Appendix N - MANE-VU Basis for Reasonable Controls

Class I States’ Demonstration that the Goals are Based on Reasonable Controls

40 CFR Section (d)(1)(i)(A) of EPA’s Clean Air Visibility Rule requires that in

establishing reasonable progress goals for each Class I area, the State must consider

the costs of compliance, the time necessary for compliance, the energy and non-air

quality environmental impacts of compliance, and the remaining useful life of any

potentially affected sources, and the SIP must include a demonstration showing how

these factors were taken into consideration in setting the goal. These factors are

sometimes termed the “four statutory factors,” since their consideration is required by

the Clean Air Act.

Focus on SO2 

MANE-VU conducted a Contribution Assessment and developed a conceptual model

that indicated that the dominant contributor to visibility impairment at all sites during all

seasons in the base year was particulate sulfate formed from emissions of SO2. (See

the NESCAUM report entitled Contributions to Regional Haze in the Northeast and

Mid-Atlantic United States, Appendix A). The report concludes that sulfates alone

account for from one-half to two-thirds of total fine particle mass on the 20 percent

haziest days at MANE-VU Class I sites. In view of the dominant role of sulfate in

visibility impairment in Northeast and Mid-Atlantic class I areas, the report states that,

“[T]hese findings suggest that an effective emissions management approach would rely

heavily on broad-based regional SO2 control efforts in the eastern United States.” 

While other pollutants, including organic carbon, will need to be addressed in order to

achieve the national visibility goals, MANE-VU’s Contribution Assessment suggested

that an early emphasis on SO2 will yield the greatest near-term benefit. Therefore, it is

reasonable that the additional measures considered in setting the reasonable progress

goals described in this document required reductions of SO2 emissions.

Contributing Sources

The MANE-VU Contributions Assessment indicates that emissions from within MANEVU in 2002 were responsible for about 25 to 30 percent of the sulfate at MANE-VU

Class I areas. Sources in the Midwest and Southeast regions were responsible for

about 15 to 25 percent each. Point sources dominated the inventory of SO2 emissions. 

Therefore, the MANE-VU strategies discussed in Section 9.4 and 9.5, above, include

additional measures to control sources of SO2 both within the MANE-VU region and in

other states that were determined to contribute to regional haze at MANE-VU Class I

areas. 

MANE-VU’s Contribution Assessment documented the source categories most

responsible for visibility degradation at MANE-VU Class I areas. As documented in the

Long Term Strategy section of this SIP, there was a collaborative effort between the
Ozone Transport Commission and MANE-VU to evaluate a large number of potential

control measures, and several measures that would reduce SO2 emissions were

identified for further study. This led MANE-VU to prepare the report entitled,

“Assessment of Reasonable Progress for Regional Haze in MANE-VU Class I Areas”

(MACTEC, July 9, 2007), which documented an analysis of the four statutory factors for

five major source categories. This report is referred to below as the MANE-VU

Reasonable Progress Report. Table 9.6 summarizes the results of MANE-VU’s

Reasonable Progress Report, which are further discussed below as they pertain to the

strategies adopted by MANE-VU.

MANE-VU states reviewed the four-factor analysis presented in the Reasonable

Progress Report, consulted with each other about the measures, and concluded by

adopting the statements referenced above in this SIP on June 20, 2007. These

statements indicate which control measures would be further pursued for adoption.

MANE-VU Class I states shared these statements with states outside the region that

they determined reasonably caused or contributed to visibility impairment in the MANEVU Class I areas prior to consulting with those states. 

The following discussion focuses on the control measures included in modeling used to

set the reasonable progress goals: BART, emissions reductions from specific EGUs,

low sulfur fuel oil requirements, and additional measures determined to be reasonable.
Summary of Results from the Four Factor Analysis

Source

Category

Primary

Regional Haze

Pollutant

Potential

Control Measure(s)

Average Cost (in

2006 dollars) per

Ton of Pollutant

Reduction

Compliance

Timeframe

Energy and N

Quality Enviro

Impacts

Electric

Generating Units SO2

Switch to a low sulfur

coal (generally <1%

sulfur), switch to

natural gas (virtually

0% sulfur), coal

cleaning, Flue Gas

Desulfurization (FGD)-

Wet, Flue Gas

Desulfurization (FGD)-

Spray Dry, Flue Gas

Desulfurization (FGD) -

Dry.

MANE-VU

application of IPM®*

v.2.1.9 predicts

$775 to $1,690. 

MACTEC reports

$170 to $5,700

based on available

literature depending

on control method

and size of source

2-3 years following

SIP submittal

Fuel supply is

potential perm

issues, reduc

electricity prod

capacity, wast

issues

Industrial,

Commercial,

Institutional

Boilers

SO2

Switch to a low sulfur

coal (generally <1%

sulfur), switch to

natural gas (virtually

0% sulfur), switch to a

lower sulfur oil, coal

cleaning, combustion

control, Flue Gas

Desulfurization (FGD)-

Wet, Flue Gas

Desulfurization (FGD)-

Spray Dry, Flue Gas

Desulfurization (FGD) -

Dry.

MACTEC reports

$130 to $11,000

based on available

literature. 

Depends on size of

plant and control

method.

2-3 years following

SIP submittal

Fuel supply is

potential perm

issues, control 

energy require

wastewater i
Source

Category

Primary

Regional Haze

Pollutant

Potential

Control Measure(s)

Average Cost (in

2006 dollars) per

Ton of Pollutant

Reduction

Compliance

Timeframe

Energy and N

Quality Enviro

Impacts

Cement and

Lime Kilns SO2

Fuel switching, Dry

Flue Gas

Desulfurization-Spray

Dryer Absorption

(FGD), Wet Flue Gas

Desulfurization (FGD),

Advanced Flue Gas

Desulfurization (FGD).

MACTEC reports

$1,900 to $73,000

based on available

literature. Depends

on size of plant and

control method.

2-3 years following

SIP submittal

Control device 

requireme

wastewater i

Heating Oil SO2

Lower the sulfur

content in the fuel.

Depends on the state.

MACTEC reports

$550 to $750 based

on available

literature. There is

a high uncertainty

associated with this

cost estimate.

Currently feasible. 

Capacity issues

may influence

timeframe for

implementation of

new fuel standards

Increases 

furnace/boiler e

Decreased furna

maintenan

requireme

Residential

Wood

Combustion

PM

State implementation

of NSPS, ban on

resale of uncertified

devices, installer

training certification or

inspection program,

pellet stoves, EPA

Phase II certified RWC

devices, retrofit

requirement,

accelerated

changeover

requirement,

accelerated

changeover

inducement.

MACTEC reports $0

to $10,000 based on

available literature

Several years -

dependent on

mechanism for

emission reduction 

Reduce greenho

emissions, inc

efficiency of com

device

* Integrated Planning Model® CAIR versus CAIR plus analysis conducted for MARAMA/MANE-VU by ICF.
1 The information in this and the next paragraph comes from the “Assessment of Control Technology

Options for BART-Eligible Sources: Steam Electric Boilers, Industrial Boilers, Cement Plants and Paper

and Pulp Facilities,” March 2005, prepared by NESCAUM, in partnership with MANE-VU.

I. Best Available Retrofit Technology is Reasonable

BART controls are part of the strategy for improving visibility at MANE-VU

Class I areas. MANE-VU prepared reports to provide states with

information about available controls and the cost and other factors

associated with those controls. The reasonable progress goals set in this

SIP assume that states whose emissions affect MANE-VU Class I areas

will make reasonable determinations concerning BART controls for

sources in their states.

II. Emissions Reductions from Specific EGUs are Reasonable

MANE-VU identified specific EGU stacks that were significant contributors

to visibility degradation at MANE-VU Class I areas in 2002 based on

CALPUFF modeling analyses documented in the Contribution

Assessment. MANE-VU obtained information about existing and planned

controls on emissions from those stacks. This analysis and the

information on controls are documented in the MANE-VU Reasonable

Progress Report, the Contribution Assessment, and the Emissions

Inventory and Long Term Strategy section of this SIP. 

Based on information gathered from the states and RPOs, MANE-VU

anticipates that emissions from many of the specific EGU stacks will be

controlled as a result of EPA’s Clean Air Interstate Rule (CAIR). Since

CAIR is a cap and trade program, it is not possible to predict with certainty

which of the 167 stacks will in fact be controlled under CAIR in 2018.

The following discussion addresses each of the four factors with respect to

the strategy of controlling specific EGUs. Information is taken primarily

from the MANE-VU Reasonable Progress Report and MANE-VU BART

reports.

Costs of Compliance 

Technologies to control the precursors of regional haze are commercially

available.1 Since EGUs are the most significant stationary source of SO2,

NOx, and PM, they have been subject to extensive federal and state

regulations to control all three pollutants. The technical feasibility of control

technologies has been successfully proven for a large number of small

(say, 100MW) to very large boilers (over 1,000 MW) using different types

of coal used. Over the last few years, a large amount of cost data have

also become available that clearly indicated that many technologies
2 Although the IPM model runs anticipated the implementation of EPA’s Clean Air Mercury Rule (CAMR), that

rule has since been vacated by the courts. However, it is anticipated the adjustments to the predicted SO2 emissions

from electric generating units (EGUs) used in the air quality modeling, based on state-specific comments on the

amount of SO2 controls that will actually be installed due to state specific regulations and the EPA’s CAIR rule, will

have more of an impact on the air quality modeling analysis conducted for this SIP than the vacature of the CAMR

rule. MANE-VU believes the adjustments based on state-specific comments improved the reliability of the

inventory and made the modeling results more dependable.

provide substantial and extremely cost effective reductions. 

Both wet and dry scrubbers are in wide commercial use in the U.S. for

controlling SO2 emissions. The capital costs for new or retrofit wet or dry

scrubbers are higher than the capital costs for NOx and PM controls.

Capital costs ranged from $180/kW for large units (larger than 600 MW) to

as high as $350/kW for small units (200 to 300 MW), (page 2-22).

However, the last few years have seen a general trend of declining capital

costs due to vendor competition and technology maturation. The cost

effectiveness (in dollars per ton) is very attractive, since these devices

remove a very large amount of SO2(driven by high sulfur content of coal

burned). The typical cost effectiveness is in the range of 200 to 500

dollars per ton of SO2 removed though higher values are obtained for

small units operating at low capacity factors and burning low-sulfur coals.

The cost effectiveness is determined mostly by the baseline pre-controlled

SO2 emission rate (or sulfur content of fuel), size and capacity factor of the

unit, as well as the capital cost of FGDs (that generally ranges from $150

to $200/Kw).

To predict future emissions from EGUs and to further study the costs of

emissions controls for EGUs, the Mid-Atlantic/Northeast Visibility Union

(MANE-VU) and other Regional Planning Organizations have also

followed the example of the US Environmental Protection Agency (EPA) in

using the Integrated Planning Model (IPM®), an integrated economic and

emissions model. IPM projects electricity supply based on various

assumptions and develops a least-cost solution to generating needed

electricity within specified emissions targets. IPM also provides estimates

of the costs of complying with various policy requirements. 

EPA developed Base Case version 2.1.9 using IPM to evaluate the

impacts of CAIR and the Clean Air Mercury Rule (CAMR). (Recently, EPA

updated their input data and developed Base Case v.3.0. Due to timing, all

MANE-VU runs were based on EPA Base Case v.2.1.9 with some

updates and corrections.)2

The Regional Planning Organizations collaborated with each other to

update EPA Base Case v.2.1.9 using more current data about EGUs with

more realistic fuel prices, creating an IPM run called VISTAS PC_1f. This

VISTAS IPM implementation is the one that has been used in regional air
3 See the report, Comparison of CAIR and CAIR+ Proposal using the Integrated Planning Model (IPM®), ICF

Resources LLC, May 2007, which is posted on the MARAMA web site. 

4 See Table 6, “Allowance Prices (Marginal Costs) of Emissions Reductions...” p. 9, ICF, May 2007. 

Marginal cost is defined as the cost of reducing one additional ton of emissions.

quality modeling for ozone and haze state implementation plans. 

MANE-VU, through MARAMA, contracted with ICF to prepare two new

IPM runs. 3 The MARAMA CAIR Base Case run was based on the VISTAS

PC_1f run and underlying EPA Base Case v.2.1.9, with some of the

information updated, (e.g., fuel prices, control constraints, etc.) to better

reflect current information. The MARAMA CAIR Base Case run is also

sometimes called MARAMA_5c. The MARAMA CAIR Plus run was also

based on VISTAS PC_1f run and the underlying EPA Base Case v.2.1.9,

but using lower NOx emission caps and higher SO2 retirement ratios.

Consistent with the MARAMA CAIR Base Case Run, the CAIR Plus Run

also updated some of the information used in the VISTAS run (e.g., fuel

prices, control constraints, etc.) to better reflect current information. The

MARAMA CAIR Plus run is also sometimes referred to as MARAMA_4c. 

Using IPM, EPA estimates average costs for compliance with CAIR to be

$500 to $700 per ton of SO2 emissions, with marginal costs of $700 to

$1,000 per ton of SO2 emissions. On the other hand, the above

referenced analysis conducted for MANE-VU by ICF, Inc., which used

updated cost estimates for natural gas, indicated that the cost of

compliance with CAIR would rise from $806 in 2008 to $1,392 per ton in

2018 (marginal costs of allowances in 2006 dollars).4 

The MANE-VU Reasonable Progress Report reviewed options for

controlling coal-fired EGU boilers, including switching to lower sulfur coal,

switching to natural gas, coal cleaning, and flue gas desulfurization (FGD). 

The most effective control option (though not necessarily appropriate for

all installations) is FGD, which can achieve up to 95 percent reduction in

SO2 emissions. The cost varies considerably among units and was

estimated to range from as low as $170/ton to as high as $5,700/ton.

(Converted from 2001 to 2006 dollars using a conversion factor of 1.1383

www.inflationdata.com). The 2005 MANE-VU Report “Assessment of

Control Technology Options for BART-Eligible Sources estimated that

wet/dry scrubbers would cost $200 to $500 (2006 dollars) per ton of SO2

removed at BART-Eligible EGUs, which tend to be large, older units. 

MANE-VU’s strategy calls for a 90 percent reduction in SO2 emissions

from the identified 167 key stacks, but it provides that alternative

measures may be pursued if it is infeasible to achieve that level of
reduction. These stacks are located both inside and outside the MANEVU region. Costs for specific individual plants to reduce emissions by 90

percent as recommended by the MANE-VU strategy will vary. The MANEVU strategy provides the flexibility for states to control emissions from

alternative sources if necessary in order to reduce costs and asks states

to pursue controls on specific sources as appropriate and necessary. 

Given the importance of SO2 emissions from specific EGUs in impairing

visibility in MANE-VU Class I areas, the availability of technology to reduce

emissions, the estimated cost, the costs of alternative measures, and the

flexibility to achieve alternative reductions if necessary, MANE-VU

Commissioners concluded that the costs of reducing emissions from the

identified key stacks was reasonable.

Time Necessary for Compliance 

MANE-VU’s Reasonable Progress Report indicates that generally,

sources are given a two to four year phase-in period to comply with new

rules. Under Phase I of the NOx SIP call, EPA provided a compliance

date of about 3.5 years from the SIP submittal date. Most MACT

standards allow a 3-year compliance period. 

MANE-VU has concluded that there is more than sufficient time between

2008 and 2018 for affected states to adopt requirements and for affected

sources to install necessary controls.

Energy and Non-Air Quality Environmental Impacts of Compliance 

The MANE-VU Reasonable Progress Report identified several energy and

non-air quality impacts from additional EGU controls. These included

potential impacts on fuel supplies if there were large-scale fuel switching,

triggering NSR requirements, and the generation of wastewater and

sludge from flue gas desulfurization systems. Mercury emissions may be

reduced by the addition of controls for other pollutants. Furthermore, SO2,

NOx, and ammonia controls would have beneficial environmental impacts

by reducing acid deposition and nitrogen deposition to water bodies and

natural landscapes. Reductions would also result in decreases in ambient

levels of PM2.5 with corresponding health benefits. MANE-VU concluded

that the energy and non-air quality impacts of additional EGU controls are

reasonable.

Remaining Useful Life of Any Potentially Affected Sources 

It is highly unlikely that additional EGU controls required under this SIP

would have any impact on the remaining useful life of a particular EGU. 

As noted in the MANE-VU Reasonable Progress Report, remaining useful

life estimates of EGU boilers indicate a wide range of operating lifetimes,
depending on the size of the unit, capacity factor, and level of

maintenance performed. Typical life expectancies range to 50 years or

more. Additionally, implementation of regulations over the years has

resulted in retrofitting that has ultimately increased the expected life span

of many EGUs. The lifetime of an EGU may be extended through repair,

re-powering, or other strategies if the unit is more economical to run than

to replace with power from other sources. This may be particularly likely if

the unit serves an area which has limited transmission capacity available

to bring in other power. The remaining useful life of a unit should not be

confused with the economic decision of whether or not to continue

operating a unit or to re-power or replace it. The cost of environmental

compliance is only one of many factors involved in such a decision.

III. Low Sulfur Fuel Oil Requirements are Reasonable within MANE-VU

The MANE-VU contribution Assessment documented source

apportionment analyses that linked visibility impairment in MANE-VU

Class I areas with SO2 emissions from sources burning fuel oil. The

reasonable assumption underlying the low-sulfur fuel oil strategy is that

refiners can, by 2018, produce home heating and fuel oils that contain 50

percent less sulfur for the heavier grades (#4 and #6 residual oil), and a

minimum of 75 percent and maximum of 99.25 percent less sulfur in #2

fuel oil (also known as home heating oil, distillate, or diesel fuel) at an

acceptably small increase in price to the consumer. 

The MANE-VU Reasonable Progress Report discussed the four factors as

they apply to low sulfur fuel use in chapters assessing controls for

industrial, commercial, and institutional boilers and heating oil controls.

MANE-VU’s Reasonable Progress Report identified switching to a lower

sulfur oil as an available SO2 control option that would achieve 50 to 90

percent reductions in SO2 emissions from ICI Boilers. The report also

noted that home heating oil use generates an estimated 100,000 tons of

SO2 emissions in the Northeast each year, and that SO2 emissions would

decline in proportion to reductions in fuel sulfur content.The following

discussion summarizes information concerning the four factors for the lowsulfur fuel strategy.

Costs of Compliance 

The MANE-VU Reasonable Progress report noted that because of

requirements for motor vehicle fuels, refineries have already performed

the capital investments required for the production of low sulfur diesel and

ultra-low sulfur diesel. The report estimated a cost per ton of SO2

removed by switching to lower sulfur fuel would range from $554 to $734

per ton (Converted from 2001 to 2006 dollars using a conversion factor of
5 “Low Sulfur Heating Oil in the Northeast States: An Overview of Benefits, Costs and Implementation Issues”,

December 31, 2005 by NESCAUM.

1.1383 www.inflationdata.com). (See Chapter 8 of the Reasonable

Progress Report.) In some seasons and some locations, low sulfur diesel

is actually cheaper than regular diesel fuel.

While costs for these emissions reductions are somewhat uncertain, they

are quite reasonable in comparison to costs of controlling other sectors. 

Some MANE-VU states are proceeding with low-sulfur oil requirements

much sooner than 2018; however, all of the MANE-VU states agreed that

a low-sulfur oil strategy is both reasonable and achievable by 2018. 

MANE-VU has concluded that the cost of requiring lower sulfur fuel is

reasonable.

Time Necessary for Compliance 

MANE-VU’s Reasonable Progress Report indicated that furnaces and

boilers would not have to be retrofit and would not require expensive

control technology to burn ULSD distillate fuel oil. Therefore, the time

necessary for compliance would be determined by the availability of the

fuel. 

The MANE-VU Reasonable Progress Report notes that nationally, more

ULSD is produced than both LSD and high sulfur fuel. The report

concludes that the US has the infrastructure to produce adequate stocks

of LSD and ULSD. The NESCAUM Low Sulfur Heating Oil Report5

 also

notes that the federal rules for heavy duty highway diesel fuel are flexible,

so that if there is a shortage of 15 ppm fuel, the 15 to 500 ppm fuel could

be used to relieve the shortage. With this flexibility, the report concludes

that the likelihood of a fuel shortage in the short term due to use of ULSD

for heating oil is reduced. The volatile nature of heating supply and

demand presents unique challenges to the fuel oil industry. The success

of a low sulfur fuel oil program is predicated on meeting these challenges. 

The Northeast states are assessing a variety of business strategies and

regulatory approaches that could be used to minimize any potential

adverse supply and price impacts that could result from a regional 500

ppm sulfur standard for heating oil. Suppliers can increase pre-season

reserves and look to increase imports from offshore refiners producing low

sulfur product. Blending domestically produced biodiesel into heating oil

offers opportunity to reduce imports, stabilize supplies and minimize

supply-related price spikes. Air quality regulators are also considering

permitting seasonal averaging of sulfur content which would allow higher

sulfur imports to be brought to the Northeast market during periods of

peak demand. Over the course of the year, the higher sulfur fuel would
6 The MANE-VU Statement concerning controls outside of MANE-VU titled, Statement of the MidAtlantic/Northeast Visibility Union (MANE-VU) Concerning a Request for a Course of Action by States

Outside of MANE-VU Toward Assuring Reasonable Progress” dated June 20, 2007.

have to be offset by heating oil with a sulfur content below the standard.

The strategy adopted by MANE-VU phases in the requirement for lower

sulfur fuel over the next 10 years, providing adequate time for this strategy

to be implemented. 

Energy and Non-Air Quality Environmental Impacts of Compliance

Reducing the sulfur content of fuel oil would have a variety of beneficial

consequences for boilers and furnaces using the fuel, according to MANEVU’s Reasonable Progress Report. Low sulfur distillate fuel is cleaner

burning and emits less particulate matter, which reduces the rate of fouling

of heating units substantially and permits longer time intervals between

cleanings. The MANE-VU report cites a study by the New York State

Energy Research and Development Authority (NYSERDA) that showed

that boiler deposits are reduced by a factor of two by lowering the fuel

sulfur content from 1,400 ppm to 500 ppm.

The report also notes that decreasing sulfur levels in fuel would enable

manufacturers to develop more efficient furnaces and boilers by using

more advanced condensing equipment that recovers energy normally lost

to the heating of water vapor in the exhaust gases. Furthermore, SO2

controls would also have beneficial environmental impacts by reducing

acid deposition and helping to decrease concentrations of PM2.5. 

Reductions in PM2.5 would potentially help nonattainment areas meet

health-based National Ambient Air Quality Standards.

Remaining Useful Life of Any Potentially Affected Sources 

Switching to low sulfur fuel would not adversely affect the remaining useful

lifetime of any affected source. In fact, the use of low sulfur oil could

extend the useful life of a source by reducing the maintenance required

since low sulfur oil is less damaging to the combustion equipment. 

IV. Additional Emission Reduction Measures Outside MANE-VU are

Reasonable

The MANE-VU Statement concerning controls outside MANE-VU

explained in Section 9.4.3, above, requested states to reduce non-EGU

SO2 emissions by 28 percent relative to on-the-books, on-the-way 2018

emissions projections6. MANE-VU asked neighboring RPOs to consider

non-EGU emissions reductions comparable to MANE-VU’s low sulfur fuel
strategies, which are expected to achieve a greater than 28 percent

reduction in non-EGU SO2 emissions in 2018. This request was reflected

in the modeling used to determine the reasonable progress goals by

reducing emissions from the following source categories in both the

Midwest RPO and the VISTAS regions:

• Coal-fired industrial/commercial/institutional boilers (60 percent

reduction)

• Oil-fired industrial/commercial/institutional boilers (75 percent

reduction)

• Other industrial/commercial/institutional boilers (50 percent

reduction)

In addition, emissions from the following source categories were reduced

in the VISTAS region:

• Other oil combustion sources in the area source inventory (75

percent reduction) (same SCC codes as used in MANE-VU). 

These strategies are similar to those being pursued in the MANEVU region. 

Low Sulfur Oil Strategy The strategies reducing emissions from oil-fired

installations are considered reasonable in other regions for the reasons

noted above with regard to the low sulfur fuel oil requirements being

pursued within MANE-VU. MANE-VU realizes that the use of fuel oil is

more prevalent in the Northeastern US than in the Midwest or Southeast. 

Switching to lower sulfur fuel in the Midwest or Southeast may achieve a

smaller reduction in emissions than will be achieved in the Northeast. 

However, use of the lower sulfur fuel will have beneficial impacts on

regional haze, fine particulate air pollution, acid rain, and equipment

operation, as described above, and MANE-VU has concluded that the

costs of requiring lower sulfur fuel would be reasonable in light of these

benefits. Furthermore, MANE-VU’s reasonable progress goals would

allow Midwestern and Southeastern states the flexibility to achieve needed

emissions reductions in the manner they determine to be most practical

for their states; a low sulfur oil strategy is not mandated.

Coal-Fired ICI Boiler Strategy The reduction of emissions from coal-fired

ICI boilers in the Midwest RPO and VISTAS is considered a reasonable

strategy given the importance of those sources in the Midwest and

Southeastern US and the costs and benefits described in several

reasonable progress analyses. Further discussion of the reasonableness

of controlling ICI boilers is provided below. 

Emissions from ICI boilers are currently governed by multiple State and

federal regulations under the Titles I, III, and IV of the Clean Air Act. The
7 The report entitled “Reasonable Progress for Class I Areas in the Northern Midwest – Factor Analysis

(July 18, 2007, EC/R Inc. for LADCO and Minnesota Pollution Control Agency) evaluated the four statutory

factors for controls on ICI boilers. The report covered a region that included the states of North and South

Dakota, Minnesota, Wisconsin, Michigan, Iowa, Missouri, Illinois, and Indiana. This will be called the

EC/R report. 

regulation of ICI boilers by various Clean Air Act programs has resulted in

a variety of unit level emission limits resulting from SIP, New Source

Performance Standards, New Source Review, or Maximum Achievable

Control Technology requirements. Overlaid on these unit level

requirements are system-wide allowances of the NOX SIP call and the

Acid Rain SO2 opt-in program. Thus, the specific emission limits and

control requirements for a given ICI boiler vary and depend on boiler age,

size, and geographic location.

Air pollution reduction and control technologies for ICI boilers have

advanced substantially over the past 25 years. In addition, advances in

power generation technologies, renewable energy, and energy efficiency

have the potential to further reduce emissions from these facilities. The

focus of the evaluation in the MANE-VU Reasonable Progress Report was

on the first category mentioned above - emission control technologies. 

The timing and magnitude of reductions from the other strategies –

improved technologies, demand reduction/energy efficiency, and clean

power may be part of a longer-term solution.

Descriptions of available SO2 control technology options are available in

Chapter 4 of the MANE-VU Reasonable Progress Report. 

Analysis of controls for the Midwest Regional Planning Organization also

identified SO2 control at ICI boilers as an important control strategy.7 The

EC/R report documented the importance of controlling emissions from ICI

boilers in the Northern Midwest because “Source apportionment analyses

identify SO2 and NOx emissions from non-EGU point sources as the

second largest contributor to visibility impairment in Isle Royale in 2018. 

ICI boilers account for a large portion of SO2 and NOx emission from nonEGU point sources.” The report indicated analyzed means to achieve two

market-based control strategies that would reduce ICI boiler SO2

emissions between 40 percent and 77 percent. The EC/R analysis

indicated that either strategy could be achieved by controlling coal fired

boilers with spray dryer absorber (SDA) technology and by switching oil

fired boilers to a lower sulfur fuel. 

In addition to the MANE-VU Reasonable Progress Report, the analysis of

the ICI boiler strategy relied on the 2005 MANE-VU report, “Assessment

of Control Technology Options for BART-Eligible Sources.” (The

following paragraphs are from the 2005 NESCAUM BART Document)
According to the 1998 survey of industrial boilers by EPA (2004), only 2

percent of gas-fired boilers and 3 percent of oil-fired boilers had any kind

of air pollution control device. More coal-fired boilers had air pollution

control devices: 47 percent had some control device and these were

largely PM controls.

Post-combustion SO2 control was used by less than one percent of

industrial boilers in 1998, with the exception of boilers firing petroleum

coke: 2 percent of boilers firing petroleum coke had acid scrubbers. A

small percentage of industrial boilers had combustion controls in place in

1998, although since 1998, additional low-NOX firing systems may have

been installed.

Almost all SO2 emission control technologies fall in the category of

reducing SO2 after its formation, as opposed to minimizing its formation

during combustion. The exception to the nearly universal use of postcombustion controls is found in fluidized bed boilers, in which limestone is

added to the fluidized bed combustion. Typically 90 percent of the sulfur

can be captured in a coal-fired fluidized bed using limestone with Ca/S

molar ratios of 2 to 2.5, depending on the sulfur content of the fuel, the

reactivity of the limestone and the operation of the combustor. Postcombustion SO2 control is accomplished by reacting the SO2 in the gas

with a reagent (usually calcium- or sodium-based) and removing the

resulting product (a sulfate/sulfite) for disposal or commercial use

depending on the technology used. SO2 reduction technologies are

commonly referred to as Flue Gas Desulfurization (FGD) and/or

"Scrubbers" and are usually described in terms of the process conditions

(wet versus dry), byproduct utilization (throwaway versus saleable) and

reagent utilization (once-through versus regenerable). Within each

technology category, multiple variations are possible and typically involve

the type and preparation of the reagent, the temperature of the reaction

(for dry processes), the use of enhancing additives, etc. Because these

variations mostly involve complex process chemistry, but are

fundamentally similar, this summary focuses on the major categories of

SO2 control technologies, their applicability, performance and cost.

Post-combustion SO2 control is accomplished by reacting the SO2 in the

gas with a reagent (usually calcium- or sodium-based) and removing the

resulting product (a sulfate/sulfite) for disposal or commercial use

depending on the technology used. SO2 reduction technologies are

commonly referred to as Flue Gas Desulfurization (FGD) and/or

"Scrubbers" and are usually described in terms of the process conditions

(wet versus dry), byproduct utilization (throwaway versus saleable) and

reagent utilization (once-through versus regenerable).

Within each technology category, multiple variations are possible and
typically involve the type and preparation of the reagent, the temperature

of the reaction (for dry processes), the use of enhancing additives, etc.

Because these variations mostly involve complex process chemistry, but

are fundamentally similar, this summary focuses on the major categories

of SO2 control technologies, their applicability, performance and cost.

A coal with sufficiently low sulfur content that when burned in the boiler

meets the applicable SO2 emission standards without the use of

additional controls is sometimes referred to as “compliance coal.” Coals

naturally low in sulfur content may be mined directly from the ground.

Alternatively, the sulfur content of coal fired in the boiler may be lowered

first by cleaning the coal or blending coals obtained from several sources.

However, burning low-sulfur coal may not be a technically feasible or

economically practical SO2 control alternative for all boilers. In some

cases, a coal with the required sulfur content to meet the applicable

standard may not be available or cannot be fired satisfactorily in a given

boiler unit design. Even if such a coal is available, use of the low-sulfur

coal that must be transported long distances from the mine may not be

cost competitive with burning higher sulfur coal supplied by closer mines

and using a post-combustion control device.

Various coal cleaning processes may be used to reduce the sulfur content

of the coal. A significant portion of the pyritic sulfur minerals mixed with

the mined coal can usually be removed by physical gravity separation or

surface property (flotation) methods. However, physical coal cleaning

methods are not effective for removing the organic sulfur bound in coal.

Another method of reducing the overall sulfur content of the coal burned in

a given boiler unit is to blend coals with different sulfur contents to meet a

desired or target sulfur level.

Fluidized bed boilers generally operate at lower temperatures than other

combustion systems, 800 to 870oC (1500 to 1600o

F). The lower

temperatures allow the use of limestone or dolomite to be added to the

bed to capture sulfur. Limestone (CaCO3) is converted to CaO at

approximately 800oC (1500oF). SO2 released from the fuel reacts with

CaO to form CaSO4, which is thermodynamically stable at bed

temperatures. By recycling some of the solids leaving the bed, which

contain unsulfated calcium, 90 percent removal of SO2 can be achieved

with Ca/S molar ratios of 2 to 2.5 in circulating fluidized beds. Higher Ca/S

ratios are required in bubbling beds. In either case, the sorbent is removed

with the ash from the bed and sent to disposal.

Wet FGD “scrubbers” date back to the 1960s with commercial applications

in Japan and the U.S. in the early 1970s. They represent the predominant

SO2 control technology in use today with over 80 percent of the controlled
capacity in the world and the U.S.

In a wet scrubber, the SO2-containing flue gas passes through a vessel or

tower where it contacts an alkaline slurry, usually in a counterflow

arrangement. The intensive contact between the gas and the liquid

droplets ensures rapid and effective reactions that can yield greater than

90 percent SO2 capture. Currently, advanced scrubber designs have

eliminated many of the early problems, primarily related to reliability, but

have also demonstrated very high SO2 reduction capabilities with some

units providing over 95 percent control.

Variations of the basic technology, in addition to equipment improvements

made over the years, include reagent and byproduct differences.

Limestone, lime, sodium carbonate and even seawater-based processes

are commercial. Limestone is by far the most widely used with

commercial-grade gypsum (wallboard quality) being produced in the socalled Limestone Forced Oxidation (LSFO) process. The use of other

reagents, as mentioned, is driven by site-specific criteria, such as local

reagent availability, economics, efficiency targets, etc.

Dry processes include spray dryer absorbers (SDA) and Dry Sorbent

Injection (DSI) technologies. SDA refers to a configuration where the

reaction between SO2 and the sorbent takes place in a dedicated reactor

or scrubber hence the common reference to “dry scrubber”; conversely,

DSI uses the existing boiler/duct system as the "reactor" and several

configurations are possible based on the temperature window desired.

This can occur at furnace (~2200oF), economizer (800-900oF) or duct

temperatures (~250oF). Dry processes are more compatible with low to

medium sulfur coals due to limitations in reaction rates and sorbent

handling (e.g., atomization). Therefore, high-sulfur applications are not

likely. In addition, another common feature among them is the need for

particulate control downstream of the sorbent injection. Usually this is

accomplished through the use of fabric filters (baghouses) which are, not

only efficient collectors of particulates, but also provide additional SO2

removal as the flue gas passes through unreacted sorbent collected on

the filters.

Dry SO2 controls vary significantly in performance, with SDAs being able

to achieve about 80 percent removal rates, whereas the various forms of

DSI are capable of 40 to 75 percent efficiencies.

Costs of Compliance 

Industrial boilers have a wider range of sizes than EGUs and often operate

over a wider range of capacities. Thus cost estimates for the same

technologies will generally span a relatively larger range, and costs for
8MANE-VU’s Reasonable Progress Report is entitled “Assessment of Reasonable Progress for Regional

Haze in MANE-VU Class I Areas” prepared by MACTEC for MARAMA, dated July 9, 2007.

9 BART Five Factor Analysis titled, “Five-Factor Analysis of BART-Eligible Sources: Survey of Options for

Conduction BART Determinations” prepared by NESCAUM for MANE-VU dated June 1, 2007.

individual boilers will depend on the capacity of the boiler and typical

operating conditions. 

The MANE-VU “Ask” provides the flexibility for states to control sources

where costs are in the lower end of the projected range rather than

applying a blanket reduction across all sources. The modeling

assumptions are applied across entire categories in order to estimate

impacts on visibility but this does not preclude another approach that

achieves similar emissions reductions at lower costs. 

MANE-VU’s Reasonable Progress Report provides cost estimates for

controlling emissions from ICI boilers that range from $130 per ton to

$11,000 per ton, a very wide range due to the variability of sources in this

category.8

 

The 1995 Assessment of Control Technology Options for BART-Eligible

Sources noted that both wet and dry scrubbers are in wide commercial use

to control SO2 emissions from industrial boilers in the U.S. Dry sorbent

injection (DSI) has lower capital costs than a spray dryer absorber (SDA),

although DSI can only achieve about 40 percent SO2 reduction. SDA

systems can achieve 90 percent reduction. Capital costs for DSI are in the

range of $8,600 to $26,000 per MMBtu/hr, depending on the size of the

system and on the sulfur content of the fuel. Capital costs for SDA systems

are about double that for DSI systems, but the cost per ton of SO2

removed is similar: $400 to $4000 per ton of SO2 removed. These costs

are higher than the costs for scrubbers on EGUs, which are only $100 to

$200 per ton of SO2 removed.

Wet FGD systems also remove 90 percent and higher of the SO2, but the

capital cost is a bout 50 percent higher than the cost for an SDA system.

The costs per ton of SO2 removed are similar to the cots for SDA for coalfired boilers. Costs per ton of SO2 are estimated to be about twice as high

for oil-fired boilers as compared to coal-fired boilers. 

In the BART Five-Factor Analysis9

 NESCAUM compiled cost estimates for

controls on BART units from state staff, the 2005 BART Control

Technology Report by NESCAUM report, and other RPO analyses. Cost

estimates from NESCAUM as well as the low, medium, and high cost

designations are summarized below in the table below.
10 Table from Appendix B in “Five-Factor Analysis of BART-Eligible Sources: Survey of Options for

Conduction BART Determinations” prepared by NESCAUM for MANE-VU dated June 1, 2007

Cost of Technologies for Industrial Boilers10

Pollutant

Industrial Boilers Cost Effectiveness

Control Cost Units Cost Bin

NOx Low NOx Burners 200-3000 $/Ton NOx Mid

NOx SNCR 1300-

10000 $/Ton NOx Mid to High

NOx SCR 4000-

15000 $/mmBtu/hr High

SO2 Wet/Dry Scrubbers 400-4000 $/Ton SO2 (coal) Mid

SO2 Wet/Dry Scrubbers 800-8000 $/Ton SO2 (oil) Mid to High

PM ESP 15-40 $/Actual cubic

feet/minute --

PM Reverse Air Fabric Filter 15-40 $/Actual cubic

feet/minute --

PM Pulse Jet Fabric Filter 17-40 $/Actual cubic

feet/minute --

PM Venturi Scrubber 12-40 $/Actual cubic

feet/minute --

PM Cyclone 1-5 $/Actual cubic

feet/minute --

Time Necessary for Compliance 

MANE-VU has concluded that there is sufficient time between 2008 and

2018 for affected states to adopt requirements and for affected sources to

install necessary controls. 

For combustion based and post-combustion based engineering and

construction leads times will vary between 2 and 5 years depending on the

size of the facility and specific control technology selected. Generally, 

sources are given a 2-4 year phase-in period to comply with new rules.

Under the previous Phase I of the NOX SIP Call, EPA provided a

compliance date of about 31⁄2 years from the SIP submittal date. Most

MACT standards allow a 3-year compliance period. Under Phase II of the
NOX SIP Call, EPA provided a 2-year period after the SIP submittal date for

compliance. States generally provided a 2-year period for compliance with

RACT rules. MANE-VU’s Reasonable Progress report assumed that a 2-

year period after SIP submittal is adequate for pre-combustion controls

(fuel switching or cleaning) and a three year period for the installation of

post combustion controls. 

For BART control measures, the proposed BART guidelines require States

to establish enforceable limits and require compliance with the BART

emission limitations no later than 5 years after EPA approves the regional

haze SIP.

Energy and Non-Air Quality Environmental Impacts of Compliance

Switching to lower sulfur fuel or installing post-combustion controls may

reduce boiler heat rate and energy output. Scrubbers and spray dryers will

require additional safeguards for fuel handling and waste handling systems

to avoid additional non-air environmental impacts such as increased

effluents in waste water discharges and storm water runoff. These factors

will need to be considered specific to individual sources. Carbon dioxide is

emitted as a by-product of flue gas desulfurization, therefore impacts of

increased carbon emissions will need to be considered, particularly if

carbon emissions are limited in the future under climate change mitigation

strategies.

The MANE-VU reasonable progress report notes, “Reducing the sulfur

content of distillate fuel oil has a variety of beneficial consequences for ICI

boilers. Low sulfur distillate fuel is cleaner burning and emits less

particulate matter which reduces the rate of fouling of heating units

substantially and permits longer time intervals between cleanings.” (p.4-14)

The EC/R report for the Northern Midwest region concludes, “The energy

and other environmental impacts of the potential control measures for ICI

boilers are believed to be manageable.” (p.102). The report indicates, “the

electricity and steam required by controls installed to meet SO2 and NOx

emission caps would be less than 1 percent of the total electricity and

steam production in the region. Solid waste disposal and wastewater

treatment costs are expected to be less than 5 percent of the total

operating costs of pollution control equipment.” (p.48) 

SO2 controls would have beneficial environmental impacts by reducing acid

deposition and helping to decrease concentrations of PM2.5. Reductions in

PM2.5 would potentially help nonattainment areas meet health-based

National Ambient Air Quality Standards. 

The MANE-VU reasonable progress report notes, “Reducing the sulfur
content of distillate fuel oil has a variety of beneficial consequences for ICI

boilers. Low sulfur distillate fuel is cleaner burning and emits less

particulate matter which reduces the rate of fouling of heating units

substantially and permits longer time intervals between cleanings.” (p. 4-

14)

Remaining Useful Life of Any Potentially Affected Sources 

It is unlikely that additional controls required to meet the goals established

under this SIP would have any impact on the remaining useful life of a

particular source. The strategy provides for flexibility in determining which

sources to control so that the most cost-effective controls can be adopted

and implemented over the next 10 years. 

Available information for remaining useful life estimates of ICI boilers

indicates a wide range of operating time, depending on size of the unit,

capacity factor, and level of maintenance performed. Typical life

expectancies range from about 10 years up to over 30 years. However, the

remaining useful life of a source is very unit specific.

References 

U.S. Environmental Protection Agency, National Emission Standards for

Hazardous Air Pollutants for Industrial/ Commercial/Institutional Boilers and

Process Heaters,

http://cascade.epa.gov/RightSite/dk_public_collection_detail.htm?ObjectType=dk_

docket_collection&cid=OAR-2002-0058&ShowList=items&Action=view (Accessed

February 25, 2004).