, (e.g., during periods of startup, shutdown,
malfunction, or other abnormally high NOx emission occurrences) and how they were resolved,
if able.
3
Plant NOx Optimization/Testing Plans
4
BRANDON SHORES
Pre-Study Preparation
Pulverizers
•
Inspections, Preventive Maintenance (PM) and Scheduled Rebuilds of pulverizers
Boiler
•
•
•
Inspections, Repairs, and PMs on burners
Inspections of duct work and boiler casing and repairs of leaks to maintain flue gas temperature
Inspections, repair and testing of OFA components
SCRs
•
•
•
•
Vacuum catalyst surface
Inspections, Repairs and PMs of NH3 injection grids and associated piping and valves
Balance injection rates across grid, as needed
Inspections, Repairs and PMs of urea-to-ammonia system and NH3 dilution and blower equipment
Optimization Test Plan
Action/Test
Long-term
vs.
Ozone Day
Variables to Change
Parameters to Monitor
Data collection at
Loads and Duration
Potential Issues
IN FURNACE
Tune burners for high load
(baseline), balanced, per
design
Long-term
Burner settings;
excess air
SCR Inlet NOx; Process
CO; furnace slagging; LOI
in ash
5
Low, mid & high
3 – 5 days
Detrimental slagging;
increased CO and LOI
in ash
Test adjustments in OFA
quantity or BOOS airflow,
if applicable
Longterm/Ozone
Day
OFA flow (% of total
air); burner settings;
excess air
Max Load reached; SCR
Inlet NOx; Process CO;
furnace slagging; LOI in
ash
Low, mid & High
Load
1 – 3 days
Load limitation;
increased CO and LOI
in ash
Unit 2-Test max load
achieved using BOOS and
1 mill out.
Longterm/Ozone
Day
Mill selection; burner
setting; air flow to
BOOS; excess air;
coal flow;
Max Load reached; SCR
Inlet NOx; Process CO;
furnace slagging; LOI in
ash
High Load;
Load limitation; CO,
LOI in ash
Unit 2 – Test 26 Mill as
BOOS instead of 23 Mill
Long-term
Mill selection; burner
setting; air flow to
BOOS; excess air;
SCR Inlet NOx; Process
CO; furnace slagging; LOI
in ash
Low, mid & High
Load
1 – 3 days
3 days
CO, detrimental
slagging; increased
CO and LOI in ash
SCRs
Test Urea feed vs. Aq.
NH3 feed
Longterm/Ozone
Day
NH3 feed source
Stack NOx
2 days
Minimizing time for
switch over between
feeds;
Maximize NH3 feed to SCR
Longterm/Ozone
Day
NA
All potential restrictions
in NH3 supply (e.g., trim
valves, urea reactor
capacity); Stack NOx;
NH3 in scrubber (slip)
3 days
Increase NH3 supply,
but without adding
NH3 slip
Increase urea feed rate
Ozone Day
Urea flow
NH3 slip; ammonium
bisulfate formation (APH
∆P
1 day
APH pluggage
6
H.A. Wagner
Pre-Study Preparation
Pulverizers
•
Inspections, Preventive Maintenance (PM) and Scheduled Rebuilds of pulverizers
Boilers
•
•
•
Inspections, Repairs, and PMs on burners
Inspections of duct work and boiler casing and repairs of leaks to maintain flue gas temperature (Unit 3)
Inspections, repair and testing of OFA components (Unit 3)
SNCR (Unit 2)
•
•
Inspections, Repairs and PMs of urea storage and delivery equipment
Inspections, Repairs and PMs of urea injection ports/nozzles
SCR (Unit 3)
•
•
Vacuum catalyst surface
Inspections, Repairs and PMs of urea-to-ammonia system and NH3 dilution and blower equipment
Optimization Test Plan
Action/Test
Long-term
vs.
Ozone Day
Variables to Change
Parameters to Monitor
IN FURNACE
7
Data collection at
Loads and Duration
Potential Issues
Tune Unit 2 and Unit 3
burners for NOx
optimization
Test alternative burner
impeller (adjusted angle
to optimize NOx over
combustion) on Unit 2
Test co-firing natural gas
on Unit 2
NOx Controls
Test higher urea
injection/load level
(higher slip) on Unit 2
Test earlier introduction
of NH3 during startup of
Unit 3
Test lower outlet NOx
setpoint; higher NH3
injection/load level
(higher slip) on Unit 3
Long-term
(baseline)
Excess air; OFA
registers (U3); burner
registers
NOx conc.; Process CO
conc.; furnace slagging;
LOI in ash
High load
1 – 7 days
Long-term
(baseline)
Burner impeller
angle; excess air
NOx conc.; Process CO
conc.; furnace slagging;
LOI in ash
High load
1 – 7 days
Ozone Day
Natural gas and coal
flows
NOx conc.; CO conc.
All load range;
2 - 10 days
Detrimental slagging;
increased CO and LOI
in ash
Supply (pressure) of
natural gas when Unit
1 is on gas.
NOx conc.; NH3 slip
conc. and/or Fly ash
ammonia odor;
All load range;
1 – 7 days
NH3 slip; ash quality
Longterm/Ozone
Day
Long-term
Ozone Day
Detrimental slagging;
increased CO and LOI
in ash
Ammonia Slip
target/Urea injection.
Keep bypass damper
closed
(longer/sooner)
during
shutdowns/startups;
NH3 injection earlier
during startup
NOx conc.; NH3 slip
conc. and/or Fly ash
ammonia odor
During Startups
NH3 slip; furnace
pressure issues
during startup.
NOx Outlet set point
NOx conc.; NH3 slip
conc. and/or Fly ash
ammonia odor
All load range;
4 - 7 days
NH3 slip; ash quality
8
C.P. Crane
Pre-Study Preparation
Boilers
•
•
Inspections, Repairs, and PMs on cyclones, including primary and secondary air dampers
Inspections, repair and testing of OFA components
SNCRs
•
•
•
Inspections, Repairs and PMs of urea storage and delivery equipment
Inspections, Repairs and PMs of urea injection ports/probes
PM ammonia slip meters
Optimization Test Plan
Action/Test
Long-term
vs.
Ozone Day
Variables to Change
Parameters to Monitor
Data collection at
Loads and Duration
Potential Issues
IN FURNACE
Tune cyclone for high
load, balanced, per design
NA (baseline)
Burner settings;
excess air
NOx Conc.; CO conc.;
furnace slagging; LOI in
ash
Low, mid & high
Test Stoichiometry from
0.95 down to 0.88 with
constant urea/load
control on 100% PRB
Longterm/Ozone
Day
Stoichiometry
NOx conc.; CO conc.; Hg
conc.; slagging; Max load
achieved
All load range;
2 – 3 weeks
Test Stoich. Effects on
Unit 2 with a blend of
Ozone Day
Stoichiometry
NOx conc.; CO conc.; Hg
conc.; slagging; Max load
achieved
Load > 200 MWg;
2 – 5 days
9
3 – 5 days
Detrimental slagging;
increased CO and LOI
in ash
High CO at low Stoich;
high Hg at high
Stoich; Load
limitation on Low
Stoich.
NAPP/PRB achieving max
load (same as above test)
SNCRs
Test higher urea
injection/load level
(higher slip)
Test higher urea
concentration at injector
(less diluted)
Longterm/Ozone
Day
Longterm/Ozone
Day
Optimize injection levels
Longterm/Ozone
Day
Ammonia Slip
NOx conc.; NH3 slip
target/Urea injection. conc.; Fly ash quality;
All load range;
1 – 7 days
NH3 slip; ash quality;
baghouse ∆P
Urea conc. At
NOx conc.; NH3 slip
injector; urea
conc.; Fly ash quality;
injection flow rate;
injector level
selection (500, 600 or
800 level).
Urea flow to each
NOx cond. NH3 slip conc.
injection level
All load range;
1 – 7 days
Injector nozzle
plugging/spray
patterns
All load ranges;
1 – 7 days
Nozzle pluggage;
baghouse ∆P
10
Appendix G NOx Emission Reduction Calculations
MDE staff
Phase 1 calcualtions based on historic 2011‐2013 capacity
MDE
Projected Reductions
2011 OS Heat Input 2011 OS Nox 2012 OS Heat 2013 OS Heat Baseline HI OS Avg MMBtu
Tons
Input MMBtu
2012 OS Nox Tons Input MMBtu
2013 OS Nox Tons mmbtu (11‐13 avg)
EGU
Brandon 1
1.46E+07
613.82
1.62E+07
726.77
1.20E+07
485.85
1.43E+07
Brandon 2
1.58E+07
762.21
1.43E+07
892.17
1.19E+07
628.43
1.40E+07
Wagner 2
2.77E+06
516.03
2.19E+06
475.12
1.20E+06
251.35
2.05E+06
Wagner 3
6.47E+06
204.24
4.91E+06
154.72
5.88E+06
174.26
5.75E+06
Crane 1
3.27E+06
688.92
2.79E+06
573.73
1.63E+06
344.27
2.56E+06
Crane 2
3.90E+06
810.97
3.27E+06
668.94
2.44E+06
658.65
3.20E+06
Chalk Point 1
6.34E+06
529.19
5.73E+06
517.96
5.12E+06
404.51
5.73E+06
Chalk Point 2
8.65E+06
988.38
3.58E+06
408.58
5.80E+06
630.94
6.01E+06
Dickerson 1
2.19E+06
273.15
2.03E+06
263.04
1.27E+06
173.65
1.83E+06
Dickerson 2
2.51E+06
312.28
1.76E+06
227.62
1.32E+06
181.59
1.86E+06
Dickerson 3
2.79E+06
344.77
2.12E+06
269.55
1.37E+06
189.18
2.09E+06
Morgantown 1
1.27E+07
244.74
9.46E+06
152.23
9.40E+06
112.29
1.05E+07
Morgantown 2
1.51E+07
233.31
1.30E+07
194.70
8.43E+06
148.52
1.22E+07
All Facility Totals
9.71E+07
6522.01
8.13E+07
5525.11
6.77E+07
4383.49
8.20E+07
All Facilites Avg. Tons/Day
Note all data from CAMD OS Season total data
Projected REG Projected REG Baseline Baseline OS Tons @ Indicator OS Tons @ Nox tons ( Nox Rate Indictor Rate & Indictor Rate
11‐13 avg) lb/mmbtu Rates
Optimization
608.81
0.09
0.08
570.09
570.09
0.07
489.88
489.88
760.94
0.11
0.34
349.06
349.06
414.17
0.40
0.07
201.31
177.74
177.74
0.06
0.30
384.60
384.60
535.64
0.42
0.28
448.39
448.39
712.85
0.45
483.89
0.17
0.07
200.52
200.52
675.97
0.22
0.33
992.02
675.97
236.61
0.26
0.24
182.83
182.83
240.50
0.26
0.24
186.31
186.31
267.83
0.26
0.24
209.31
209.31
169.76
0.03
0.07
368.03
169.76
192.18
0.03
0.07
425.68
192.18
5476.87
0.13
5008.00
4236.60
35.80
32.73
27.69 Tons/Day
468.86
1240.27
Tons Total
3.06
8.11
Tons/Day Reduction
8.56%
22.65%
Appendix H COMPLIANCE PLAN
26.11.38
Description of what needs to go into the Plan referred to in 26.11.38.03A(1):
The Plan shall summarize the data that will be collected to demonstrate compliance with
COMAR 26.11.38.03A(2), which states that beginning on May 1, 2015, for each operating day
during the ozone season, the owner or operator of an affected electric generating unit shall
minimize NOx emissions by operating and optimizing the use of all installed pollution control
technology and combustion controls consistent with the technological limitations,
manufacturers’ specifications, good engineering and maintenance practices, and good air
pollution control practices for minimizing emissions (as defined in 40 C.F.R. § 60.11(d)) for such
equipment and the unit at all times the unit is in operation while burning any coal.
The Plan shall be fully enforceable by the Department and cover all modes of operation,
including but not limited to normal operation, start –up, shutdown, and low capacity operation.
The Plan shall describe how each affected unit will minimize NOx emissions during each mode
of operation.
For start-up and shutdown operation, the plan shall be fully enforceable by the Department
and include for each affected unit, at the minimum, a definition of the completion of startup
and commencement of shutdown based on MW, general start-up and shutdown procedures for
the boiler, the temperature at which NOx controls become effective, the MW at which the
temperature required for NOx controls to become effective occurs, the duration of time that
the affected unit will operate in each of those modes, ramping rates, all measures taken to
minimize NOx emissions during each of those modes, and any information deemed necessary
by the Department upon review of the submitted plan.
For low capacity operation, the plan shall be fully enforceable by the Department and include
for each affected unit, at the minimum, measures taken to minimize emissions during this
mode of operation, and any information deemed necessary by the Department upon review of
the submitted plan.
For normal operation, the plan shall be fully enforceable by the Department and include for
each affected unit, at the minimum, how the use of all installed pollution control technology
and combustion controls will be optimized, general startup and shutdown procedure for the
NOx control technology, the control strategy for the NOx control technology including percent
control setpoints and a description of any cascade control, expected range of NOx control
technology reagent injection rates, and any information deemed necessary by the Department
upon review of the submitted plan.
All requirements and indicators included in an approved plan shall be fully enforceable by the
Department under the terms of the regulation.
Appendix I Collaborative Solution to the Ozone Transport Problem Tad Aburn, Air Director, MDE
Maryland’s Proposal for a Collaborative
Solution to the Ozone Transport Problem
September 2014 Update
Technical and Policy Framework for Resolving the Issue Through
Complementary “Good Neighbor” and “Attainment” SIPs
Tad Aburn, Air Director, MDE
Air Directors Technical Collaborative – September 4, 2014
Martin O’Malley, Governor | Anthony G. Brown, Lt. Governor | Robert M. Summers, Ph.D., Secretary
Topics
• Background
• Why is Maryland Pushing so Hard
for “Good
Good Neighbor
Neighbor” Partnerships?
• Technical Analyses to Date
• Maryland’s Modeling and Analysis of
Emissions Data
• Maryland’s efforts to further reduce
emissions from local mobile
sources and other emission sectors
• Our Ask of Upwind States
• Timing and Future Efforts
• Discussion
Page 2
1
Background – Ozone Transport
• Many, many balls in the air
• Supreme Court has acted
• Not real clear on what happens next
• “Expand the OTR” Petition under Section
176A of the Clean Air Act (CAA)
• Challenges to EPA over large
nonattainment areas (CAA Section 107)
• Challenges to EPA over “Good Neighbor”
SIPs (CAA Section 110A2D)
• EPA’s
EPA’ Transport
T
t Rule
R l Process
P
• A collaborative effort between upwind and
downwind states to address the ozone
transport issue
• Remainder of this presentation will focus
on the collaborative effort
Page 3
Background – The Collaborative
• On August 6, 2013- Approximately 30 Air Directors participated in a call to
begin a technical collaboration on ozone transport in the East
• There was discussion … and general agreement … on beginning technical
analyses of a scenario (called “Phase 1”) that would try and capture the progress
that
h could
ld be
b achieved
hi d if:
if
• The EPA Tier 3 and Low Sulfur Fuel program is effectively implemented
• The potential changes in the EGU sector from shutdowns and fuel switching driven
by MATS, low cost natural gas and other factors were included
• The potential changes in the ICI Boiler sector driven by Boiler MACT and low cost
natural gas were also included
• There was also general agreement that, at some point, Commissioner level discussions
may take place
• In early April 2014, preliminary discussions between Commissioners began
• Discussions continue … potential meeting in October
Page 4
2
Why Is MD Pushing So Hard
• Only state East of the Mississippi designated as a
“Moderate” nonattainment area by EPA
• Baltimore is the only nonattainment area in the
East required to submit an “Attainment”
Attainment SIP by
June of 2015
• This SIP must be supported by an “Attainment
Demonstration”
• The Attainment Demonstration must be based upon
photochemical modeling and other technical analyses
• It must show that monitors in the Baltimore area are
expected to comply with the ozone standard by 2018
• We have enough modeling and technical analysis
completed to understand what Maryland needs in
it’s plan to bring the State into attainment
Page 5
• This analysis also shows that most other areas in the
East should also attain
The Key Elements of Maryland’s Plan
• Number 1 Need – The Tier 3 Mobile
Source and Fuel Standards
• The most important new program to reduce
high ozone in Maryland
• Number 2 – Additional local reductions in
Maryland and close-by neighboring states
to reduce mobile source emissions
• New mobile source efforts in the Ozone
Transport Region and new Maryland control
programs are on the books or in the works
• Number 3 - Good Neighbor SIPs or
Commitments to address transport
Page 6
• Analysis shows that if power plants in upwind
states simply run the controls that have already
been purchased … during the core ozone
season … and planned retirements occur …
that transport for the current ozone standard
will be addressed
3
Addressing Mobile Sources and …
… “along the I-95 corridor” controls
• Maryland’s modeling looks at more than
just upwind power plants
• New
N ffederal
d l control
t l programs for
f mobile
bil
sources, like the Tier 3 vehicle and fuel
standards, are critical
• Maryland’s plan … and the modeling …
includes new controls just in the OTR like:
• California car programs
• Aftermarket catalyst initiatives
• RACT requirements
• Consumer products and paints
• Diesel Inspection and Maintenance
• Non-traditional control efforts
Page 7
• Many more
Modeling the Maryland Plan
• Maryland has conducted preliminary
modeling of the Plan and believes that the
Plan will allow MD to come very close to
meeting the 75 ppb ozone standard
• Will most likely also allow most other areas
in the East to attain the standard by 2018
• MD’s modeling has been conducted
primarily with the OTC platform that uses
2007 as the base year and 2018 as the
attainment year
• MD is updating the modeling to use the newer
platform based upon EPA modeling efforts
• This platform uses 2011 as the base year and
2018 as the attainment year
• Based upon early comparisons, it appears
that modeling with the new platform will
generate consistent results and may, in many
areas, show even greater ozone benefits
Page 8
4
The Bottom Line
Maryland’s plan is currently being modeled as
“Attainment Run #3” or “Scenario A3”
Before Scenario A3
After Scenario A3
2007
Base
2018 Scenario A3
Page 9
Bottom Line by Monitor
… Before and After Scenario A3
County
Harford,, MD
Prince Georges, MD
Fairfield, CT
New Castle, DE
Bucks, PA
Suffolk, NY
Camden, NJ
Fairfax, VA
Franklin, OH
F lt County,
Fulton
C
t GA
Wayne, MI
Sheboygan, WI
Mecklenberg Co, NC
Knoxville, TN
Jefferson County, KY
Lake County, IN
Cook County, IL
Design Value
2007
90.7
85.3
88.7
81.3
90.7
88.0
87.5
85.3
84.7
90 3
90.3
81.3
83.3
87.0
80.7
80.0
77.5
77.0
After Scenario A3
2018
74.7
65.1
70.8
66.3
76.8
71.0
74.2
66.9
69.7
73 7
73.7
74.5
70.8
67.6
70.7
67.0
77.4
75.0
10
Page 10
5
Building the Clean Air Plan
The 2007 Base
Add the regional controls
across the East (Scenario 3a)
Add the “OTR” controls along I
95 corridor (Scenario A2)
Add the new controls just
in MD (Scenario A3)
Page 11
Updated CMAQ Chemistry?
• For years, Maryland and the University of
Maryland have been analyzing model
performance aloft, where most transport takes
place … Not always great
• Also
Al analyzing
l i measuredd data
d t to
t look
l k att
mobile source inventories
• In 2011, the Discover AQ field study in the
Mid-Atlantic provided new unique data aloft
• U of M has analyzed aloft chemistry and
found some problems with nitrogen chemistry
• Fails to carry NOx reduction benefits
downwind
• Working on new aloft chemistry concepts …
Also looking at inconsistencies in mobile
source inventories
• Will show small, but important additional
benefits from regional scale NOx strategies
• Maybe an extra 1 or 2 ppb benefit in Maryland
Page 12
6
A Little More Detail
• Scenario A3 includes control measures to
address local emissions and transport. It
includes the following:
• Implementation
p e e tat o of
o the
t e federal
ede a Tier
e 3 vehicle
ve c e and
a d
fuel standards across the East
• Implementation of all “on-the-books” federal
control programs across the East
• Implementation of new and old “Inside the Ozone
Transport Region” control measures like the new
OTC Aftermarket Catalyst initiative and
continued implementation of California car
standards
t d d
• Implementation of new local measures in certain
states like Maryland, Connecticut and New York
• Good Neighbor SIPs or commitments from 10
upwind states to insure that power plants run
previously purchased controls during the core
summer ozone season
Page 13
Running Power Plant Controls Effectively
• Maryland and several other states have
analyzed power plant (Electric Generating
Unit or EGU) emissions data from
Continuous Emissions Monitors (C
C
(CEMS)
S)
to see how well existing pollution controls
are being run
• Changes in the energy market, a
regulatory system that is driven by ozone
season tonnage caps and inexpensive NOx
allowances have created an unexpected
situation where many EGU operators can
meet ozone season tonnage caps without
operating their control technologies
efficiently
• Sometimes not at all
Page 14
7
How the EGU Data Analysis Was Built
• Maryland began the data analyses in late 2012
• Looked at EGUs in the 9 upwind states named in the 176A Petition
(IL, IN, KY, NC, MI, OH, TN, VA, WV) … MD and PA
• Shared a draft with Air Directors on April 21, 2013
• The April 2012 package focused on a bad ozone episode (8 days) in
2011
• Received comments from numerous states
• Shared a second draft with Air Directors on May 13, 2013
• This package added a second bad ozone episode in 2012 (10 days) and
updated earlier materials – additional comments received
• The 2011 and 2012 episodes analyzed capture two of the worst
ozone periods in 2011 and 2012
• Other states, like Wisconsin and Delaware have done similar analyses
and reached similar conclusions
• Third updated, data packages to Air Directors soon
• Using West Virginia EGUs as an example
• West Virginia has an interesting story
Page 15
Summary of Generation in WV - 2012
• Total number of units = 60
• Total heat input capacity =
173,267MMBTU/hr = 17,586 MW
• Total State MW Capacity in %
• Total number of Coal units = 35 = 88%
• Total number of NG units = 20 = 9%
• Total number of other (oil, etc.) units = 5 = 3%
• Total number of Nuclear units = 0 = 0%
• Total Capacity Coal = 15,489 MW
• 15 units with SCR = 11,755 MW = 76%
• 4 units with SNCR = 496 MW = 3%
• 16 units without SCR/SNCR = 3,237 MW = 21%
Page 16
8
Summary of Generation in WV - 2018
• Total number of units = 39
• Total heat input capacity = 143,851
MMBTU/hr = 14,493 MW
• Total State MW Capacity in %
• Total number of Coal units = 19 = 90%
• Total number of NG units = 20 = 10%
• Total number of other (oil, etc.) units = = 0%
• Total number of Nuclear units = 0 = 0%
• Total Capacity Coal = 12,946 MW
• 15 units with SCR = 11,648 MW = 90%
• 2 units with SNCR = 191 MW = 1.5%
• 2 units without SCR/SNCR = 1,107 MW = 8.5%
Page 17
The MD Analyses Focus on Coal
NOx Emissions by Primary Fuel Type - Ozone Season - Eastern U.S.
700000
Unknown
600000
Coal
NOx Tons
500000
400000
Diesel Oil/Other
Oil/Residual Oil
300000
Natural Gas/Other
Gas/Pipeline Natural Gas
200000
Other Solid Fuel, Wood
100000
0
Page 18
9
Controls on Coal WV Units - 2012
… by size … smallest to largest
14,000
Heat Input Capacity (MMBtu/hr)
12 000
12,000
10,000
8,000
6,000
4 000
4,000
2,000
0
Smallest ------------------------------------------------------------------------------------------------------------------ Largest
SCR
SNCR
Without SCR/SNCR
Page 19
Running Controls
Average Ozone Season Emission
Rates at Specific Units by Year
0.5000
West Virginia Coal Fired EGUs, SCR
0.4500
Example: Specific units (names not shown) consistently running controls NOx Emission Rate, lbs/MMBtu
0.4000
0.3500
0.3000
0.2500
These 4 units have consistently run
at low rates around or below 0.1
lb/MMBtu since 2004
0.2000
0.1500
0.1000
0.0500
0.0000
2002
2004
2006
2008
2010
2012
2014
Page 20
10
Not Running Controls as Well
Average Ozone Season Emission
Rates at Specific Units by Year
0.5000
West Virginia Coal Fired EGUs, SCR
0 4500
0.4500
NOx Emission Rate, lbs/MMBtu
0.4000
Example: Specific units (names not shown) not running controls in later years.
0.3500
0.3000
0.2500
0.2000
0.1500
0.1000
These 3 units have been running
at higher rates since 2009
0.0500
0.0000
2002
2004
2006
2008
2010
2012
2014
Page 21
Actual Emissions – July 1 to 10, 2012
90
West Virginia, Coal EGUs, July 1-10, 2012
80
Emissions from units not
running their SCR controls as
well as they have in the past
70
NOx Emissions, tons
60
50
40
30
20
10
0
7/1/2012
SCR operating
7/2/2012
7/3/2012
SCR not operating
7/4/2012
SNCR
7/5/2012
7/6/2012
7/7/2012
without SCR/SNCR, under 3000 MMBtu
7/8/2012
7/9/2012
7/10/2012
without SCR/SNCR, over 3000 MMBtu
Page 22
11
Reductions That Could Have Been Achieved
200
180
West Virginia Coal EGUs, SCR, July 1 - 10, 2012
160
NOx Emissions, tons
Actual
Emissions
140
Average daily reductions that could have
been achieved … about 50 tons per day
120
100
Emissions if controls run consistent
with best rates from earlier years
80
60
40
20
0
7/1/12
7/2/12
7/3/12
7/4/12
NOx, Actual (tons)
7/5/12
7/6/12
7/7/12
7/8/12
7/9/12
7/10/12
NOx at lowest OS avg. emission rate (tons)
Page 23
11 State Emissions
PA has several
issues … SCRs
S
Same
iin NC underperforming
SNCR Units
… units without
Appear to be
SCR or SNCR
Larger Emitters
have large
emissions
In VA SNCR
Units Appear
g
to be Larger
Emitters
TN SCR Units
always run well
Page 24
12
Reductions That Could Have Been Achieved
…11 State Total
Average daily reductions that could have
been achieved … about 490 tons per day
Page 25
How Might This Affect Ozone?
• Maryland has performed several very
preliminary model runs to look at how
much running EGU controls
g increase ozone levels
inefficientlyy might
• Three runs:
• Scenario 2B – A worst case run
• Assumes SCR and SNCR controls are not
run at all
• Scenario 3B – A worst data run
• Assumes SCR and SCR units all run at worst
rates seen in
i CAMD ddata - 2005 to 2012
• Scenario 3C – Based upon CAMD data
analysis for EGU performance in 2011 and
2012
• Assumes that units that had higher ozone
season emission rates were operating at the
best ozone season rates observed since 2005
Page 26
13
These are Preliminary Runs …
… as the modeling improves some of the details will
change, but the overall conclusions will not
• These are sensitivity runs
• They are not perfect, but they are clearly
meaningful and policy relevant
• From our 2007 platform
• One month screening runs
• Input data continues to be enhanced
Page 27
Lost Ozone Benefits – Worst Case
… no SCR or SNCR controls run at all
• Difference plot between … 2018 with and without controls
Domain Wide Concentrations
Preliminary
Page 28
14
Lost Ozone Benefits – Worst Case
… no SCR or SNCR controls run at all
• Difference plot … DVs … 2018 with and without controls
Difference in Design Values
Preliminary
Page 29
Lost Ozone Benefits – Worst Data
… SCR or SNCR controls run at highest
rates in CAMD data
• Difference plot … DVs … 2018 with and without controls
Difference in Design Values
Preliminary
Page 30
15
Lost Ozone Benefits – 2011/2012
… based upon 2011 and 2012 CAMD
EGU performance data
• Difference plot … DVs … 2018 with and without controls
Difference in Design Values
Preliminary
Page 31
Lost Ozone Benefit in PPB
Most Difficult
Monitors
County
Harford, MD
Prince Georges, MD
Fairfield, CT
New Castle, DE
Bucks, PA
Suffolk, NY
Camden, NJ
Fairfax, VA
Franklin, OH
Fulton County, GA
Wayne, MI
Sheboygan, WI
Mecklenberg Co, NC
Knoxville, TN
Jefferson County, KY
Lake County, IN
Cook County, IL
Increased Ozone in 2018 – 3 EGU Control Scenarios
Worst Case – No
SCRs or SNCRs
(Scenario 2B)
Using worst rate
CAMD Data
(Scenario 3B)
Using actual
2011/2012 Data
(Scenario 3C)
4.3
4.6
2
3.8
3.1
2
2.7
4.4
5.8
2.3
1.6
1.5
4.1
4
6.7
1.1
0.8
1.2
1
0.3
0.8
0.6
0.4
0.5
1
1.7
0.3
0.5
0.1
1.8
0.7
2
0.2
0.2
0.5
0.5
0.1
0.4
0.4
0.2
0.3
0.5
1
0.2
0.2
0.1
1.2
0.5
1.5
0.1
0.1
Preliminary
32
Page 32
16
Lost Ozone Benefit – Clean Monitors
… EPA will propose a new ozone standard soon … 60 to 70 ppb range …
designations to most likely be based upon 2014 to 2016 or 2015 to 2017 data
Projected to be
Clean in 2018 …
P t ti ll att Risk
Potentially
Ri k
County
Blair, PA
Armstrong, PA
Washington, OH
Warren, OH
Kanawa, WV
Monogolia WV
Monogolia,
Oldham, KY
Boone, KY
Campbell, KY
Greene, IN
Vanderburgh, IN
Person, NC
Garrett, MD
Page 33
Increased Ozone in 2018 – 3 EGU Control
Scenarios
Preliminary
2018 – Controls Worst Case – No Using worst rate Using actual
Running Well SCRs or SNCRs CAMD Data 2011/2012 Data
(Scenario 3A) (Scenario 2B) (Scenario 3B) (Scenario 3C)
58.7
66.4
60.1
68.8
64.5
61 4
61.4
67.2
57.5
61.6
61.8
62.3
60.2
58.7
Greater than 70 ppb
76.5
79.8
80.5
79.8
80.2
77 1
77.1
77.1
77.2
71.3
84.4
74.0
78.1
75.9
65 to 70 ppb
64
70.7
68.9
72.1
67.8
64 4
64.4
70.2
64.7
64.3
67.3
65.8
71.7
62.6
60 to 65 ppb
62.7
68.8
66.2
70.9
66.3
63 1
63.1
69.1
61.6
63.3
65.2
64.7
63.6
61.1
33
Next Steps With this Modeling
• Run for full ozone season
• Run some regional sensitivity tests
• Run with enhanced chemistry and
mobile source adjustments from
research
• This will show slightly greater loss of
benefit from not always running
controls effectively
• Run with 2011/2018 Platform
ASAP
• Work with the Midwest Ozone
Group (MOG) on this issue
• Modeling and potential solution
• Continue to refine as part of the
Maryland Attainment SIP
Page 34
17
So where do we go
g
from here?
Page 35
Maryland’s Push
… can we work together to submit complementary SIPs?
• The current modeling tells us we are very
close to meeting the 75 ppb ozone standard
• New modeling
g between now and the first
half of 2015 will support, supplement and
strengthen this conclusion
• EPA’s process will not resolve this issue
before 2015
• In 2015 … areas like Baltimore owe
Attainment SIPs and modeling
• All states owe “Good Neighbor” SIPs
• They were actually due in 2011
• Maryland is pushing …very hard … on
“A package of complementary
Attainment and Good Neighbor SIPs” to
be finalized in late 2014 or early 2015
• We have been pushing this since early 2013
Page 36
18
How Do We Move Forward?
• Clearly continue the technical collaboration
• Continue Commissioner level discussions when
needed
• Begin
i more serious
i
discussion
di
i on making
ki sure EGU
G
controls are run effectively when needed to reduce
high ozone levels
• Maryland’s push …
• Upwind and downwind states submit a package of
complementary SIPs in 2015
• Attainment SIPs from states like Maryland
• Good Neighbor SIPs from others
• Supported by collaborative modeling
• Could “trump” an EPA Transport Rule, alter the
110A2D challenges and the 176A Petition and
influence any “CSAPR 2” initiative
Page 37
Running EGU Controls Effectively
• Maryland has heard from many Air Directors that
they are interested in looking at this issue
• MOG has expressed an interest in working with
us on this issue
• Discussion between several Air Directors has
already started
• We can build from those ongoing discussions
• Key Issues
• How to define ”run the controls”?
• What time frame? – the ozone season? – the core
ozone season?
• How to implement?
• Good Neighbor SIPs
• Voluntary agreements with sources
• Permits
• Section 126 Petitions
Page 38
• Other mechanisms
19
Timing
• Maryland Straw Proposal
• 2014 to Spring 2015
• Technical collaboration and stakeholder
di
discussions
i
continue
ti
• Summer 2014 to Spring 2015
• Commissioner level discussions
• End of 2014
• Technical work to support “Complementary
Package
g of SIPs” approaches
pp
near “SIP
Quality” status
• Spring 2015 - States submit SIPs
• This timing works for MD’s SIP, but may
also be critical if the “State Solution” is to
influence an EPA transport rule, the 176A
Petition or son or daughter of CSAPR
Page 39
Thanks
Page 40
20
Was this manual useful for you? yes no
Thank you for your participation!

* Your assessment is very important for improving the work of artificial intelligence, which forms the content of this project

Download PDF

advertisement