Appendix N - MANE-VU Basis for Reasonable Controls

Class I States’ Demonstration that t he 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 eac h Class I area, the State must consider the costs of compliance, the time nece ssary for compliance, the energy and non-air quality environmental impacts of complianc e, and the remaining useful life of any potentially affected sources, and the SIP mu st 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 SO 2

MANE-VU conducted a Contribution A ssessment 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 SO 2 . (See the NESCAUM report entitled Contributions to Regional Haze in the Northeast and Mid-Atlantic United States, Appendix A). T he 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-Atlant ic class I areas, the report states that, “[T]hese findings suggest that an effectiv e emissions management approach would rely heavily on broad-based regional SO2 control e fforts in the eastern United States.” While other pollutants, including organic carbon, will need to be addressed in order to achieve the national visibility goals, MA NE-VU’s Contribution Assessment suggested that an early emphasis on SO 2 will yield the greatest near-term benefit. Therefore, it is
reasonable that the additional measures c onsidered in setting the reasonable progress goals described in this document required reductions of SO 2 emissions.

Contributing Sources

The MANE-VU Contributions Assessment indi cates 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 s ources dominated the inventory of SO 2 emissions. Therefore, the MANE-VU strategies discuss ed in Section 9.4 and 9.5, above, include
additional measures to control sources of SO 2 both within the MANE-VU region and in
other states that were determined to cont ribute to regional haze at MANE-VU Class I

areas.

MANE-VU’s Contribution Assessment doc umented 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, t here was a collaborative effort between theOzone Transport Commission and MANE-VU to evaluate a large number of potential control measures, and several m easures that would reduce SO 2 emissions were identified for further study. This led MANE-VU to prepare the report entitled, “Assessment of Reasonable Progress for R egional Haze in MANE-VU Class I Areas” (MACTEC, July 9, 2007), which documented an anal ysis of the four statutory factors for five major source categories. This r eport 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-fac tor analysis presented in the Reasonable Progress Report, consulted with each ot her about the measures, and concluded by adopting the statements referenced above in this SIP on June 20, 2007. These

statements indicate which control measur es would be further pursued for adoption.

MANE-VU Class I states shared these stat ements with states out side the region that they determined reasonably caused or contribut ed 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, em issions reductions from specific EGUs, low sulfur fuel oil requirements, and addi tional measures determined to be reasonable.Summary of Results from the Four Factor AnalysisSourceCategoryPrimaryRegional HazePollutantPotentialControl Measure(s)Average Cost (in2006 dollars) perTon of PollutantReductionComplianceTimeframeEnergy and Non-AirQuality EnvironmentalImpactsRemainingUseful LifeElectricGenerating UnitsSO2Switch to a low sulfurcoal (generally <1%sulfur), switch tonatural gas (virtually0% sulfur), coalcleaning, Flue GasDesulfurization (FGD)-Wet, Flue GasDesulfurization (FGD)-Spray Dry, Flue GasDesulfurization (FGD) -Dry.MANE-VUapplication of IPM®*v.2.1.9 predicts$775 to $1,690.MACTEC reports$170 to $5,700based on availableliterature dependingon control methodand size of source2-3 years followingSIP submittalFuel supply issues,potential permittingissues, reduction inelectricity productioncapacity, wastewaterissues50 years ormoreIndustrial,Commercial,InstitutionalBoilersSO2Switch to a low sulfurcoal (generally <1%sulfur), switch tonatural gas (virtually0% sulfur), switch to alower sulfur oil, coalcleaning, combustioncontrol, Flue GasDesulfurization (FGD)-Wet, Flue GasDesulfurization (FGD)-Spray Dry, Flue GasDesulfurization (FGD) -Dry.MACTEC reports$130 to $11,000based on availableliterature.Depends on size ofplant and controlmethod.2-3 years followingSIP submittalFuel supply issues,potential permittingissues, control deviceenergy requirements,wastewater issues10-30 yearsSourceCategoryPrimaryRegional HazePollutantPotentialControl Measure(s)Average Cost (in2006 dollars) perTon of PollutantReductionComplianceTimeframeEnergy and Non-AirQuality EnvironmentalImpactsRemainingUseful LifeCement andLime KilnsSO2Fuel switching, DryFlue GasDesulfurization-SprayDryer Absorption(FGD), Wet Flue GasDesulfurization (FGD),Advanced Flue GasDesulfurization (FGD).MACTEC reports$1,900 to $73,000based on availableliterature. Dependson size of plant andcontrol method.2-3 years followingSIP submittalControl device energyrequirements,wastewater issues10-30 yearsHeating Oil SO2Lower the sulfurcontent in the fuel.Depends on the state.MACTEC reports$550 to $750 basedon availableliterature. There isa high uncertaintyassociated with thiscost estimate.Currently feasible.Capacity issuesmay influencetimeframe forimplementation ofnew fuel standardsIncreases infurnace/boiler efficiency,Decreased furnace/boilermaintenancerequirements18-25 yearsResidentialWoodCombustionPMState implementationof NSPS, ban onresale of uncertifieddevices, installertraining certification orinspection program,pellet stoves, EPAPhase II certified RWCdevices, retrofitrequirement,acceleratedchangeoverrequirement,acceleratedchangeoverinducement.MACTEC reports $0to $10,000 based onavailable literatureSeveral years -dependent onmechanism foremission reductionReduce greenhouse gasemissions, increaseefficiency of combustiondevice10-15 years* Integrated Planning Model® CAIR versus CAIR plusanalysis 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 m any of the specific EGU stacks will be
controlled as a result of EPA’s Clean Ai r 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 precurso rs of regional haze are commercially
available. 1 Since EGUs are the most signifi cant stationary source of SO 2 , NO

x , and PM, they have been subject to extensive federal and state regulations to control all three pollutant s. 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 y ears, a large amount of cost data have also become available that clearly indicated that many technologies2 Although the IPM model runs anticipated the implementa tion 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 SO 2 emissions from electric generating units (EGUs) used in the air quality modeling, based on state-specific comments on the

amount of SO 2 controls that will actually be installed due to stat e specific regulations and the EPA’s CAIR rule, will have more of an impact on the air quality modeling analys is conducted for this SIP than the vacature of the CAMR rule. MANE-VU believes the adjustments based on st ate-specific comments improved the reliability of the inventory and made the modeling results more dependable. provide substantial and extremel y cost effective reductions.

Both wet and dry scrubbers are in wide commercial use in the U.S. for controlling SO 2 emissions. The capital costs for new or retrofit wet or dry scrubbers are higher than the capital costs for NO

x 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 s een 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 SO 2 (driven by high sulfur content of coal burned). The typical cost effectiveness is in the range of 200 to 500 dollars per ton of SO 2 removed though higher values are obtained for small units operating at low capacity factors and burning low-sulfur coals.
The cost effectiveness is determined mo stly by the baseline pre-controlled
SO 2 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 EG Us and to further study the costs of emissions controls for EGUs, the Mi d-Atlantic/Northeast Visibility Union (MANE-VU) and other Regional Planning Organizations have also followed the example of the US Envi ronmental 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 ta rgets. IPM also provides estimates of the costs of complying wit h 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 mo re 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 air3 See the report

, Comparison of CAIR and CAIR+ Proposal us ing the Integrated Pl anning 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, c ontrol constraints, etc.) to better
reflect current information. The MARA MA 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 under lying EPA Base Case v.2.1.9, but using lower NOx emission caps and higher SO2 retirement ratios.
Consistent with the MARAMA CAIR Ba se 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 so metimes referred to as MARAMA_4c.

Using IPM, EPA estimates average costs for compliance with CAIR to be $500 to $700 per ton of SO 2 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, includi ng switching to lower sulfur coal, switching to natural gas, coal cleani ng, and flue gas desulfurization (FGD). The most effective control option (t hough not necessarily appropriate for all installations) is FGD, which can achieve up to 95 percent reduction in
SO 2 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 us ing 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 SO 2 removed at BART-Eligible EGUs, whic h tend to be large, older units.

MANE-VU’s strategy calls for a 90 percent reduction in SO 2 emissions from the identified 167 key stacks, but it provides that alternative measures may be pursued if it is in feasible to achieve that level ofreduction. These stacks are loca ted both inside and outside the MANEVU region. Costs for specific indi vidual plants to reduce emissions by 90percent 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 SO 2 emissions from specific EGUs in impairing visibility in MANE-VU Class I areas, the availability of technology to reduce emissions, the estimated cost, the cost s 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 NO x 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 Envir onmental 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 t here 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 fo r other pollutants. Furthermore, SO 2 , 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 PM 2.5 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 EG U 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 lif e expectancies range to 50 years or more. Additionally, implementation of regulations over the years has resulted in retrofitting that has ulti mately 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 source s. 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 vi sibility impairment in MANE-VU
Class I areas with SO 2 emissions from sources burning fuel oil. The reasonable assumption underlying the low-su lfur fuel oil strategy is that refiners can, by 2018, produce home heat ing 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 o il, distillate, or diesel fuel) at an acceptably small increase in price to the consumer.

The MANE-VU Reasonable Progress Repor t discussed the four factors as they apply to low sulfur fuel use in chapters assessing controls for industrial, commercial, and instituti onal boilers and heating oil controls.

MANE-VU’s Reasonable Progress Report identified switching to a lower
sulfur oil as an available SO 2 control option that would achieve 50 to 90 percent reductions in SO 2 emissions from ICI Boilers. The report also noted that home heating oil use generat es an estimated 100,000 tons of
SO 2 emissions in the Northeast each year, and that SO 2 emissions would decline in proportion to reductions in fuel sulfur content.The followingdiscussion 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 t he production of low sulfur diesel and ultra-low sulfur diesel. The repor t estimated a cost per ton of SO 2 removed by switching to lower sulfur fuel would range from $554 to $734 per ton (Converted from 2001 to 2006 dolla rs using a conversion factor of5 “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 distilla te 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 Report 5 also notes that the federal rules for heavy dut y 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 vo latile nature of heating supply and demand presents unique challenges to t he 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 qualit y regulators are also considering permitting seasonal averaging of sulfur content which would allow higher sulfur imports to be brought to t he Northeast market during periods of peak demand. Over the course of the year, the higher sulfur fuel would6 The MANE-VU Statement concerning controls outsi de of MANE-VU titled, Statement of the MidAtlantic/Northeast Visibility Union (MANE-VU) Conc erning a Request for a Course of Action by States
Outside of MANE-VU Toward Assuri ng 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 Envir onmental Impacts of Compliance

Reducing the sulfur content of fuel oil would have a variety of beneficialconsequences 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 fa ctor 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, SO 2 controls would also have beneficial environmental impacts by reducing acid deposition and helping to decrease concentrations of PM 2.5 . Reductions in PM 2.5 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 fa ct, 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
SO 2 emissions by 28 percent relative to on-the-books, on-the-way 2018 emissions projections 6 . MANE-VU asked neighboring RPOs to consider non-EGU emissions reductions comparabl e to MANE-VU’s low sulfur fuelstrategies, which are expected to achieve a greater than 28 percent
reduction in non-EGU SO 2 emissions in 2018. This request was reflected in the modeling used to determine the reasonable progress goals by reducing emissions from the followi ng source categories in both the Midwest RPO and the VISTAS regions:

• Coal-fired industrial/commercial/in stitutional boilers (60 percent reduction)
• Oil-fired industrial/commercial/in stitutional boilers (75 percent reduction)
• Other industrial/commercial/in stitutional boilers (50 percent reduction)

In addition, emissions from the follo wing 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 su lfur fuel oil requirements being pursued within MANE-VU. MANE-VU rea lizes 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 t hey 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 curr ently governed by multiple State and federal regulations under the Titles I, III, and IV of the Clean Air Act. The7 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 Pollu tion 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 limit s resulting from SIP, New Source Performance Standards, New Source Review, or Maximum Achievable Control Technology requirements. Overlaid on these unit level requirements are system-wi de allowances of the NO X SIP call and the
Acid Rain SO 2 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 emi ssions from these facilities. The
focus of the evaluation in the MA NE-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 SO 2 control technology options are available in Chapter 4 of the MANE-VU Reasonable Progress Report.

Analysis of controls for the Midw est 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 SO 2 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 SO 2 and NOx emission from nonEGU point sources.” The report indi cated analyzed means to achieve two market-based control strategies that would reduce ICI boiler SO 2 emissions between 40 percent and 77 percent. The EC/R analysis indicated that either strategy coul d 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 t he 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 ex ception 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 fl uidized bed using limestone with Ca/S molar ratios of 2 to 2.5, depending on t he sulfur content of the fuel, the reactivity of the limestone and the oper ation of the combustor. Postcombustion SO2 control is accomplis hed 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 utilizati on (throwaway versus saleable) and reagent utilization (once-through ve rsus 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 enhanc ing 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 acco mplished 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 utilizati on (throwaway versus saleable) and reagent utilization (once-th rough versus regenerable).

Within each technology category, multiple variations are possible andtypically involve the type and preparat ion of the reagent, the temperature of the reaction (for dry processes) , the use of enhancing additives, etc. Because these variations mostly in volve 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 emissi on standards without the use of
additional controls is sometimes referr ed to as “compliance coal.” Coals naturally low in sulfur content ma y be mined directly from the ground. Alternatively, the sulfur content of c oal 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 sulf ur 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 sulf ur 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 1600 o F). The lower temperatures allow the use of limes tone or dolomite to be added to the bed to capture sulfur. Limestone (CaCO3) is converted to CaO at approximately 800oC (1500oF). SO2 rel eased 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 t he 1960s with commercial applications in Japan and the U.S. in the early 1970s. They represent the predominant SO2 control technology in use today wit h over 80 percent of the controlledcapacity 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 contac t between the gas and the liquid droplets ensures rapid and effective r eactions that can yield greater than 90 percent SO2 capture. Current ly, 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 si te-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 refe rs to a configuration where the
reaction between SO2 and the sorbent ta kes 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 processe s are more compatible with low to
medium sulfur coals due to limitat ions in reaction rates and sorbent handling (e.g., atomization). Therefor e, 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 particulate s, 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 for8MANE-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, “F ive-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 flexib ility 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 boile rs 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 industr ial 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 t he 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 scr ubbers on EGUs, which are only $100 to $200 per ton of SO2 removed.

Wet FGD systems also remove 90 percent and higher of the SO 2 , but the capital cost is a bout 50 percent hi gher than the cost for an SDA system. The costs per ton of SO 2 removed are similar to the cots for SDA for coalfired boilers. Costs per ton of SO 2 are estimated to be about twice as high for oil-fired boilers as compared to coal-fired boilers.

In the BART Five-Factor Analysis 9 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” pr epared by NESCAUM for MANE-VU dated June 1, 2007 Cost of Technologies for Industrial Boilers 10

Pollutant Industrial Boilers Cost Effectiveness

Control Cost Units Cost Bin

NOx Low NOx Burner s 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 c ontrol 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 NO X SIP Call, EPA provided a compliance date of about 31⁄2 years fr om the SIP submittal date. Most MACT standards allow a 3-year compli ance period. Under Phase II of theNO X SIP Call, EPA provided a 2-year peri od after the SIP submittal date for compliance. States generally provided a 2-year period for compliance with
RACT rules. MANE-VU’s Reasonable Pr ogress report assumed that a 2- year period after SIP submittal is adequate for pre-combustion controls (fuel switching or cleaning) and a thr ee year period for the installation of post combustion controls.

For BART control measures, the pr oposed 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 Envir onmental 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 SO 2 and NOx emission caps would be less than 1 perc ent of the total electricity and steam production in the region. So lid 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)

SO 2 controls would have beneficial envir onmental impacts by reducing acid deposition and helping to decrease concentrations of PM 2.5 . Reductions in

PM 2.5 would potentially help nonattainment areas meet health-based National Ambient Air Quality Standards.

The MANE-VU reasonable progress report notes, “Reducing the sulfurcontent 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 provi des 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 us eful life estimates of ICI boilers indicates a wide range of operating time, depending on size of the unit, capacity factor, and level of main tenance 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&Show List=items&Action=view (Accessed February 25, 2004).