August 6 2007 MANE-VU/MRPO Consultation Summary (DRAFT) 

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MANE-VU/MRPO Consultation Meeting 

August 6, 2007 

Rosemont, IL 

 On Monday, August 6, 2007, the Mid-Atlantic/Northeast Visibility Union (MANE-VU) 

Class I states (Maine,Vermont, New Hampshire, and New Jersey) held a consultation with 

several of the Midwest Regional Planning Organization (MRPO) states (Illinois, Indiana, Ohio, 

Michigan and Wisconsin). The following summary documents the discussions that took place 

during the consultation. 

Summary of Today’s Consultation Agreements

1. Define next steps for multi-pollutant approach to reduce regional haze, PM 2.5, and 

ozone 

2. Discuss crafting a revised national ask among interested MANE-VU and MRPO 

states regarding needs for national action on EGUs, including potential multipollutant control levels for CAIR Phase III with emission rates and output-based 

options; 

3. Pursue discussions on options for reducing SO2 (and NOx) emissions from ICI 

boilers, including: 

• Reconvening the MANE-VU/MRPO ICI boiler workgroup to re-examine the 

workgroup’s January 2007 straw proposal; 

• Developing a process for sharing information on SO2 RACT for ICI boilers, and 

examining potential SO2 control measures; 

• Contacting NACAA regarding expansion of the Boiler MACT model rule work to 

address SO2 and NOx; and 

• Discuss crafting a national ask among interested MANE-VU and MRPO states 

regarding national action on ICI boilers. 

4. Discuss crafting a national ask regarding low sulfur fuel for all off-road sources, and 

share information on biodiesel. 

5. Continue to share modeling assumptions and analyses, and continue dialogue 

between MANE-VU and MRPO states regarding SIP submittals. 

6. Define next steps to gather information on controls for locomotives and ocean-going 

vessels. 

7. Develop list of controls for units that will be scrubbed, not just MANE-VU’s list of 

167 stacks. 
August 6 2007 MANE-VU/MRPO Consultation Summary (DRAFT) 

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Attendees

States and Tribes FLMs and EPA

Maine – Dave Littell, Jeff Crawford National Park Service – Bruce Polkowsky 

New Hampshire – Tom Burack, Bob Scott Forest Service – Anne Mebane, Chuck Sams, 

Rich Fisher 

New Jersey – Chris Salmi Fish and Wildlife Service – Tim Allen 

Vermont –Justin Johnson, Dick Valentinetti, 

Paul Wishinski 

EPA Region I – Anne Arnold 

Illinois – Laurel Kroack, Scott Leopold EPA Region II – Bob Kelly

Indiana – Tom Easterly, Ken Ritter EPA Region III (by phone) – Ellen Wentworth, 

Neil Bigioni 

Ohio – Bob Hodanbosi EPA Region V – John Summerhays 

Michigan – Vince Hellwig, Cindy Hodges, 

Bob Irvine 

EPA – OAQPS (by phone) – Todd Hawes, 

Michelle Notarianni

Wisconsin – Larry Bruss 

MRPO – Mike Koerber 

MANE-VU – Anna Garcia, Doug Austin 

MARAMA – Susan Wierman, Julie McDill 

NESCAUM – Gary Kleiman 

Consultation Meeting Presentations and Discussions

Welcome and Introductions – Goals for Today’s Meeting - David Littell, Maine DEP 

• Presented goals for today’s consultation: 

- Review requirements, resources and critical timing issues to ensure all share a 

common understanding; 

- Discuss options for control measures to identify what is reasonable for joint work 

between regions; 

- Identify impediments to implementing control measures and discuss how to address 

them; 

- Identify links between haze and PM that help define what is reasonable; 

- Examine reasonable progress for MRPO and MANE-VU Class I areas in terms of 

control measure options; and 

- Summarize points of agreement and identify issues for follow-up consultation 

• Compare our request for what we need in terms of reductions to improve visibility at our 

Class I areas with what the MRPO states have done to address their own Class I areas and 

regional haze/PM issues 

• Find out how close we are, what gaps may still remain, and discuss how we may address 

them together. 
August 6 2007 MANE-VU/MRPO Consultation Summary (DRAFT) 

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Overview of Open Technical Call & Consultation Briefing Book – Anna Garcia, MANE-VU 

• Open Technical Call discussions provided a good technical basis for today’s meeting. 

• MANE-VU staff is developing draft documentation of the Open Call and of today’s 

discussions, and will circulate the drafts for comment and make the final documentation 

available to all states for use in their state implementation plans (SIPs). 

Summary of Reasonable Progress Work and Development of “Asks” for MANE-VU Class 

I Areas – Chris Salmi, New Jersey DEP 

Presentation: 

• Provided a review of MANE-VU Class I states’ Resolution on Principles; 

• Showed focus for MANE-VU is on sulfate reductions for the 2018 milestone; 

• Gave an overview of MANE-VU’s four factor analysis; 

• Outlined how MANE-VU Class I states developed the “asks” for the MANE-VU and 

MPRO regions; 

• Provided a comparative analysis of the MANE-VU region “ask” with that of the MRPO 

“ask”; 

• Outlined the specifics of each of the asks, including for MRPO: 

- Timely implementation of BART requirements; 

- A focused strategy for the electricity generating units (EGUs) comprising a 90% 

reduction of sulfate emissions from 2002 levels from 167 stacks that modeling 

indicates affect visibility impairment in MANE-VU Class I areas; 

- A 28% reduction from non-EGU sector emissions based on 2002 levels; and 

- Continued evaluation of other measures, including measures to reduce SO2 and 

nitrogen oxide (NOx) emissions from coal-burning facilities by 2018. 

• Within MANE-VU, the Class I states have the following commitment: 

- Timely implementation of BART requirements; 

- A focused strategy for the electricity generating units (EGUs) comprising a 90% 

reduction of sulfate emissions from 2002 levels from 167 stacks that modeling 

indicates affect visibility impairment in MANE-VU Class I areas; 

- A low sulfur fuel oil strategy with different implementation timeframes for inner zone 

states versus outer zone states, that results in a 38% reduction from non-EGU sector 

emissions in the MANE-VU region; and 

- Continued evaluation of other measures, including measures including energy 

efficiency, alternative clean fuels and other measures to reduce SO2 and nitrogen 

oxide (NOx) emissions by 2018. 

• Also outlined the national “ask” MANE-VU plans to make of the US EPA, for a Phase 3 

of CAIR that reduces SO2 by at least an additional 18%. 

• From presentation, next steps are: 

- Consult within and outside MANE-VU about which control strategies are reasonable; 

- Open a dialogue with the USEPA concerning a possible Phase 3 of CAIR; 

- Define strategies to include in the final modeling; 

- Determine goals based on the final modeling; 

- SIPs are due 12/17/07; 

- Adopt enforceable emissions limits & compliance schedules; and 
August 6 2007 MANE-VU/MRPO Consultation Summary (DRAFT) 

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- Progress evaluation due in 5 years. 

Discussion: 

• Question (Tom Easterly, Indiana): Are there emission rate targets instead of a flat 90% 

reduction? 

- Answer (Chris Salmi, New Jersey): No, and no net reductions. 

• Question (Tom Easterly, Indiana): Where do the emissions go? 

• Answer (Gary Kleiman, NESCAUM): MANE-VU EGU reduction on the order of 

68,000 TPY would be “rearranged.” They are spread out between all EGUs 

proportionately, except for those in the 167 stacks, to maintain the cap.Question (Tom 

Easterly, Indiana): Did MANE-VU use the 0.5dV exemption threshold for BART 

sources? 

- Answer (Gary Kleiman, NESCAUM): MANE-VU did not exempt any BART sources 

from the BART determination process. 

• Question (Mike Koerber, MRPO): What is the source of the MANE-VU numbers? 

- Answer (Gary Kleiman, NESCAUM): They are from MARAMA’s inventory work. 

National ask for EGU sector based on IPM results and increasing the SO2 ratios. 

• Comment (Mike Koerber, MRPO): The MANE-VU numbers are close to his, but we need 

to sync them up. 

• Comment (Tom Easterly, Indiana): Companies make economic analyses for installation 

of controls and we keep changing the rules on them. 

- Answer (Gary Kleiman, NESCAUM): They are spread out between all EGUs 

proportionately, except for those in the 167 stacks, to maintain the cap. 

Summary of Reasonable Progress Work for MRPO Class I Areas – Mike Koerber, MRPO 

Presentation:

• MRPO results consistent with MANE-VU analyses. 

• MRPO states still looking at strategies for their 4 northern Class I areas, nitrates a bigger 

share of visibility impairment, visibility impacts mostly from southerly transport. 

• With OTB measures, we are above glide path in 2018 for all 4 Class I areas. 

• Review of MRPO 5-Factor Analysis (including degree of visibility improvement) for 

reasonable progress. 

• Review of new visibility metric of $/dV improvement, additional control measures 

comparable in costs to existing OTB controls, most visibility improvement obtained from 

MRPO’s EGU1 (0.3dV) and EGU2 (0.4dV) strategies. 

• MRPO analysis regional in nature, not a focused EGU strategy like MANE-VU due to 

different source / receptor relationships. 

• Review of projected visibility levels, Seney above glide path in 2018, a lot more SO2 will 

need to be “squeezed” out of the system to achieve 2064 natural conditions. 

• Review of MRPO source apportionment analysis, MRPO contributes 10-15% of visibility 

impairment at Lye Brook in Vermont. 

• Conclusions and key findings from MRPO analyses: 

- Many Class I areas in the eastern half of U.S. expected to be below the glide path in 

2018 (with existing controls), including those in the Northeast; 

- Contribution analyses show closer states have larger impacts; and 
August 6 2007 MANE-VU/MRPO Consultation Summary (DRAFT) 

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- Regional emission reductions (in 2013-2018 timeframe), such as those identified in 

MANE-VU’s June 2007 resolutions, may be necessary to meet reasonable progress 

goals in the MRPO Class I areas and provide for attainment of new tighter PM2.5 and 

possibly tighter ozone standards in the MRPO states. 

Discussion:

• Question (Tom Easterly, Indiana): How do we deal with ammonia? 

- Answer (Mike Koerber, MRPO): EPA won’t touch it and ammonia is included in the 

analyses for completeness. 

• Question (Jeff Crawford, Maine): Are mobile measures included? 

• - Answer (Mike Koerber, MRPO): Only bundled measures including chip reflash and 

diesel retrofits where the states are not preempted from doing such measures. 

• Question (Tom Easterly, Indiana): Would a monthly electric bill of $150 be doubled? 

- Answer (Mike Koerber, MRPO): Yes, at least doubled. 

• Question (Dave Littell, Maine): Are ammonia controls from the agricultural sector 

assumed? 

- Answer (Mike Koerber, MRPO): Yes, assumes 10% ammonia reductions from best 

practices. 

• Question (Jeff Crawford, Maine): How much of the ammonia comes from CAFOs versus 

fertilizer application? 

 - Answer (Mike Koerber, MRPO): Two-thirds to three-quarters comes from CAFOs, but 

 urban ammonia sources are also important. 

• Question (Tim Allen, F&W Service): How much benefit is there from ammonia controls? 

- Answer (Mike Koerber, MRPO): The analysis shows that a 10% ammonia decrease 

that may be cost-effective will result in greater than a 0.10dV improvement. 

• Comment (Bruce Polkowsky, NPS): 10% is a lot. 

• Comment (Larry Bruss, Wisconsin): There is a lot of uncertainty when it comes to the 

effects of ammonia reductions. 

• Question (Doug Austin, MANE-VU): Is the $/dV analysis based on three states or nine? 

- Answer (Mike Koerber, MRPO): It is based on three states, and a nine-state analysis 

would be higher 

• Comment (Gary Kleiman, NESCAUM): MANE-VU saw almost identical MRPO 

contributions in the 10-15% range. 

• Comment (Chris Salmi, New Jersey): New Jersey is looking at performance standards for 

the 24-hour PM2.5 standard and a potentially tighter ozone standard. 

• Comment (Laurel Kroack, Illinois): Illinois would be interested if New Jersey could share 

that information. 

EPA and FLM Perspectives on RPGs and Reasonable Measures Work – Bruce Polkowsky, 

NPS; Chuck Sams, Forest Service; John Summerhays, EPA Region V; Todd Hawes, EPA - 

OAQPS 

Bruce Polkowsky, National Park Service

• Tomorrow is the 30th anniversary of the passage of the 1977 Clean Air Act Amendments 

that enacted section 169A and established the regional haze program. 
August 6 2007 MANE-VU/MRPO Consultation Summary (DRAFT) 

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• The uniform progress line is “useful,” but the 4-Factor analses are most important from 

FLM perspective. 

• Don’t forget the 20% clean days reasonable progress goal (VISTAS getting 1 dv 

improvement). 

• Are states being overly optimistic in their CAIR controls scenarios? Information coming 

in from states seems to be pointing to predicting a higher level of controls than what 

CAIR predicts. 

• The location of controls is important for visibility as seen in the MANE-VU 167 stack 

analysis. 

• The 2013 progress report is key, and it is important to know about new sources, too. 

• PM 2.5, ozone and regional haze issues are all coming together in the 2013-2018 

timeframe. The PM2.5 SIPs should take into account what the regional haze measures 

will achieve. Strategies should be coordinated to maximize their effectiveness for both 

regional haze, PM2.5, and ozone SIPs. 

• The FLMs encourage states to be as detailed as possible in their regional haze SIPs, 

including dates, for control measure development. It is up to EPA through the approval 

and disapproval process as to how they will react to state promises to pursue control 

measures in the regional haze SIPs. 

Chuck Sams, Forest Service

• There should be one hard copy of the regional haze SIP per FLM reviewer. 

• The FLM goal is for comments back to the states 30 days before their public hearings. 

• The FLMs need need the SIPs as soon as possible for their 60-day review. 

• The FLMs would would appreciate a summary sheet that provides a cross-reference as to 

when the specific items on their checklist can be found in the SIP. 

• There is an FLM expectation for ongoing consultation. 

John Summerhays, EPA Region V

• There are three main requirements of the Regional Haze Rule: 

- (1) Reasonable Progress – lots of questions about what conclusions and questions 

about what EPA will have as a requirement to the different scenarios; 

- (2) BART – haven’t seen much control taken on BART. EPA is thinking about how 

to ensure consistency in BART determinations by different states. EPA asks the RPOs 

to try to insure consistency across their states; and 

- (3) Consultations - RPOs have done valuable work in technical analyses and 

facilitating consultations. 

• EPA appreciates being part of the current process and continuing that participation into 

the future. 

Todd Hawes, EPA – OAQPS

• While EPA is not in a position to initiate consultations as required by the Regional Haze 

Rule, today’s meeting is a good representation of what they envisioned the consultation 

process would be. 
August 6 2007 MANE-VU/MRPO Consultation Summary (DRAFT) 

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• EPA is getting lots of questions from states about the regional haze SIPs. Some states are 

saying they are not going to set reasonable progress goals, while some say they are only 

going to do BART, use it for their reasonable progress goal with no analysis. 

• EPA is legally bound and expecting full SIPs on 12/17/2007 that include all of the 

required elements. It is not acceptable for states to say they do not have the time or 

resources, or that the SIP cannot be done by December 17. 

• The EPA lawyers are working on “what if” scenarios. 

Discussion:

• Question to FLMs and EPA (Dick Valentinetti): Will the Federal agencies comment on 

the extent of agreement and disagreement on strategies? 

- Answer (Bruce Polkowsky, NPS): Yes, they will. 

• Comment (Tim Allen, F&W Service): They will also be looking for regional consistency 

and that the various emission reductions for meeting the Class I reasonable progress goals 

are proportional between the states. They may comment more on any disagreements 

between RPOs. 

• Comment (Bruce Polkowsky, NPS): The continuing consultation requirement is in 

308(i)(4). The MANE-VU states have provided input on format and frequency. The 

monitoring aspects are crucial and especially important to consult about. 

• Question to EPA (Bruce Polkowsky, NPS): The long-term strategy is a 10-year strategy 

from rule adoption, but are promises to look at reductions approvable? 

- Answer (Todd Hawes, EPA): Realistically, we have to see what comes in December. 

They realize that they will not get 100% approvable SIPS in December 2007 and will 

have to see then what they will do about it. 

• Comment (Bruce Polkowsky, NPS): FLMs would rather have a SIP later that has all 

elements rather than one that is on time that does not. 

• Question to EPA (Susan Wierman, MARAMA): Can EPA process the BART SIPs first to 

start BART clock? 

- Answer (Todd Hawes, EPA): Yes, they are discussing BART severability, and it 

would be easier to consider BART first if they get a complete SIP. 

• Comment (Susan Wierman, MARAMA): Holding up BART approvals due to 

incompleteness of the rest of SIP would be unfortunate. Glad to hear EPA discussing this 

issue. 

• Comment (Todd Hawes, EPA): They have 6 months to deem complete. 

• Question to MANE-VU (John Summerhays, EPA): How are BART compliance dates set 

in M-V? 

- Answer (Susan Wierman, MARAMA): Some states are setting the date to be “as 

expeditiously as practicable.” The states need to be doing their best to get BART 

controls in place as we do not want a repeat of the NOx SIP call delays. The BART 

requirement is one of the best ways in the Clean Air Act for getting old facilities 

controlled. 

• Question to MRPO (Todd Hawes, EPA): Can I get clarification on the $/dV metric 

developed by MRPO? Is there any cost-effectiveness breakpoint? 

- Answer (Mike Koerber, MRPO): It is a reference point. 

• Question to EPA (Chris Salmi, New Jersey): How will EPA react to inconsistencies 

between state SIPs? 
August 6 2007 MANE-VU/MRPO Consultation Summary (DRAFT) 

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- Answer (Todd Hawes, EPA): The rule says EPA is the arbiter of any disagreement and 

there is little guidance beyond that. EPA would lean heavily on consultation 

documentation, but EPA will ultimately have to decide. 

• Comment to EPA and FLMs (Chris Salmi, New Jersey): It is one of the MANE-VU 

Class I States principles that the FLMs will help identify and EPA will act upon any 

inconsistencies. 

Roundtable Discussion on Reasonable Progress Goals and Reasonable Measures

 States continued the consultation with a roundtable discussion open on all issues raised 

during the Open Technical Call and this consultation meeting. Most of the discussion focused on 

the substance of the MANE-VU statements, or “asks” from the MRPO states and from the U.S. 

EPA. 

ICI Boilers, MACT and NOx/SO2 RACT

 During the Open Technical Call it was suggested that there may be an opportunity to 

examine the scope of the ICI boiler sector and potential emission reductions from that source 

category. Several states brought up the recent vacatur of the Boiler MACT in terms of the 

possibility for states to work together on this sector. NACAA is discussing with its members and 

the Ozone Transport Commission and Northeast States for Coordinated Air Use Management an 

effort to develop a Boiler MACT model rule. While for Boiler MACT this effort would focus on 

hazardous air pollutants (HAPs), including volatile organic compounds (VOCs), it may be 

possible to include in that project a parallel process to gather information on NOx and SO2 

emissions from the boiler sector and develop options for control strategies, separate from the 

MACT levels. 

 MANE-VU states also inquired about what MRPO states are doing for PM 2.5 

attainment. Many of the MRPO states are focusing on local sources for urban excess, and it 

appears that EPA is discouraging a focus on regional strategies. Illinois informed the group that 

it has a multi-pollutant agreement including scrubbers. Illinois also has a statewide NOx RACT 

proposal with stringent levels and is working on SO2 RACT, such as low sulfur diesel for nonroad and refinery SO2 reductions. These RACT proposals are working their way through 

Illinois’ regulatory processes, so they are not yet included in SIPs and are not reflected in 

MRPO’s modeling. Michigan may also look at statewide RACT under the new PM2.5 standard. 

 In addition to the work done by the ICI boiler workgroup, OTC has completed some 

regional inventory work on its ICI boilers and NESCAUM is completing a study on ICI boilers 

that was sponsored by EPA. All of this work can be included in the review of this sector. 

Follow up items from this discussion include:

• Reconvene MANE-VU/MRPO ICI Workgroup that was initiated under the State 

Collaborative to re-examine ICI boiler work and define next steps; 

• Contact NACAA about possible addition to Boiler MACT model rule work to examine 

potential for NOx and SO2 reductions and identify strategies; and 
August 6 2007 MANE-VU/MRPO Consultation Summary (DRAFT) 

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• Look at pursuing SO2 RACT regionally, as well as asking EPA again for an ICI national 

rule. 

Low Sulfur Fuels 

In addition to the low sulfur fuel measures that MANE-VU is pursuing, the states 

discussed other areas of opportunity for low-sulfur fuels, including nonroad low-sulfur diesel. 

Illinois indicated that they will be talking to their four refineries about non-road low-sulfur diesel 

Michigan indicated that they are looking at a possible executive order mandating low-sulfur nonroad diesel for state contracts. MRPO states also expressed interest in low-sulfur fuel for 

locomotives. 

 New Hampshire inquired as to whether the cost for biodiesel is similar to low-sulfur 

diesel, and suggested that we share information on biodiesel as an option. New Jersey expressed 

interest in ocean-going vessels as a source sector for low-sulfur fuel opportunities. The National 

Park Service folks indicated that there is a recent World Trade Organization agreement that 

could be of use in this regard, and that this is a sector that the VISTAS and WRAP states are also 

looking into. 

Follow up items from this discussion include:

• Look at federal rules that are in the works for non-road, locomotive and marine engines 

to see if there are gaps or opportunities that MANE-VU and MRPO could explore 

together; and 

• Share information on biodiesel as a low-sulfur fuel option. 

State/Regional EGU Strategy 

 States discussed the EGU strategy proposed by the MANE-VU Class I areas, regarding a 

focus to pursue reductions of 90% or greater from the 167 stacks identified on the MANE-VU 

list. The MANE-VU states have agreed to pursue 90% EGU reductions and a low-sulfur fuel oil 

strategy. MRPO states will continue to examine what the potential for reductions are at these 

units, and provide information about which sources in their states are putting controls on, to 

better inform the process and our modeling. According to the information MRPO has at this 

time, over 70% of the emissions from the 167 stacks on the list will be scrubbed. The question 

remains whether that will be enough, or whether MRPO will still need to address the remaining 

30% even if it has a very low impact. Another issue was raised regarding whether it would be 

acceptable for MRPO states to substitute reductions from the non-EGU sector that go beyond the 

28% level for reductions that may not be obtainable in the EGU sector. MANE-VU states 

indicated that this would likely be acceptable, depending on the location and type of non-EGU 

source. 

 MANE-VU states raised the question as to whether the 70/30 split is the same for the rest 

of the EGUs, i.e. those in the MRPO region that are not part of the 167 stacks on the list. MRPO 

responded that they can get that information and provide it to MANE-VU. For example, IPM 

indicates that Rockport will be getting controls, while MRPO’s information from the source is 
August 6 2007 MANE-VU/MRPO Consultation Summary (DRAFT) 

Page 10 of 11 

that they will not. There is also a concern that cumulatively, the controls that the EGU sources 

say are going on will be larger than what is required by CAIR, i.e., it will not reflect reductions 

that will be “sold” on the trading market, or what units they will be sold to, to keep emissions at 

the CAIR budget level. 

 Another concern was raised regarding the addition of controls to older EGUs and how 

they can be permitted given NSR issues for increases in other emissions. Some states responded 

that it has been possible to add scrubbers to older units and address increases in other emissions 

by fine-tuning the control systems. 

 Generally, while the concept is feasible, MRPO states anticipate needing more assistance 

and information from the MANE-VU Class I areas to understand the justification for controls on 

these units. In addition, it will be helpful to look at ways to incentivize the retirement/closing of 

old units and their replacement with cleaner technology, such as through output-based standards. 

We will also need to work together to craft language that will work in our SIPs to reflect the 

approach that MANE-VU is requesting that will be acceptable to EPA. 

Follow up items from this discussion include:

• Continue to share specific information about what MANE-VU and MRPO sources are 

anticipating as controls on EGUs as compared to what is indicated in IPM modeling; 

• Update our inventories and databases accordingly so that our information is “synched”; 

and 

• Continue dialogue on approaches for addressing this sector to meet the 90% reduction 

target for the 167 stacks and on equivalent alternatives. 

National “Ask” for CAIR Phase III 

 There is interest from some MRPO states in joining MANE-VU in its “ask” for a Phase 

III of CAIR. All of the MRPO states will review and consider the option as we continue our 

consultation process. For many MRPO states the real concern is obtaining PM 2.5 reductions; 

regional haze is not their primary concern. As we continue to discuss the national “ask” we need 

to develop control levels that will help all of our states with attainment for ozone, PM and 

regional haze. MANE-VU based its request on the recent IPM modeling work done on the levels 

that came out of the state collaborative work. Those levels are not as stringent as those that are in 

the original OTC multi-pollutant position, and we are iin the process of reviewing them. 

Follow up items from this discussion include:

• MANE-VU to revisit its multi-pollutant strategy; 

• MRPO and MANE-VU to have discussions on potential multi-pollutant control levels for 

a CAIR Phase III; and 

• Craft a revised national “ask” to reflect revised levels, as appropriate. 

NEXT STEPS 

In addition to the agreements reached during the discussions (listed at the beginning and 

in the roundtable discussion sections of this document) the MANE-VU Class I states and the 
August 6 2007 MANE-VU/MRPO Consultation Summary (DRAFT) 

Page 11 of 11 

MRPO states agreed to continue the consultation dialogue on the upcoming State Collaborative 

call, scheduled for 10:00 am CDT, 11:00 am EDT on Thursday, August 16th. The states will 

continue discussions from today’s meeting, bring forth additional issues as necessary, and have a 

first opportunity to review and discuss the draft documentation of the consultation. 
State of Ohio Environmental Protection Agency

STREET ADDRESS: MAILING ADDRESS:

Lazarus Government Center

50 W. Town St., Suite 700

Columbus, Ohio 43215

October 3, 2007

Anna Garcia

Acting Executive Director

OLD-oe Transp-ort Commission

Hall of the States

444 North Capitol Street, Suite 638

Washington, DC 20001

Dear Ms. Garcia:

TELE: (614) 644-3020 FAX: (614) 644-3184

www.epa.state.oh.us

P.O. Box 1049

Columbus,OH 43216-1049

The purpose of this letter is to respond to your letter dated July 30, 2007, letter and the

MANE-VU States' initial request for a course of action by states outside of the MANE-VU

region toward assuming reasonable progress at your Class I areas (Le., the MANE-VU "ask").

I would like to first express my thanks to the MANE-VU States and their representatives for

traveling to Chicago on August 6 for the initial consultation meeting. This was a productive

meeting and sets the stage for further constructive dialogue.

At the August 6 meeting, the following action items were identified:

1. Define next steps for multi-pollutant approach to reduce regional haze, PM 2.5, and

ozone.

2. Discuss crafting a national "ask" among interested MANE-VU and MRPO states

regarding national action on EGUs, including potential multi-pollutant control levels

for a possible CAIR Phase III with emission rates and output-based options.

3. Pursue discussions on options for reducing S02 (and' NOx) emissions from ICI

boilers, including:

• Reconvening the MANE-VU/MRPO ICI boiler workgroup to re-examine the

workgroup's January 2007 straw proposal;

• Developing a process for sharing information on S02 RACT for ICI boilers, and

examining potential S02 control measures;

• Contacting NACAA regarding expansion of the Boiler MACT model rule work to

address S02 and NOx; and

• Discuss crafting a revised national "ask" among interested MANE-VU and

MRPO states regarding needs for national action on ICI boilers.

" Printed on Recycled Paper

Ted Strickland, Governor

Lee Fisher, Lieutenant Governor

Chris Korleski, Director

Ohio EPA is an Equal Opportunity Employer ®~47
Ms. Anna Garcia

Page 2

4. Discuss crafting a national "ask" regarding low sulfur fuel for all off-road sources,

and share information on biodiesel.

5. Gather information on pending federal controls for locomotives and commercial

marine vessels.

6. Continue to share emissions data and modeling analyses, and continue dialogue

between MANE-VU and MRPO states regarding SIP submittals. (Note, clarification

of the MANE-VU "ask" is still needed.)

7. Develop' list· of controls for units that will be scrubbed,not just MANE-VU's list of

167 stacks.

The above elements provide a significant starting point for our consultation activities. In

addition, I suggest the following actions be initiated in order to move the process forward:

• Establish a clear understanding of the MANE-VU "ask" by agreeing on base

emissions inventories and control assumptions;

• Draft language on a national "ask" based on the multi-pollutant needs of the

states, including potential controls for EGUs and ICI boilers; and

• Reconvene the MANE-VU/MRPO ICI boiler workgroup (with participation by the

Southeastern States and USEPA) to re-examine and refine the workgroup's

January 2007 straw proposal.

It appears that, based on our review of the Round 5 Midwest RPO modeling for 2018 and

U.S. EPA modeling for 2015, reasonable further progress is essentially meeting or exceeding

reasonable further progress interim goals in each of the MANE-VU Class I areas. Is this not

correct? It is apparent that significant regional emission reduction programs are achieving

health and interim visibility goals across the majority of the eastern United States. With the

current goals achieved, the focus should be on the development of the next tier of costeffective controls, looking at the need for reduct.ions to achieve the revised ambient air quality

standards and considering a future regional haze interim milestone date (e.g., 2005). CAIR

phase 3, ICI controls and regional programs for fuels, etc. should be the focus for making

continued progress towards the 2064 ultimate regional haze goals.
Ms. Anna Garcia

Page 3

Finally, I believe it is premature to. respond to the MANE-VU "ask" for additional reductions in

S02 emissions from EGU and non-EGU sources. The work and discussion noted above are

needed before an accurate estimate of future air quality in MANE-VU can be completed.

While I am unable to commit to any particular course of action at this time, I am looking

forward to further discussions which consider our mutual air quality interests.

Sincerely,

.Robert Hodanbosi, Chief

Division of Air Pollution Control
September 2, 2009

The Honorable Lisa P. Jackson, Administrator

U.S. Environmental Protection Agency

Ariel Rios Building

1200 Pennsylvania Avenue, NW

Mail Code 11 01A

Washington, DC 20460

Dear Administrator Jackson:

On behalf of 17 states in the eastern half of the U.S., we wish to provide the following

recommendations to the Environmental Protection Agency (EPA) to consider as it

develops a replacement rule for the Clean Air Interstate Rule (CAIR), in light of the

December 23,2008, remand by the U.S. Court of Appeals for the D.C. Circuit.

The recommendations follow through on the commitment we made in the March 9, 2009,

Framework Document to work together to address the transport requirements of Section

110(a)(2)(D) of the Clean Air Act (CAA), and to attain the ozone and PM2.5 National

Ambient Air Quality Standards (NAAQS). Please understand that in preparing these

recommendations our fundamental air quality objective is to achieve attainment and

ensure maintenance of the NAAQS as expeditiously as practicable.

As the result of our collaboration, we recommend for your consideration a framework,

which is based on in-depth technical evaluations and a sincere and concerted effort by

all states to reach common ground on an overall approach to addressing transport. This

comprehensive framework comprises national rules involving significantly contributing

states that combine statewide emissions caps and complementary regional trading

programs with a state-led planning process to address transport in a multi-pronged and

layered approach. While the undersigned states have reached consensus on this

suggested framework, there are some regional differences concerning the timing and

stringency of electric generating unit (EGU) reductions, and the criteria for determining

which states are included in the state-led plarming process. In addition, the states differ

in their perspectives on whether performance based standards should be part of the

strategy.

The Lake Michigan Air Directors Consortium (LADCO) and the Ozone Transport

Commission (OTC) will be submitting separate letters to explain their perspectives on

these areas of regional differences on implementation of the framework.

Many areas in the eastern U.S. are designated as nonattainment for the current ozone

and PM2.5 standards (1997 version), and it is expected that even more areas will not be

in compliance with 2008 ozone and 2006 PM2.5 standards. Numerous data analysis and

modeling studies have shown that some (not all) of these nonattainment problems are

strongly influenced by inter-state transport.

Additional regional emission reductions will be necessary to help states meet the new air

quality standards. A timely and robust federal program that requires substantial regional

emission reductions from mobile sources, area sources and large point sources such as
EGUs is an essential component of any strategy to reduce interstate transport of air

pollution. These reductions are necessary to attain and maintain compliance with the

NAAQS.

The undersigned states recommend a 3-step approach, as further discussed below, to

establish a framework from which to address the requirements of CAA section

110(a)(2)(D):

1, Identifying areas of interest (i.e., those not meeting the standards and those

struggling to maintain the standards);

2, Identifying, based on specific criteria, upwind states which contribute to

nonattainment or interfere with maintenance in these areas of interest; and

3, Implementing a multi-sector remedy to meet CAA requirements.

Step 1 - Identifying Areas of Interest

A. While the requirements of Section 11 0(a)(2)(D) apply to all areas, most attention

should be given to those areas not meeting or struggling to maintain the NAAQS.

These "areas of interest" should be identified using monitoring and modeling

data.

B. Specifically, areas with both base monitored design values and future modeled

design values above the applicable NAAQS should be designated as areas of

interest. The monitored design values are based on the maximum design value

from the periods 2003-2005 through the most recent three-year period, and the

future modeled values are based on future year modeling which reflects legally

enforceable control measures and a conservative model attainment test - i.e.,

use of maximum design values rather than average design values.

1. The use of maximum design values and a conservative model attainment test

are intended to account for historic variability, which is necessary to ensure

maintenance. An alternative means of accounting for historic variability is to

conduct a statistical analysis of the year-to-year variation in meteorology.

2. Requiring a more conservative model attainment test will necessitate a

change in EPA's modeling guidance. EPA should also establish performance

criteria to insure that the modeling is capturing transport appropriately.

3. EPA's approach in CAIR also reflects a "monitored and modeled" test to

identify areas of interest.

Step 2 - Identifying Upwind States that Significantly Contribute to Nonattainment

or Interfere with Maintenance

A. An upwind state significantly contributes to nonattainment or interferes with

maintenance in a downwind area of interest if its total impact from all source

sectors equals or exceeds 1% of the applicable NAAQS.

Page 2 of6
B. Individual state contributions should be determined through a weight-of-evidence

approach, including source apportionment modeling.

C. Use of 1% of the NAAQS as the significance threshold is consistent with EPA's

approach in CAIR.

Step 3 - Implementing a Multi-Sector Remedy to Meet Clean Air Act Requirements

A two-part process is recommended consisting of: (A) a national/regional control

program adopted by EPA for EGUs and additional federal control measures for

other sectors, and (B) state-led efforts to develop, adopt, and implement federally

enforceable plans for each area of interest that is not expected to attain the

standards even after implementation of the national/regional program.

A. National/Regional Control Program

A significantly contributing state (i.e., a state which contributes at least 1% to a

downwind area of interest) must comply with the national/regional control

program described below.

1. EGU point source strategy (applicable to units.':: 25 MW)

In adopting a CAIR replacement rule EPA should:

(a) make federally enforceable through appropriate mechanisms all

nitrogen oxide (NOx) and sulfur dioxide (S02) controls to comply

with the original CAIR Phase I program;

(b) make federally enforceable through appropriate mechanisms

optimization by no later than early 2014 of existing NOx and S02

controls;

(c) make federally enforceable through appropriate mechanisms

application by 2015 of low capital cost NOx controls;

(d) establish statewide emission caps by no later than 2017 for all

fossil fuel-fired units ~25MW. The caps should reflect an analysis

of NOx and S02 controls on coal-fired units 100 MW which, in

combination with the three measures above, will achieve rates

that are not expected to exceed 0.25 Ib/MMBTU for S02 (annual

average for all units ;,25 MW) and 0.11 Ib/MMBTU for NOx (ozone

seasonal and annual average for all units ~25 MW) and which will

result in lower rates in some states. Previously banked emissions

under the Title IV or CAIR programs shall not be used to comply

with the state-wide emission caps; and

(e) to the fullest extent allowed under the Clean Air Act, EPA should

work with the states to establish regional emissions caps with full

emissions trading to replace the caps currently applicable under

CAIR.

Page 3 of 6
Again, there are regional differences on some elements of the EGU point

source strategy, including mechanisms for achieving reductions prior to

2017. Further recommendations will be provided in separate letters by

LADCO and OTC.

2. Non-EGU point source strategy

a. EPA should identify and prioritize other categories of point

sources with major emissions of NOx and/or S02 (e.g., cement

plants) based on a review of available emissions inventories and

other information, such as source apportionment studies.

b. For the non-EGU point sources, EPA should identify and evaluate

control options for reducing NOx and/or S02 emissions. The

evaluation should consider the technological, engineering, and

economic feasibility of each control option.

c. At a minimum, EPA should evaluate the technological,

engineering, and implementation feasibility, and cost-effectiveness

of controlling S02 and NOx emissions from industrial, commercial,

and institutional boilers 100 MMBTU/hour.

3. Mobile source strategy, such as new engine standards for on-highway

and off-highway vehicles and equipment, and a single consistent

environmentally-sensitive formulated fuel.

4. Area source strategy, such as new federal standards for consumer

products and architectural, industrial and maintenance coatings as

originally promised by EPA in 2007

B. State- Led Attainment Planning

The undersigned states recommend the use of a state-led attainment planning

process concurrent with developing the transport SIP to address areas of interest

that are not expected to attain after implementation of the national/regional

control program. The state-led planning effort should involve a key subset of

significantly contributing states to develop, adopt, and implement an appropriate

attainment strategy. EPA should work with the states to establish criteria for

determining which significantly contributing states should be involved in the stateled planning process. Additionally EPA should work with the states to determine

the appropriate criteria for each state to satisfy CM section 11 0(a)(2)(D). The

advantages of this state-led planning effort include:

• A one-size-fits-all federal solution cannot provide the most appropriate

and cost-effective solution for each area;

• Attainment planning is more effective and more likely to succeed if it is

done on a non-attainment area basis with a key subset of contributing

states;

• Additional controls are identified where they are needed; and

• States maintain their responsibility under the Clean Air Act to establish

state implementation plans.

Page 4 of 6
Further recommendations on this issue will be provided in separate letters by

LADCO and OTC. .

The comprehensive framework outlined above represents the culmination of our

collaborative work over the past six months. look forward to working with you further

as EPA develops its CAIR replacement rule.

Sincerely,

A ....~-- con~

Maine

~~J:?S- Massachusetts

,,:7~~4;;;s.~

New Hampshire

Page

tllMtd~ New Jersey

a/~l Ohio

W)!J~~ Rhode Island
~~2<_ Wisconsin

Page 6 of6


ii

Scope of Document

This document provides an initial analysis of the five factors which must be

considered in establishing a reasonable progress goal toward achieving natural

visibility conditions in mandatory Class I areas. These factors were examined

both for existing (“on the books”) control programs and several candidate control

measures for priority pollutants and emission sources. The results of this report

are intended to inform policymakers in setting reasonable progress goals for the

four northern Class I areas in Minnesota and Michigan, pursuant to the

requirements of the Regional Haze Rule. A number of entities have participated

in the design and review of this study, including air pollution control agencies in

Michigan, Wisconsin, Minnesota, and other states, as well as by the National Park

Service, the U.S. Forest Service, Tribes, the Midwest Regional Planning

Organization (MRPO), and other Regional Planning Organizations.

This document does not address policy issues, set reasonable progress goals, or

recommend a long-term strategy for regional haze. The States of Minnesota and

Michigan will establish reasonable progress goals and develop a long-term

strategy in consultation with other states. Separate documents will be prepared by

the States which address the reasonable progress goals, each state's share of

emission reductions, and coordinated emission control strategies. These

documents will be based on the information contained in this and other technical

reports (e.g., “Regional Haze in the Upper Midwest: Summary of Technical

Information,” January 9, 2007). 

Disclaimer

The analysis described in this document has been funded by the Lake Michigan

Air Directors Consortium and the Minnesota Pollution Control Agency. It has

been subject to review by these organizations and other organizations listed

above. However, the report does not necessarily reflect the views of the

sponsoring and participating organizations, and no official endorsement should be

inferred.
iii

Contents

1. Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

2. Background . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3

3. Methodology . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8

3.1 Factor 1 – Costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9

3.2 Factor 2 – Time Necessary for Compliance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10

3.3 Factor 3 – Energy and Other Impacts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10

3.4 Factor 4 – Remaining Equipment Life . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11

3.5 Factor 5 – Visibility Impacts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12

4. Analysis of Existing Control Measures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15

4.1 Factor 1 – Costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15

4.2 Factor 2 – Time Necessary for Compliance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17

4.3 Factor 3 – Energy and Other Impacts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19

4.4 Factor 4 – Remaining Equipment Life . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19

4.5 Factor 5 – Visibility Impacts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19

5. Analysis of Potential Additional Control Measures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22

5.1.1 Factor 1 – Costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26

5.1.2 Factor 2 – Time Required for Compliance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30

5.1.3 Factor 3 – Energy and Other Impacts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31

5.1.4 Factor 4 – Remaining Equipment Life . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35

5.1.5 Factor 5 – Visibility Impacts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35

5.2 Industrial, Commercial, and Institutional Boilers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39

5.2.1 Factor 1 – Costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44

5.2.2 Factor 2 – Time Necessary for Compliance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 48

5.2.3 Factor 3 – Energy and Other Impacts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 48

5.2.4 Factor 4 – Remaining Equipment Life . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 48

5.2.5 Factor 5 – Visibility Impacts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 51

5.3 Reciprocating Engines and Turbines . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 53

5.3.1 Factor 1 – Costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 56

5.3.2 Factor 2 – Time Necessary for Compliance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 56

5.3.3 Factor 3 – Energy and Other Impacts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 56

5.3.4 Factor 4 – Remaining Equipment Life . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 58

5.3.5 Factor 5 – Visibility Impacts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 58

5.4 Ammonia Emissions from Agricultural Sources . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 61

5.4.1 Factor 1 – Costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 62

5.4.2 Factor 2 – Time Necessary for Compliance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 64

5.4.3 Factor 3 – Energy and Other Impacts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 64

5.4.4 Factor 4 – Remaining Equipment Life . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 66

5.4.5 Factor 5 – Visibility Impacts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 66
Contents (Continued)

iv

5.5 Mobile Sources . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 68

5.5.1 Factor 1 – Costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 69

5.5.2 Factor 2 – Time Necessary for Compliance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 72

5.5.3 Factor 3 – Energy and Other Impacts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 72

5.5.4 Factor 4 – Remaining Equipment Life . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 72

5.5.5 Factor 5 – Visibility Impacts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 73

5.5.6 Biofuels . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 73

5.6 Miscellaneous Facility Analyses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 77

5.6.1 Cement Plants . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 77

5.6.1.1 Factor 1 - Costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 78

5.6.1.2 Factor 2 - Time Necessary for Compliance . . . . . . . . . . . . . . . . . . . . . . . . . 79

5.6.1.3 Factor 3 - Energy and Other Impacts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 79

5.6.1.4 Factor 4 - Remaining Equipment Life . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 80

5.6.1.5 Factor 5 - Visibility Impacts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 80

5.6.2 Glass manufacturing plant . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 82

5.6.2.1 Factor 1 - Costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 82

5.6.2.2 Factor 2 - Time Necessary for Compliance . . . . . . . . . . . . . . . . . . . . . . . . . 82

5.6.2.3 Factor 3 - Energy and Other Impacts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 83

5.6.2.4 Factor 4 - Remaining Equipment Life . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 83

5.6.2.5 Factor 5 - Visibility Impacts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 84

5.6.3. Lime Manufacturing Plants . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 86

5.6.3.1 Factor 1 - Costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 86

5.6.3.2 Factor 2 - Time Necessary for Compliance . . . . . . . . . . . . . . . . . . . . . . . . . 88

5.6.2.3 Factor 3 - Energy and Other Impacts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 88

5.6.3.4 Factor 4 - Remaining Equipment Life . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 88

5.6.3.5 Factor 5 - Visibility Impacts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 89

5.6.4. Oil Refinery . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 91

5.6.3.1 Factor 1 - Costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 91

5.6.3.2 Factor 2 - Time Necessary for Compliance . . . . . . . . . . . . . . . . . . . . . . . . . 92

5.6.2.3 Factor 3 - Energy and Other Impacts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 92

5.6.3.4 Factor 4 - Remaining Equipment Life . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 93

5.6.3.5 Factor 5 - Visibility Impacts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 93

6. Summary and Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 95

6.2 Factor 2 – Time Necessary for Compliance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 102

6.3 Factor 3 – Energy and Other Impacts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 102

6.4 Factor 4 – Remaining Equipment Life . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 106

6.5 Factor 5 – Visibility Impacts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 106

7. References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 112
v

Contents (Continued)

Appendix A. On-the-Books Factor Analyses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-1

Appendix B. Potential SO and NO Regional Control Strategies and Unit-level Control 2 X

 Technologies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . B-1

Appendix C. EGU Control Analysis Parameters and Individual EGU and ICI Boiler Facility

 Analyses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . C-1

Figures

Figure 1. Northern-Midwest Class I Areas. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

Figure 2-1. Composite Back Trajectories for Light Extinction on the 20% Worst Days. . . . . . . 3

Figure 2-2. Results of 2018 PSAT modeling for Boundary Waters Canoe Area. . . . . . . . . . . . . 4

Figure 2-3. Summary of SO , NO , and NH emissions in Michigan, Minnesota, and Wisconsin.4 2X 3

Figure 2-4. Summary of SO , NO , and NH emissions in Michigan, Minnesota, Wisconsin, 2X 3

Illinois, Indiana, Iowa, Missouri, North Dakota, and South Dakota. . . . . . . . . . . . . . . . . . 6

Figure 3-1. Geographic regions for the factor analysis. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8

Figure 4-1. Estimated visibility impacts of on-the-books controls in comparison with reasonable

progress goals for the northern-Midwest Class I areas . . . . . . . . . . . . . . . . . . . . . . . . . . 21

Figure 5.2-1. Projected Emissions from ICI Boilers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41

Figure 5.2-2 Fraction of Medium and Large Emissions by Fuel Type . . . . . . . . . . . . . . . . . . . . 42

Figure 6-1. Geographic regions for the factor analysis. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 95

Figure 6-2. Estimated visibility impacts of on-the-books controls in comparison with reasonable

progress goals for the northern-Midwest Class I areas . . . . . . . . . . . . . . . . . . . . . . . . . . 97

Figure 6.5-1. Estimated overall visibility impacts of control strategies in comparison with

reasonable progress goals for the northern-Midwest Class I areas. . . . . . . . . . . . . . . . . 111
vi

Tables

Table 2-1. Regional Emissions Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5

Table 2-2. CAMx Model Sensitivity Analysis of the Impacts of SO , NO , and NH Emission 2X 3

Reductions on Visibility . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7

Table 3.3-1 Summary of Energy and Environmental Impacts Evaluated Under Factor 3 . . . . . . 11

Table 3.5-1. Sensitivity Factors Used in Calculating Extinction Changes . . . . . . . . . . . . . . . . . 13

Table 4-1. On-the-Books Control Measures Included in the Factor Analysis . . . . . . . . . . . . . . 15

Table 4-2. Summary of Five-Factor Analysis of On-The-Books Controls . . . . . . . . . . . . . . . . . 16

Table 4.1-1. Non-EGU Facilities Subject to BART in the 9-State Region . . . . . . . . . . . . . . . . 18

Table 4.5-1. Comparison of Overall Visibility Goals in 2018 with Projected Impacts for On-theBooks Controls . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20

Table 5-1. Individual Sources Selected for Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23

Table 5.1-1. Estimated Allowable Emissions Under the EGU1 and EGU2 Control Strategies

..................................................................... 25

Table 5.1-2. Estimated Baseline Emissions from EGUs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25

Table 5.1-3. Estimated Costs of EGU1 SO Controls for the 3-State and 9-State Regions . . . . 2 28

Table 5.1-4. Estimated Costs of EGU1 NO Controls for the 3-State and 9-State Regions . . . X 28

Table 5.1-5. Estimated Costs of EGU2 SO Controls for the 3-State and 9-State Regions . . . . 2 29

Table 5.1-6. Estimated Costs of EGU2 NO Controls for the 3-State and 9-State Regions . . . X 29

Table 5.1-7. Factors Used to Calculate Energy and Non-Air Environmental Impacts of EGU

Control Measures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32

Table 5.1-8. Estimated Energy and Non-Air Environmental Impacts of EGU Control Strategies

..................................................................... 33

Table 5.1-9. Estimated Annual Health Benefits of EGU Control Strategies Applied to the 5-State

MRPO Region . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34

Table 5.1-10. Estimated Visibility Impacts of EGU Control Strategies . . . . . . . . . . . . . . . . . . . 37

Table 5.1-11. Cost Effectiveness of EGU Control Strategies in Terms of Visibility Improvement

..................................................................... 38

Table 5.2-1. Estimated SO2 Emissions from ICI Boilers in Relation to Total Non-EGU

Emissions in 2018 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40

Table 5.2-2. Estimated NOX Emissions from ICI Boilers in Relation to Total Non-EGU

Emissions in 2018 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40

Table 5.2-3. ICI Workgroup Proposed Emission Caps . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43

Table 5.2-4. Average Growth Factors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43

Table 5.2-5. Estimated Costs of ICI1 SO2 Controls for the 3-State and 9-State Regions . . . . . 46

Table 5.2-6. Estimated Costs of ICI1 NOX Controls for the 3-State and 9-State Regions . . . . 46

Table 5.2-7. Estimated Costs of ICI Workgroup SO2 Controls for the 3-State and 9-State

Regions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47

Table 5.2-8. Estimated Costs of ICI Workgroup NOX Controls for the 3-State and 9-State

Regions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47

Table 5.2-9. Factors Used to Calculate Energy and Non-Air Environmental Impacts of ICI

Control Measures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49
Tables (continued)

vii

Table 5.2-10. Estimated Energy and Non-Air Environmental Impacts of ICI Control Strategies

..................................................................... 50

Table 5.2-11. Estimated Visibility Impacts of ICI Control Strategies . . . . . . . . . . . . . . . . . . . . 52

Table 5.2-12. Cost Effectiveness of ICI Control Strategies in Terms of Visibility Improvement

..................................................................... 52

Table 5.3-1. Estimated Emissions from Reciprocating Engines and Turbines in Relation to Total

Non-EGU Emissions in 2018 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 54

Table 5.3-2. Potential Emission Reductions for Candidate Internal Combustion Control

Measures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 55

Table 5.3-3. Estimated Cost Effectiveness of Controls for Internal Combustion Sources . . . . . 57

Table 5.3-4. Estimated Visibility Improvements from Internal Combustion Control Measures

..................................................................... 59

Table 5.3-5. Cost Effectiveness of Internal Combustion Control Strategies in Terms of Visibility

Improvement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 60

Table 5.4-1. Estimated Cost Effectiveness of Control Measures for Agricultural Ammonia

Emissions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 63

Table 5.4-2. Estimated Energy and Non-Air Environmental Impacts of Agricultural Ammonia

Emission Control Measures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 65

Table 5.4-3. Estimated Visibility Impacts of Agricultural Ammonia Emission Control Measures

..................................................................... 67

Table 5.4-4. Cost Effectiveness of Agricultural Ammonia Emission Control Measures in Terms

of Visibility Improvement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 67

Table 5.5-1. Estimated Cost Effectiveness and Emission Reduction Potential of Mobile Source

Controls for the 3-State and 9-State Regions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 71

Table 5.5-2. Estimated Energy and Non-Air Environmental Impacts of Mobile Source Control

Strategies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 74

Table 5.5-3. Estimated Visibility Impacts of Mobile Sources Control Strategies . . . . . . . . . . . 75

Table 5.5-4. Cost Effectiveness of Mobile Source Control Strategies in Terms of Visibility

Improvement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 76

Table 5.6-1. Control Technologies Available to Long Wet Kilns . . . . . . . . . . . . . . . . . . . . . . . 78

Table 5.6-2. Cost Effectiveness of NO and SO Control Technologies for Holcim, Inc. Facility X 2

..................................................................... 79

Table 5.6-3. Estimated Visibility Impacts of Control Strategies for Holcim Cement Kilns . . . 81

Table 5.6-4. NO Control Technologies Available for Melting Furnaces at the Cardinal FG X

Facility . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 82

Table 5.6-5. Costs and Cost Effectiveness for NO Control Technologies Available to Cardinal X

FG Facility . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 83

Table 5.6-6. Estimated Energy and Non-Air Environmental Impacts of Control Strategies at

Cardinal FG Glass Manufacturing Facility . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 83

Table 5.6-7. Estimated Visibility Impacts of Control Strategies for Cardinal FG Glass Furnaces

..................................................................... 85

Table 5.6-8. Control Technologies Available for Lime Manufacturing Plants . . . . . . . . . . . . . 86
Tables (continued)

viii

Table 5.6-9. Costs and Cost Effectiveness for NOx and SO2 Control Technologies at Rockwell

and CLM Corporation Lime Manufacturing Facilities . . . . . . . . . . . . . . . . . . . . . . . . . . 87

Table 5.6-10. Estimated Energy and Non-Air Environmental Impacts of Control Strategies at

Rockwell and CLM Corporation Lime Manufacturing Facilities . . . . . . . . . . . . . . . . . . 88

Table 5.6-11. Estimated Visibility Impacts of Control Strategies for Rockwell and CLM

Corporation Lime Kilns . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 90

Table 5.6-12. Control Technologies Available for the Murphy Oil Refinery . . . . . . . . . . . . . . . 91

Table 5.6-13. Cost Effectiveness of NO Control Technologies at Model Oil Refinery . . . . . . X 92

Table 5.6-14. Cost Effectiveness for SO2 Control Technologies for Murphy Oil Refinery

Facility . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 92

Table 5.6-15. Estimated Energy and Non-Air Environmental Impacts of Control Strategies at

Murphy Oil Refinery Facility . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 93

Table 5.6-16. Estimated Visibility Impacts of Control Strategies for Murphy Oil Refineries . . 94

Table 6-1. Summary of Candidate Future Control Measures Evaluated for Regional Haze . . . 98

Table 6.1-1. Estimated Cost Effectiveness for Potential Control Measures in Terms of Emission

Reductions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 100

Table 6.1-2. Estimated Cost-effectiveness of On-the-Books Programs . . . . . . . . . . . . . . . . . . 101

Table 6.2-1. Estimated Time Required for Compliance with Potential Control Measures . . . 103

Table 6-3.1. Estimated Energy and Non-Air Environmental Impacts of Potential Control

Measures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 104

Table 6.5-1. Comparison of Visibility Goals in 2018 with Projected Impacts for On-the-Books

Controls . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 107

Table 6.5-2. Estimated Visibility Impacts of Potential Control Strategies . . . . . . . . . . . . . . . . 109

Table 6.5-3. Summary of Visibility Impacts and Cost Effectiveness of Potential Control

Measures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 110
ACT Alternative Control Techniques

ALAPCO Association of Local Air Pollution Control Officials

ANPRM Advance Notices of Proposed Rulemaking

APU Auxiliary Power Unit

ASOA Anthropogenic Seconday Organic Aerosol

B20 Biodiesel in a 20% blend with petroleum diesel

B40 Biodiesel in a 40% blend with petroleum diesel

BACT Best Achievable Control Technology

BART Best Available Retrofit Technology

BenMAP Benefits Mapping and Analysis Program

BMP Best Management Practice

BSOA Biogenic Secondary Organic Aerosol

CAIR Clean Air Interstate Rule

CAMx Comprehensive Air Modeling with extensions

CARB California Air Resources Board

CUECost Coal Utility Environmental Cost

E10 Ethanol in a 10% bled with petroleum diesel

EC Elemental Carbon (particulate)

EGU Electric Generating Unit

EGU1 Possible cap for NOX and SO2 for midwest region; NOx limited to 0.10 lb/mmBtu of fossil fuel 

consumption, SO2 limited to 0.15 lb/mmBtu of fossil fuel consumption

EGU2 Possible cap for NOX and SO2 for midwest region; NOx limited to 0.07 lb/mmBtu of fossil fuel 

consumption, SO2 limited to 0.10 lb/mmBtu of fossil fuel consumption

EIA Energy Information Administration

ENVIRON 

Report Evaluation of Candidate Mobile Source Control Measures for LADCO States in 2009 and 2012

FCCU Fluid Catalytic Cracking Unit

FPRM Federal Particulate Reference Method

GR Gas Reburn

HAP Hazardous Air Pollutants

HDDV Heavy-Duty Diesel Vehicles

ICAC Institute of Clean Air Companies

ICI Industrial, Commercial, and Institutional

ICI 

Workgroup 

Strategy

Strategy to control SO2 and NOX regional emissions; specific limitations are a function of boiler type 

and size, and fuel type; overall requires approximately a 77% reduction in SO2 emissions and a 70% 

reduction in NOx emissions

ICI1 Strategy to control SO2 and NOX regional emissions; requires a 40% reduction in SO2 emissions and a 

60% reduction in NOx emissions, from the 2018 baseline emissions

IL Illinois

IN Indiana

IPM Integrated Planning Model

kW Kilowatt

LADCO Lake Michigan Air Directors Consortium

LEC Low-Emission Combustion

LNB Low NOx burners

LRAPA Lane Regional Air Protection Agency

LSD Lime Spray Dryer (scrubber)

LSFO Limestone Forced Oxidation (scrubber)

MACT Maximum Available Control Technology

MCDI Midwest Clean Diesel Initiative

MI Michigan

List of Acronyms
List of Acronyms

mmBtu Million British Thermal Units

MN Minnesota

MO Missouri

MRPO Midwest Regional Planning Organization

MW Megawatt

NAAQS National Ambient Air Quality Standards

NACAA National Association of Clean Air Agencies

ND North Dakota

NEEDS National Electric Energy System Database

NEI National Emission Inventory

NESCAUM Northeast States for Coordinated Air Use Management

OFA Overfire Air

OH Ohio

OTC Ozone Transport Comission

POC Primary Organic Carbon (particulate)

PSAT Particle Source Apportionment Tool

RIA Regulatory Impact Assessment

RICE Reciprocating Internal Combustion Engines

SCR Selective Catalytic Reduction

SD South Dakota

SDA Spray-Dry Absorbers

SIP State Implementation Plan

SNCR Selective Non-Catalytic Reduction

STAPPA State and Territorial Air Pollution Program Administrators

TN Tennessee

TSE Truck Stop Electrification

U.S. EPA United States Environmental Protection Agency

VISTAS Visibility Improvement State and Tribal Associations of the Southeast

VOC Volatile Organic Compounds

WFGD Wet Flue Gas Desulfurization

WI Wisconsin

(NH4)(HSO4) ammonium sulfate

(NH4)(NO3) ammonium nitrate

(NH4)2SO4 ammonium sulfate

CO carbon monoxide

CO2 carbon dioxide

HC hydrocarbons

NH3 ammonia

NH4+ ammonium

NO3- nitrate

NOx nitrogen oxide

PM2.5 particulate matter (2.5 micrometers or smaller)

SO2 sulfur dioxide

Chemical Symbols
1

1. Introduction

The Regional Haze Rule requires States to set reasonable progress goals toward meeting a

national goal of natural visibility conditions in Class I areas by the year 2064. The first

reasonable progress goals will be established for the planning period 2008 to 2018. The states of

Minnesota and Michigan, along with the Midwest Regional Planning Organization (MRPO),

representatives of other states, tribal governments, and federal agencies, are working to address

visibility impairment due to regional haze in four northern-Midwest Class I areas. These areas,

shown in Figure 1-1, are the Boundary Waters Canoe Area Wilderness, Voyageurs National Park,

Isle Royale National Park, and the Seney Wilderness Area.

The Regional Haze Rule identifies four factors which should be considered in evaluating

potential emission control measures to meet visibility goals. These are as follows:

1. Cost of compliance

2. Time necessary for compliance

3. Energy and non-air quality environmental impacts of compliance

4. Remaining useful life of any existing source subject to such requirements

In addition, the U.S. Environmental Protection Agency’s regional haze rule identifies a fifth

factor which should be considered. This is the uniform rate of visibility improvement needed to

attain natural conditions by 2064. 

Figure 1. Northern-Midwest Class I Areas.
2

The purpose of this report is to analyze these reasonable progress factors for several

possible control strategies intended to improve visibility in the northern-Midwest Class I areas:

2 X • SO and NO emissions from electric generating units (EGUs)

2 X • SO and NO emissions from Industrial, commercial and institutional (ICI) boilers

• Ammonia from agricultural operations

X

• NO emissions from onroad and nonroad mobile sources

X

• NO emissions from reciprocating engines and turbines

In addition, an analysis is provided of existing (“on the books”) control programs:

• Clean Air Interstate Rule (CAIR)

• BART for available States (i.e., MI, MN, WI, and ND)

• Maximum Available Control Technology (MACT) standards for combustion turbines and

industrial boilers

• On-road mobile source programs (i.e., 2007 Highway Diesel Rule, Tier II/Low Sulfur

Gasoline)

• Non-road mobile source programs (i.e., Non-road Diesel Rule, Control of Emissions from

Unregulated Non-road Engines, Locomotive/Marine ANPRM)

The current factor analysis has been carried out in conjunction with other related work

being conducted by the MRPO (also known as the Lake Michigan Air Directors Consortium,

LADCO) and the Midwest states, and within the overall framework described in the document,

“Approaches for Meeting Reasonable Progress for Visibility at Northern Class I Areas.” In 1

addition, the methodology for this analysis has been developed in a collaborative process

involving state representatives, the MRPO, and other stakeholders. On June 1, 2007, EPA issued

guidance related to setting reasonable progress goals (“Guidance for Setting Reasonable Progress

Goals Under the Regional Haze Program”). A preliminary review of EPA's guidance document

indicates that the approach taken in this report is consistent with the guidance.

This report is organized in six sections. Section 2 gives a summary of background

information from other studies that provided the basis for selecting the priority pollutants and

emission sources to be analyzed in this factor analysis. Section 3 describes the general

methodology used in the factor analysis. Section 4 gives results of the factor analysis for on-thebooks controls, and Section 5 gives factor analysis for potential future regional haze controls. 

Section 6 summarizes the results and conclusions of the factor analysis.
3

2. Background

To support planning efforts for regional haze in the northern-Midwest Class I areas, the

States prepared a summary of technical information. This summary document includes a 2

conceptual model of haze, the technical basis for visibility analysis, and the effectiveness of

control measures in improving visibility. A key part of the conceptual model of haze is a

contribution assessment based on air quality data analyses and photochemical modeling. The

contribution assessment identifies important states and sources contributing to visibility

impairment in the northern-Midwest Class I areas.

The most important contributing states are Michigan, Minnesota, and Wisconsin, as well

as surrounding states, such as the Dakotas, Iowa, Missouri, Illinois, and Indiana. For example,

Figure 2-1 presents the results of composite back trajectories for light extinction on the 20%

worst visibility days. The orange areas are where the air is most likely to come from on poor air

quality days, and the green areas are where the air is least likely to come from on poor air quality

days. As can be seen, bad air days are generally associated with transport from regions located to

the south of these class I areas.

The most important contributing pollutants and source sectors are SO emissions from 2

electrical generating units (EGUs) and certain non-EGUs, which lead to sulfate formation, and

NOx emissions from a variety of source types (e.g., motor vehicles), which lead to nitrate

formation. Ammonia emissions from livestock waste and fertilizer applications are also

Figure 2-1. Composite Back Trajectories for Light Extinction

on the 20% Worst Days.
4

Figure 2-2. Results of 2018 PSAT modeling for Boundary

Waters Canoe Area.

important, especially for nitrate formation. For example, Figure 2-2 presents the results of

particle source apportionment tool (PSAT) modeling for the Boundary Waters Canoe Area for

2018. As can be seen, sulfates are the dominant species indicating the importance of SO2

emissions.

The modeling analyses were based on emissions inventories for 2002 and 2018. 

Figure 2-3 and Table 2-1 summarize the major contributors to the SO , NO , and ammonia 2 X

emissions inventories in 2002 and 2018 for Michigan, Minnesota, and Wisconsin – the three

Figure 2-3. Summary of SO , NO , and NH emissions in 2X 3

Michigan, Minnesota, and Wisconsin.
2002 2018 2002 2018 2002 2018 

Point sources

Electric generating units 2,023 1,755 1,013 514 7,489 4,952 Industrial, commercial and institutional boilers 227 215 136 132 674 641 Reciprocating engines 71 66 

Turbines 19 20 

Other point sources 156 196 257 287 815 948 

Area sources 113 112 208 225 594 588 Mobile sources

Onroad 1,862 708 

Nonroad 51 4 557 338 123 19 

Marine, aircraft, railroad 21 11 294 222 44 20 

Total 2,592 2,294 4,417 2,512 9,739 7,168 

Table 2-1. Regional Emissions Summary

Estimated emissions in the 3-state region 

surrounding the northern Midwest Class I areas 

(tons/day)

Estimated emissions 

(to

SO2 NOX SO2 

5
 The EGU projections used in this study are taken from the VISTAS 2.1.9 version of IPM, which was a

developed in July 2005. In January 2007, EPA prepared new EGU projections (i.e., 3.0 version of IPM). The new

EGU projections reflect lower 2018 SO emissions for the 3-state region (about 500 TPD less). The MRPO is 2

currently updating its regional modeling inventory to reflect a more current base year (2005) and improved future

year emission estimates, including use of the new EGU projections. The new inventory will be available in mid2007.

6

states nearest to the northern-Midwest Class I areas. (Appendix A provides state level emissions

estimates for major emission categories.) These estimates are derived from the MRPO Base K

emissions inventory for 2002, and MRPO projections of 2018 emissions with existing on-thebooks control measures. Figure 2-4 gives a similar emission summary for the nine-state region 3,a

to the South and West of the Midwest Class I areas, including Illinois, Indiana, Iowa, Michigan,

Minnesota, Missouri, North Dakota, South Dakota, and Wisconsin. As Figure 2-3 shows, EGUs

account for the bulk of SO emissions in the three states in 2002, and are also projected to 2

account for the bulk of SO emissions in 2018. Mobile sources contribute the bulk of NO 2 X

emissions in 2002, followed by EGUs. NO emissions from both EGU and mobile sources are X

projected to decline between 2002 and 2018, but they are still projected to be the largest sources

of NO in 2018. Agricultural sources account for the bulk of ammonia emissions in both 2002 X

and 2018.

A preliminary CAMx model sensitivity analysis has been carried out to estimate the

potential impacts of SO , NO , and NH emission reductions on light extinction in the northern 2X 3

Midwest Class I areas. This analysis evaluated the impacts of 10% across the board emission 4

2X 3 reductions for SO , NO , and NH . Results of the sensitivity analysis are presented in Table 2-2. 

A 10% reduction in SO emissions is predicted to reduce light extinction from sulfate particulate 2

matter by 7.7 to 8.9%, and overall particulate light extinction by 1.3 to 3.5% in the northern

Midwest Class I areas. The SO emission reduction is predicted to increase extinction of nitrate 2

Figure 2-4. Summary of SO , NO , and NH emissions in 2X 3

Michigan, Minnesota, Wisconsin, Illinois, Indiana,

Iowa, Missouri, North Dakota, and South Dakota.
7

particulate matter by 2.4 to 3.2%. This is because less NH would be bound to sulfate in the form 3

of ammonium sulfates [(NH ) SO or NH (HSO )], making more NH available for the formation 42 4 4 4 3

of ammonium nitrate (NH NO ). A 10% NO emission reduction is predicted to reduce light 4 3 X

extinction from nitrate particulate matter (mainly NH NO ) by 9.7 to 11.3%, and overall 4 3

particulate light extinction by 2.4 to 2.8%. A 10% NH emission reduction is predicted to reduce 3

4 3 light extinction from NH NO by 7.7 to 9.3%, and overall particulate light extinction by 2.0 to

2.7% at the northern Midwest Class I areas.

Table 2-2. CAMx Model Sensitivity Analysis of the Impacts of SO , NO , 2 X

and NH Emission Reductions on Visibility 3

Change in

emissions

Particulate

component

Impacts on predicted light extinction (% change)

Boundary

Waters Voyageurs

Isle

Royale Seney Average

10% reduction

2

in SO a

Sulfate -8.6 -7.7 -8.5 -8.9 -8.4

Nitrate 2.4 3.2 2.5 3.1 2.8

Overall -2.4 -1.3 -2.6 -3.5 -2.5

10% reduction

X

in NO a

Sulfate -0.1 0.3 -0.0 0.1 0.1

Nitrate -9.7 -10.1 -10.1 -11.3 -10.3

Overall -2.4 -2.8 -2.4 -2.6 -2.5

10% reduction

3

in NH a

Sulfate -0.5 -0.5 -0.9 -0.8 -0.7

Nitrate -7.9 -9.4 -7.7 -9.3 -8.6

Overall -2.0 -2.7 -2.1 -2.5 -2.3

Each test entailed a 10% across-the-board reduction in 2018 emissions of the indicated a

pollutant, without any other change to the emissions inventory.

The sensitivity results give a somewhat different perspective from the PSAT results

X 2 shown in Figure 2-2, with respect to the potential relative impacts of NO and SO controls. For

example, in the PSAT results for Boundary Waters (Figure 2-2), the estimated light extinction

from sulfate particulate dominates is much larger than the estimated light extinction from nitrate

particulate. However, based on the sensitivity results for Boundary Waters, a 10% reduction in

NO is projected to produce the same overall light extinction impact as a 10% reduction in SO . X 2

This is partly because the reduction in SO , while reducing sulfate particulate, is projected to also 2

result in a small increase in nitrate particulate. However, it must be noted that the source

apportionment (PSAT) and source sensitivity are not the same, and the results are expected to

differ. The PSAT results represent absolute model values, while the sensitivity results represent

relative model values. The relative model values may be more appropriate given that they reflect

EPA’s modeling guidance and correct for model performance problems such as underprediction

of nitrates.
8

3. Methodology

The methodology for this factor analysis was developed in a collaborative process

involving the MRPO, state representatives, the National Park Service, and the U.S. Forest

Service. A two pronged approach was adopted, comprising a broad category-level analysis 5

coupled with an in-depth analysis of selected individual sources. 

The category-level analysis addresses the overall impacts of different emission control

strategies on a broad class of emission sources, such as electric generating units (EGUs); or

industrial, commercial and institutional (ICI) boilers. These control strategies generally involve

an emission cap or a percentage rollback in overall emissions, both of which allow emissions

trading among the sources in a given geographical region. 

Two regions were selected for analysis, as illustrated in Figure 3-1. A three-state region

(shown in brown) includes Michigan, Minnesota, and Wisconsin, which immediately surround

the northern-Midwest Class I areas. A nine-state region includes these three states and adds six

surrounding states (shown in yellow) – North and South Dakota, Iowa, Missouri, Illinois, and

Indiana.

The in-depth analysis focused on the impacts of applying pollution control devices to

selected individual facilities. These were used to help evaluate how category-level strategies will

potentially apply to individual sources and to evaluate the uncertainties of the category-level

analysis.

Figure 3-1. Geographic regions for the factor analysis.
9

Some additional individual sources were selected from source-types which were not part

of the category-level analyses. The analyses of these facilities were designed to ensure that

opportunities for cost-effective visibility improvements were not overlooked.

The first step in the technical evaluation of control measures for a source category was to

establish the future emissions baseline with on-the-books regulations. This baseline was used to

assess the progress toward the reasonable further progress goal with only on-the-books controls. 

The future baseline also provides a frame of reference to estimate the amount of emissions

available for additional control. 

The primary timeframe for the analysis is the 2018 reasonable progress milestone. 

However, potential emission reductions by 2012 will also be evaluated. Estimates of 2012

and 2018 baseline emissions for various emission source categories have been developed by the

MRPO. The control technologies to meet on-the-books controls were identified based on the

technical support documents and other background information published in support of the

applicable regulations.

Once the baseline level of control in 2018 (and 2012) was identified, a list of potential

additional control technologies was compiled from a variety of sources, including control

techniques guidelines published by the EPA, emission control cost models such as

AirControlNET and CueCost, Best Available Retrofit Technology (BART) analyses, LADCO

White Papers, and a menu of control options developed by the National Association of Clean Air

Agencies (NACAA – formerly STAPPA and ALAPCO). The menu of options for each source 6

category was then narrowed to a set of technologies that would achieve the emission reduction

target under consideration. The following sections discuss the methodology used to analyze each

of the regional haze factors for the selected technologies.

3.1 Factor 1 – Costs

Control costs include both the capital costs associated with the purchase and installation

of retrofit and new control systems, and the net annual costs (which are the annual reoccurring

costs) associated with system operation. The basic components of total capital costs are direct

capital costs, which includes purchased equipment and installation costs, and indirect capital

expenses. Direct capital costs consist of such items as purchased equipment cost,

instrumentation and process controls, ductwork and piping, electrical components, and structural

and foundation costs. Labor costs associated with construction and installation are also included

in this category. Indirect capital expenses are comprised of engineering and design costs,

contractor fees, supervisory expenses, and startup and performance testing. Contingency costs,

which represent such costs as construction delays, increased labor and equipment costs, and

design modification, is an additional component of indirect capital expenses. Capital costs also

include the cost of process modifications. Annual costs include amortized costs of capital

investment, as well as costs of operating labor, utilities, and waste disposal. For fuel switching

options, annual costs include the cost differential between the current fuel and the alternate fuel.
10

For Factor 1, results of the cost analysis are expressed in terms of total cost-effectiveness,

in dollars per ton of emissions reduced. Cost effectiveness is also calculated in terms of dollars

per deciview by combining results from the Factor 1 and Factor 5 analyses.

A relevant consideration in a cost-effectiveness calculation is the economic condition of

the industry (or individual facility if the analysis is performed on that basis). Even though a

given cost-effectiveness value may, in general, be considered “acceptable,” certain industries

may find such a cost to be overly burdensome. This is particularly true for well-established

industries with low profit margins. Industries with a poor economic condition may not be able to

install controls to the same extent as more robust industries. A thorough economic review of the

source categories selected for the factor analysis is beyond the scope of this project.

3.2 Factor 2 – Time Necessary for Compliance

For Factor 2, we evaluated whether a potential control strategy could be fully

implemented by the target dates of 2018 or 2012, or how much of an emission reduction can be

achieved by these target years. The time for compliance was defined to include the time needed

to develop and implement the regulations, as well as the time needed to install the necessary

control equipment. The time required to install a retrofit control device includes time for capital

procurement, device design, fabrication, and installation. The Factor 2 analysis also included the

availability of production and labor capacity for fabricating and installing control devices, as well

as the need for staging the installation of multiple control devices at a given facility.

For mobile sources, control strategies may not require retrofits to existing emission

sources, but instead rely on the turnover of vehicle fleets, or replacement of nonroad engines. In

these cases, the Factor 2 analysis focuses on quantifying the fraction of the source category which

would use the new technology by the target date, and the emission reduction that would result. 

For agricultural sources of ammonia, Factor 2 was analyzed in terms of time required to fully

implement technical control strategies or to grow vegetative buffers.

3.3 Factor 3 – Energy and Other Impacts

Table 3.3-1 summarizes the energy and environmental impacts analyzed under Factor 3. 

We evaluated the direct energy consumption of the emission control device, solid waste

generated, wastewater discharged, other environmental impacts. Other non-air quality

environmental impacts considered included solid waste generation, wastewater discharge, acid

deposition, nitrogen deposition, and climate impacts (e.g., generation and mitigation of

greenhouse gas emissions).

Costs of disposal of solid waste or otherwise complying with regulations associated with

waste streams were calculated as part of Factor 1, and were evaluated as to whether they could be

cost-prohibitive or otherwise negatively affect the facility. Energy needs and non-air quality

impacts of identified control technologies were aggregated to estimate the energy impacts for the

specified industry sectors. However, indirect energy impacts were not considered, such as the
11

different energy requirements to produce a given amount of coal versus the energy required to

produce an equivalent amount of natural gas. For completeness, information on other air quality

environmental impacts was provided in Factor 3 (e.g., improvement in ambient PM and ozone 2.5

concentrations due to reductions in regional NO and SO emissions). X 2

Table 3.3-1 Summary of Energy and Environmental Impacts

Evaluated Under Factor 3

Energy Impacts

Electricity requirement for control equipment and associated fans

Steam required

Fuel required

Environmental Impacts

Waste generated

Wastewater generated

Additional CO produced 2

Reduced acid deposition

Reduced nitrogen deposition

Benefits from reductions in PM and ozone, where available 2.5

Impacts Not Included

Impacts of control measures on boiler efficiency

Energy required to produce lower sulfate fuels

Secondary environmental impacts to produce additional energy (except

CO ) produced 2

3.4 Factor 4 – Remaining Equipment Life

Factor 4 accounts for the impact of the remaining equipment life on the cost of control. 

Such an impact will occur when the remaining expected life of a particular emission source is

less than the lifetime of the pollution control device (such as a scrubber) that is being considered. 

In this case, the capital cost of the pollution control device can only be amortized for the

remaining lifetime of the emission source. Thus, if a scrubber with a service life of 15 years is

being evaluated for a boiler with an expected remaining life of 10 years, the shortened

amortization schedule will increase the annual cost of the scrubber.

In general, the category-level control strategies evaluated in this study are market-based

strategies, which would allow trading among emission sources to achieve a region-wide target. 
12

The affected industries are expected to install control devices in a a manner that minimizes

overall costs to the industry. Under this scenario, it is expected that control devices would not be

installed on emission sources with short life expectancies. 

In the analyses of individual facilities, the ages of major pieces of equipment were

determined where possible, and compared with the service life of pollution control equipment. 

The impact of a limited useful life on the amortization period for control equipment was then

evaluated, along with the impact on annualized cost-effectiveness.

3.5 Factor 5 – Visibility Impacts

Visibility impacts of potential emission control strategies were estimated using the results

of the MRPO’s modeling analyses. For the examination of existing control measures, the

visibility impacts were calculated directly by the modeling for 2018. For the examination of

potential additional control measures, visibility impacts were derived using the results of PSAT

analyses and sensitivity analyses for 2018. In the PSAT analyses, the MRPO estimated the

contribution of different emission source groups to the overall light extinction coefficient at each

Class I area. Sources were grouped by major emission source categories and by source regions 7

4

(generally states). In addition, extinction contributions were modeled for the sulfate (SO ), =

nitrate (NO ), and ammonium (NH ) fractions of particulate matter, as well as other particulate 3 4

– +

components. The MRPO sensitivity analysis evaluated the impacts of 10% across-the-board

2X 3 reductions in emissions of SO , NO , and NH . The MRPO also computed light extinction

contributions for the several high-emitting individual facilities in the region.

A rollback approach was used to estimate the visibility impacts of potential future

emission control strategies for SO and NO emissions from different source categories. In this 2 X

approach, the extinction coefficient is assumed to change in proportion to the change in

emissions from the source category. Impacts were calculated on a source-category-specific,

state-specific, and chemical species fraction basis. The algorithm used for these rollback

calculations is as follows:

where:

RX = estimated reduction in extinction coefficient for pollutant i (SO , NO , or NH ), i,j,k 2 X 3

category j, and source region k (Mm ) –1

Rdn = estimated emission reduction resulting from a control strategy for pollutant i, i,j,k

emission source category j and source region k (tons/year)
13

PSAT = estimated contribution of emissions for the particulate species corresponding to i,j,k

pollutant i (SO for SO , NO for NO , and NH for NH ), for category j, and 4 23 X 4 3

=– +

source region k to the extinction coefficient, based on PSAT modeling for 2018

(Mm ) –1

PSAT = total contribution pollutant i from PSAT modeling (Mm ) i,tot

–1

Emis = projected emission rate in 2018 for pollutant i, source category j, and source i,j,k

region k, with on-the-books controls but before the application of any additional

control strategy (tons/year)

SensXChg = Predicted change in extinction based on the results of CAMx sensitivity analysis i

for pollutant i (Mm ), as shown in Table 3.5-1 –1

SensEChg = Fractional change in emissions in the sensitivity analysis (10%)

The above approach assumes a linear relationship between the emissions of precursor

pollutants and the amount of light extinction that will result from these precursors. This

simplifying assumption is subject to considerable uncertainty. In addition, the above approach

draws on sensitivity analyses and PSAT analyses using the CAMx model, and is subject to the

uncertainties of these model analyses. As a result, this approach and can under-predict or overpredict visibility impacts.. However, it provides a mechanism for estimating visibility impacts as

a prelude to more-detailed modeling.

Table 3.5-1. Sensitivity Factors Used in

Calculating Extinction Changes

Pollutant

Light extinction change per 10% reduction in

emissions (Mm ) –1 a

Boundary

Waters Voyageurs

Isle

Royale Seney

SO2 –1.7 –1.0 –2.0 –3.4

NOX –1.7 –2.0 –1.9 –1.9

NH3 –1.4 –1.9 –1.6 –2.5

Based on CAMx sensitivity analyses (discussed in a

Section 2). Table 2-2 has given these changes as a

percentage of the projected baseline light extinction.
14

The impacts in terms of extinction coefficient were then converted to deciviews using the

following equation, based on the definition of a deciview:

where:

RdV = estimated reduction in visibility degradation at a particular Class I area

(deciviews)

BX = total extinction coefficient at the Class I area in 2018, from all sources (Mm ) –1

RX = reduction in extinction coefficient for a particular source or source category

(Mm ) –1

The visibility impacts in this report are generally expressed in terms of deciviews.

In addition to the extinction and deciview estimates, the impacts of pollution control

strategies were also quantified in terms of the change in emissions divided by distance (Q/d). 

This information can be useful in evaluating the impacts for sources which have not been

included in the 2018 PSAT analysis. For a group of sources or facilities, the Q/d factor is

computed as follows:

where:

(Q/d) = the sum of emissions divided by distance for a given group of emission sources

and in relation to a given Class I area (tons/mile)

Rdn = the emission reduction at source n, within the group of emission sources (tons) n

Dist = the distance from source n to the Class I area (miles) n
15

4. Analysis of Existing Control Measures

A factor analysis was conducted for on-the-books and on-the-way Federal regulatory

programs impacting priority sectors in the 3-State and 9-State regions. The purposes of this

analysis were to:(1) assess the progress toward the reasonable progress goal with only on-thebooks controls, and (2) provide a frame of reference to estimate the amount of emissions

available for additional control.

The MRPO Base K/Round 4 Strategy Modeling emissions inventory applies these

programs in their Scenario 1 2018 projections. Cost-effectiveness and emission reduction

information were obtained from available documents (e.g., Regulatory Impact Analyses (RIAs),

preliminary Best Available Retrofit Technology (BART) analyses for available facilities, and

Advance Notices of Proposed Rulemaking (ANPRM)). Table 4-1 lists the programs included in

the on-the-books analysis. In addition, the table lists the sources of information used to evaluate

the impacts of these programs. Table 4-2 summarizes information on the projected impacts of

these control measures relative to the four reasonable progress factors for regional haze.

Table 4-1. On-the-Books Control Measures Included in the Factor Analysis

Regulatory Program Information Source

Clean Air Interstate Rule (CAIR) CAIR RIA8, 9

BART Company BART analyses, where available10, 11

Maximum Available Control Technology (MACT)

standards

• Reciprocating Internal Combustion Engines

(RICE) MACT Federal Register Notice12

• Industrial Boilers and Process Heaters MACT

Federal Register Notice13

On-road mobile source programs • 2007 Highway Diesel Rule RIA14

• Tier II Emissions Standards RIA15

• Low Sulfur Gasoline RIA15

Non-road mobile source programs • Non-road Diesel Rule RIA16

• Control of Emissions from Unregulated Non-road

Engines RIA17

• Locomotive/Marine ANPRM18

4.1 Factor 1 – Costs

EPA has estimated that the cost of the CAIR program will range from $720 to $2,600 per

2 X ton of SO or NO emissions reduced. CAIR is the most recent of a number of existing cap- 6,7

and-trade programs to reduce SO and NO emissions from EGUs in the eastern U.S. Other cap- 2 X

and-trade programs for SO and NO include the Acid Rain Program and the NO SIP call for 2 X X

the ozone National Ambient Air Quality Standards (NAAQS). 
Factor 1 

Control Strategy Cost effectiveness ($/ton) Energy

Solid 

prod

(1

tons

3-State SO2: 13% 3-State SO2: 47% 4.5% of total 

NOX: 75% NOX: 75%

9-State SO2: 34% 9-State SO2: 48%

NOX: 79% NOX: 80%

BART: Based on company BART analyses from MN and ND

$248 - $1,770

Combustion MACTs $1,477 - $7,611 9-State SO2: 10% 9-State SO2: 10%

NOX: 5% NOX: 5%

Highway vehicle programs $1,300 - $2,300 3-State NOX: 83% 3-State NOX: 83%

9-State SO2: 80% 9-State SO2: 80%

Nonroad mobile sources ($1,000) - $1,000 3-State NOX: 39% 3-State NOX: 39%

9-State SO2: 27% 9-State SO2: 27%

350 MM gallons of fuel saved

Table 4-2. Summary of Five-Factor Analysis of On-The-Books Controls

Factor 2 Factor 3

CAIR and other cap-and-trade programs (e.g., Acid Rain, NOX SIP Call)

$720 - $2,600 

Percent Emission 

Reductions from 2002 

baseline in 2018

Percent Emission 

Reductions from 2002 

baseline at full 

implementation

16
 The EGU projections used in this study are taken from the VISTAS 2.1.9 version of IPM, which was a

developed in July 2005. In January 2007, EPA prepared new EGU projections (i.e., 3.0 version of IPM). The new

EGU projections reflect lower 2018 SO2 emissions for the 3-state region (about 500 TPD less). The MRPO is

currently updating its regional modeling inventory to reflect a more current base year (2005) and improved future

year emission estimates, including use of the new EGU projections. The new inventory will be available in mid2007.

17

The Midwest states have identified over 30 non-EGU facilities which would be subject to

BART based on their estimated impacts on the northern Midwest Class I areas. These sources,

listed in Table 4.1-1, include industrial boilers, petroleum refineries, steel plants, aluminum

plants, cement plants, chemical manufacturing facilities, pulp and paper plants, and iron mines. 

Emission sources in Minnesota and North Dakota have prepared draft BART analyses, and some

have proposed control technologies to meet the requirements of the BART program. The

facilities proposing additional controls for BART are primarily EGUs. Based on control

technologies proposed by the facilities, the draft BART analyses give a range of costeffectiveness estimates from $300 to $1,770 per ton of emissions reduced. Appendix A presents

additional details on facility-specific BART analyses. It must be noted that the states have not

yet established thresholds for BART controls. Facilities may need to install more stringent

controls than have been identified in the current BART analyses.

MACT standards for reciprocating internal combustion engines (RICE) are expected to

reduce Hazardous Air Pollutants (HAP) through measures to improve combustion efficiency. 

These combustion changes are also expected to reduce NO emissions with a cost-effectiveness X

of about $1,500 per ton of NO reduced. MACT standards for industrial, commercial, and X

2

institutional boilers and process heaters are expected to reduce HAP emissions as well as SO

emissions through sorbent injection controls. The cost per ton of SO removed is estimated at 2

about $7,600. 

The Unregulated Engine Rule is expected to produce cost savings of $1,000/ton. This

savings is expected to result from increased fuel economy in the non-road sector. 

4.2 Factor 2 – Time Necessary for Compliance

Because emission sources can trade emission allowances to meet the CAIR limits, the

timing and magnitude of emission reductions from the program will vary from state to state. The

Integrated Planning Model (IPM) has been used to predict where and when pollution control

technologies will be installed to meet the requirements of CAIR and other existing programs. 

Table 4-2 shows projected emission reductions in the Midwest from CAIR by 2018 and after the

rule has been fully implemented. Appendix A gives predicted emission reductions at the state a

level. These emission projections are based on the VISTAS-2.1.9 run of IPM. As Table 4-2 and

Appendix A show, most of the CAIR NO emission reductions in the Midwest are expected to be X

2

realized by 2018, but most of the reductions for SO are expected to occur between 2018 and

2026. Emission reductions for the other on-the-books control measures are expected to be

realized prior to 2018.
State Source Name County Source ID SIC Code

Illinois Conoco Phillips Madison 119090AAA

Illinois Exxon Mobil Will 197800AAA

Illinois CITGO Will 197090AAI

Illinois National Steel – Granite City Madison 119813AAI

Indiana AGC Division - ALCOA Power Generating Warrick 2 4911

Indiana Alcoa Inc. - Warrick Warrick 7 3334

Indiana Essroc Cement Corporation (Speed) Clark 8 3241

Indiana Essroc Cement Corporation (Logansport) Cass 5 3241

Indiana GE Plastics, Mt. Vernon Inc. Posey 2 2821

Indiana ISG-Burns Harbor (Formerly Beth. Steel) Porter 1 3312

Michigan Lafarge Midwest Inc. Alpena B1477 3241

Michigan Smurfit Stone Container Corp. Ontonagon A5754 2611

Michigan Tilden Mining Co Marquette B4885 1011

Michigan Empire Iron Mining Marquette B1827 1011

Michigan St. Mary’s Cement (CEMEX) Charlevoix B1559

Michigan New Page Paper (Escanaba) Delta A0884

Minnesota Ipsat Inland (Mittal) St. Louis 2713700062 1011

Minnesota EVTAC-Fairlane (United Taconite) St. Louis 2713700113 1011

Minnesota National Steel (USS Keetac) St. Louis 2713700063 1011

Minnesota Hibbing Taconite St. Louis 2713700061 1011

Minnesota USS Minntac St. Louis 2713700005 1011

Minnesota Northshore Mining Lake 2707500003 1011

N. Dakota Great River Energy – Coal Creek McLean 17 4911

N. Dakota Basin Electric Power – Leland Olds Mercer 1 4911

N. Dakota Great River Energy – Stanton Mercer 4 4911

N. Dakota Minnkota Power – MR Young Oliver 1 4911

Ohio Mead Paper Division Ross 671010028 2611

Wisconsin Georgia-Pacific Consumer Products, L.P. (former Fort 

James Operating Company)

Brown 405032870 2621

Table 4.1-1. Non-EGU Sources Subject to BART in 9-State Region

18
19

4.3 Factor 3 – Energy and Other Impacts

For Factor 3, targeted analyses of energy and other adverse environmental impacts were

not available in the various program RIAs. However, for the CAIR program it is expected that

implementation of SCR and wet scrubber technology would require additional energy to operate,

and produce additional wastewater and solid waste. BART analyses conclude that energy and

adverse environmental impacts were manageable.

Environmental benefits were qualitatively discussed in several RIAs. In general, it is

expected that any reduction in NO or SO emissions will decrease nitrate and sulfate deposition. X 2

As a result of the CAIR program, the incidence of acidic lakes is projected to decrease from 10%

2.5 in 2002 to 6% in 2026. Co-benefits of PM and ozone emission reductions are also expected at

full implementation of CAIR and the on-road programs. The non-road program is expected to

result in a diesel fuel savings of 350 million gallons per year.

4.4 Factor 4 – Remaining Equipment Life

Factor 4 generally does not apply to on-the-books controls on the sector level. Engine

and fuel standards impact on-road vehicles beginning in 2007 and non-road vehicles beginning

2008, and fleet turnover for full implementation of these new standards is expected to be

completed by 2030. Available documentation from facilities subject to BART indicate that they

will install controls rather than shut down to comply with the regulations. IPM projections for

the CAIR program indicate that some EGUs in the Midwest region may be retired before 2018. 

For example, the VISTAS-2.1.9 of IPM estimates that 26 electric generating units may be retired

in the three-state region, and 53 units in the nine-state region. 

4.5 Factor 5 – Visibility Impacts

Table 4.5-1 compares overall visibility goals with the impacts from On-the-books

controls. The MRPO has carried out regional photochemical modeling with CAMx to quantify

the level of visibility improvement associated with on-the-books controls in comparison to the

uniform rate of visibility improvement in 2018 (see Table 4-3). Figure 4-1 compares the impacts

of On-the-books measures to the glide path. Based on these results, the on-the-books control

measures will not achieve sufficient emission reductions to fall below the glide path. In addition,

On-the-books controls are less effective in improving visibility at Voyageurs than at the other

northern-Midwest Class I areas. This appears to be due to differences in source region

culpabilities. In particular, the influence from the major Midwest source regions, especially

those with the largest change (decrease) in emissions, decreases with distance, i.e., the most

impact occurs at Seney (the closest Class I area) and the least impact occurs at Voyageurs (the

farthest Class I area).
20

Table 4.5-1. Comparison of Overall Visibility Goals in 2018 with

Projected Impacts for On-the-Books Controls

Pollutant

Estimated visibility impairment on the 20%

worst-visibility days (deciviews)a

Boundary

Waters Voyageurs

Isle

Royale Seney

Baseline conditions (2000-2004)a 19.86 19.48 21.62 24.48

Projected conditions in 2018 with

on-the-books controlsb 18.94 19.18 20.04 22.38

Net change 0.92 0.30 1.58 2.10

Glide path goal for 2018 17.70 17.56 19.21 21.35

a

The baseline condition values reflect the recent adjustments proposed by the Midwest RPO to

include several missing days. The adjusted values are, on average, less than 0.5 deciviews greater

than those provided on the IMPROVE website.

b

Based on CAMx modeling by the MRPO. These modeling analyses used preliminary estimates of

the impacts of BART controls, which are generally larger than the impacts estimated in industry

BART analyses.
Figure 4-1. Estimated visibility impacts of on-the-books controls in comparison with reasonable progress

goals for the northern-Midwest Class I areas
a

These facilities were selected based on a review of SO2 and NOX emissions inventories, emissions

v. distance from each of the northern class I areas, and the results of previous source apportionment modeling

studies. Facilities were eliminated from consideration if they were subject to BART or have already agreed to new

pollution controls. Given time and resource constraints, the evaluation was limited to facilities located in the three

northern states.

22

5. Analysis of Potential Additional

Control Measures

This section discusses the impacts of several possible control strategies which could be

adopted to improve visibility in the northern-Midwest Class I areas. Control strategies for the

following emissions and emission source categories have been evaluated: 

• SO2 and NOX emissions from electric generating units (EGUs)

• SO2 and NOX emissions from Industrial, commercial and institutional (ICI) boilers

• Ammonia from agricultural operations

• NOX emissions from onroad and nonroad mobile sources

• NOX emissions from reciprocating engines and turbines

These categories were selected in a collaborative process with the Midwest States, based on a

review of regional emissions inventories and the results of previous source apportionment

modeling studies (as discussed in Section 2). These categories are expected to account for the

bulk of SO2, NOX and NH3 emissions in the region in 2018. The control strategies and levels of

reductions for these categories were selected in a collaborative process. Taconite facilities were

not included in the list of priority source categories, because all eight taconite facilities are

subject to BART (six in Minnesota and two in Michigan). A more thorough cost analysis is

being performed for BART.

In addition, 20 individual emission facilities were identified by the states for in-depth

analysis.a These sources are listed in Table 5-1. Most of the individual sources are in the

priority emission categories listed above, including 11 EGUs and four facilities with ICI boilers. 

Two lime manufacturing facilities, one cement plant one petroleum refinery, and one glass

furnace were also included in the analysis. 

The following subsections present the results of the reasonable progress factor analysis

for the selected source categories and individual facilities. A separate subsection is devoted to

each emission category, including the selected individual facilities within the category. The final

subsection addresses the individual facilities which are not in the selected emission categories.

5.1 Electric Generating Units

The MRPO and the Midwest states have been analyzing potential emission control

strategies to reduce SO2 and NOX emissions from EGUs. These strategies would establish
State County Unit ID Facility Name Unit Descriptions

MI Marquette B4261 Wisconsin Electric/Presque IsleMI Ottawa B2835 JH CampbellMI St_Clair B2796 St. Clair/BelleRiver

MN Itasca 2706100004 Clay Boswell Units 1,2,4 – NOx, SO2MN St. Louis 2713700013 Syl Laskin Units 1,2 – SO2MN St. Louis 2713700028 VA PUC

WI Buffalo 606034110 Dairyland Power Coop/AlmaWI Grant 122014530 Alliant Energy/Nelson DeweyWI Sheboygan 460033090 Alliant Energy/EdgewaterWI Ashland 802033320 Xcel Energy/Bayfront

MI Alger B1470 Kimberly Clark ICI boiler

MI Schoolcraft A6475 Manistique Papers ICI boilerMI Monroe B1743 Holcim Cement plant

MN Lake 2707500003 Northshore Mining Company/Silver Bay EU001 (EGU)MN Koochiching 2707100002 Boise Cascade Corp ICI boiler

WI Douglas 816009950 Murphy Oil Refinery (FCCU, Heater)

WI Lincoln 735008010 PCA - Tomahawk ICI boilers (B28, B27)WI Dunn 617049840 Cardinal FG Glass Furnace (P01)WI Douglas 816036430 CLM Corporation Lime manuf. (Kilns 2,3,4)WI Manitowoc 436034390 Rockwell Lime Lime manuf. (Kilns 1, 2)

Non-EGU

EGU

Table 5-1. Individual Sources Selected for Analysis

23
 The EGU projections used in this study are taken from the VISTAS 2.1.9 version of IPM, which was a

developed in July 2005. In January 2007, EPA prepared new EGU projections (i.e., 3.0 version of IPM). The new

EGU projections reflect lower 2018 SO emissions for the 3-state region (about 500 tons/day less). The MRPO is 2

currently updating its regional modeling inventory to reflect a more current base year (2005) and improved future

year emission estimates, including use of the new EGU projections. The new inventory will be available in mid2007.

24

2 X regional caps for SO and NO emissions, and would allow trading among the EGUs in the

region so that the overall regional emission caps can be attained in the most cost-effective

manner. Potential SO and NO regional control strategies and unit-level control technologies 2 X

for EGUs are presented in Appendix B. 

Two sets of possible caps have been evaluated, which are termed EGU1 and EGU2:19

! EGU1 would establish a regional emissions cap for SO and NO based on projected fuel 2 X

consumption:

" SO limited to 0.15 pounds per million British thermal units (lb/million-BTU) of 2

fossil fuel consumption in the region

" NO limited to 0.10 lb/million-BTU X

! EGU2 would establish regional emission caps for SO and NO based on projected fuel 2 X

consumption:

" SO limited to 0.10 lb/million-BTU 2

" NO limited to 0.07 lb/million-BTU X

These caps would apply to all fossil fuel power plants rated to produce 25 Megawatts (MW) or

more of electricity. The EGU1 caps were selected by the states to correspond roughly to the Best

Achievable Control Technology (BACT) levels for retrofit installations. The EGU2 caps were

selected to correspond roughly to the BACT levels for new sources.

Previously, these caps have been analyzed as control measures for ambient ozone and

PM , as well as regional haze. The timeframe considered in these previous analyses was 2009 2.5

to 2013, and the geographic area of coverage was the five-state MRPO region. For the current

regional haze factor analysis, we used the same numerical caps, but have changed the geographic

area of coverage to the three-state and nine-state regions shown in Figure 3-1. In addition, this

analysis assumes that the timeframe for implementing the caps would be 2018, the first

reasonable further progress target.

Table 5.1-1 shows the projected fuel usage in the three-state and nine-state regions in

2018, projected emissions taking into account on-the-books controls, and estimated allowable

emissions with the EGU1 and EGU2 caps. The estimates of fuel usage and baseline emissions in

2018 are based on IPM projections, which have also been used in the analysis of on-the-books a

control measures (Section 4). These projections take into account the CAIR program, the Acid

Rain program, the NO SIP call, and other on-the-books controls affecting EGUs. Table 5.1-2 X

gives estimated baseline emissions at the state level for EGUs in the region in 2002 and 2018. 

These estimates are based on the LADCO Base K emissions inventory and on IPM projections.
3-state 

region

9-state 

region

2,338 6,955

SO2 641 1,808NOX 188 571

SO2 175 522NOX 117 348SO2 117 348NOX 82 243

SO2 NOX SO2 NOX

Michigan 403 164 399 100Minnesota 116 99 86 42Wisconsin 220 107 155 46

3-State Subtotal 739 370 641 188

Illinois 478 260 241 73Indiana 912 303 377 95Iowa 150 93 147 51Missouri 305 167 281 78North Dakota 137 72 109 72South Dakota 13 16 12 15

9-State Total 2,734 1,280 1,808 571

Table 5.1-2. Estimated Baseline Emissions from EGUs

Emissions in 2002 

(1000 tons/year)

Projected emissions in 

2018 (1000 tons/year)

Table 5.1-1. Estimated Allowable Emissions Under the 

EGU1 and EGU2 Control Strategies

Projected baseline in 2018Emissions (1000 tons/year)Emissions with EGU1 caps (1000 tons/year)Fossil fuel consumption (trillion BTU)Emissions with EGU2 caps (1000 tons/year)

25
26

5.1.1 Factor 1 – Costs

In analyzing the cost of EGU control strategies, we began with the 2006 National Electric

Energy System Database (NEEDS) coupled with detailed projection outputs from the IPM 20

model. The NEEDS database contains data on the pollution control equipment currently 21

installed, as well as the electric generating capacity and heat rate for each EGU. IPM projects the

total fuel usage for each EGU in 2018, and gives an estimate of where additional control devices

will be installed between now and 2018 to meet on-the-books regulations. IPM is a dynamic

optimization model which identifies the lowest cost method of complying with air pollution

regulations while meeting electric generation requirements. The model analyzes the costs of a

number of possible pollution controls, and also the potential for reducing emissions by fuel

switching or inter-utility transfers, taking into account transmission bottlenecks, fuel supply

constraints and operational constraints.

We drew on control device cost equations used in IPM to estimate the region-wide costs

of complying with the EGU1 and EGU2 strategies. (These cost equations are included in 22

Appendix C.) This approach was chosen since the IPM model is commonly used to estimate the

costs of large-scale pollution control programs. In addition, recent IPM analyses of the CAIR

program have undergone extensive review. The following control options were included:

! For SO :2

" Limestone forced oxidation (LSFO) scrubbers

" Lime spray dryer (LSD) scrubbers 

! For NO : X

" Selective catalytic reduction (SCR)

" Selective non-catalytic reduction (SNCR)

" Low-NO burners (LNB) with and without overfire air (OFA) for dry-bottom wall- X

fired boilers

" Low-NO nozzles with close-coupled and separated overfire air for tangentially- X

fired boilers

A more exhaustive list of potential control technologies is provided in Appendix B. The options

in the above list were selected because, alone or in combination, they are generally of capable of

achieving the emission reductions needed under the EGU1 and EGU2 control strategies. 

(Appendix C gives the efficiencies assumed for the above options in the EGU analysis.)

The IPM control cost equations give the costs of installing and operating these

technologies on a particular EGU based on the electric generating capacity of the unit, its boiler

heat rate, and its average annual fuel use. Separate equations are used for capital costs, fixed

operation and maintenance costs, and variable operation and maintenance costs (depending on

fuel usage). We used these equations to estimate the cost of controlling each EGU in the region

with each technology. In amortizing capital costs, we used a 7% interest rate, with additional

capital charges of 1% per year for insurance, 1% per year for property taxes, and 2% per year for

general and administrative charges. After estimating annualized control costs and potential

emission reductions for all of the units in the region, we sorted the control options for the

different EGUs in order of increasing cost-effectiveness. We then identified the least expensive
27

sets of control technologies for achieving the EGU1 and EGU2 caps in the three-state and ninestate regions, and summed the costs of these controls. This approach was designed to take into

account the potential for trading emission credits among sources. However, it must be noted that

it does not take into account fuel switching or other secondary impacts. In addition, the cost

estimates do not take into account potential constraints that may exist for installing various

control technologies at specific facilities. Therefore, the results reflect only an estimate of the

costs which would be incurred to attain the EGU1 or EGU2 emission reduction targets.

Table 5.1-3 details the estimated costs of achieving the EGU1 SO emission cap in the 2

three-state and nine-state regions. The table shows the total generating capacity which is

expected to require control, the total emission reduction, the installed capital cost, the total 

annual cost of control (including capital amortization and operating costs), the average cost

effectiveness of control technologies, and the estimated range of cost-effectiveness values for

facilities in the region. In addition to the total costs and average cost-effectiveness values for

achieving the EGU1 SO emission cap the three-state and nine-state regions, Table 5.1-3 also 2

estimates the breakdown of costs among individual states. Table 5.1-4 provides similar cost

estimates for achieving the EGU1 NO emission cap in the three-state and nine-state regions. X

Tables 5.1-5 and 5.1-6 estimate the costs of achieving the EGU2 caps for SO and NO , 2 X

respectively.

It should be noted that the EGU1 strategy, as analyzed here, would allow trading of

emission credits across state boundaries within the three-state or the nine-state region. Therefore,

the state-specific costs in Table 5.1-3 through 5.1-6 only reflect our best estimate of how control

costs would be distributed. In addition, as has been noted earlier, these cost estimates were

developed using baseline emissions from the VISTAS 2.1.9 version of IPM, which was

developed in July 2005. In January 2007, EPA prepared new EGU projections (i.e., 3.0 version

of IPM), which would reflect lower baseline emissions in the 3-state region. Thus, annual costs

to achieve the EGU1 and EGU2 targets in the 3-state region could be lower than the estimates

given in Tables 5.1-3 through 5.1-6. However, since the most cost-effective controls may have

already been implemented to achieve the CAIR baseline in the 3-state region, costs per ton of

emission reduction to achieve the EGU1 and EGU2 levels could be higher than the estimates

given in Tables 5.1-3 through 5.1-6.

Eleven electric generating facilities were selected for more in-depth analyses. Many of

these facilities include multiple boilers, so that a total of 35 individual boilers were analyzed. 

For these plant-specific analyses, we again estimated costs using the IPM cost equations, and also

drew on additional data sources. Appendix C gives detailed estimates of capital costs and

annualized costs for each individual unit. The individual facility analyses show that control cost

estimates for any particular facility can vary by at least a factor of 2. There are a number of

reasons for this range of cost estimates. First, all of the costing approaches rely on default

assumptions for flue gas conditions, and for retrofit costs and other contingency costs, which may

differ from model to model. The cost models also use different inflation factors when updating

older cost data, and different scaling factors to calculate costs for various boiler sizes.
LSFO LSD Average Range

3-State Region

Michigan 2 37 10,441 335 1,764,626 478,652 1,428 1,000 - 2,700Minnesota 0 10 593 22 140,119 39,074 1,759 1,400 - 2,600Wisconsin 0 25 3,762 108 727,136 199,563 1,840 830 - 2,600 Total 2 72 14,796 466 2,631,881 717,289 1,540 830 - 2,700

9-State Region

Illinois 1 21 5,831 122 1,012,296 271,060 2,220 660 - 2,800Indiana 6 31 7,737 226 1,468,135 393,705 1,744 600 - 2,900Iowa 2 13 4,693 108 767,809 204,844 1,893 630 - 2,600Michigan 2 40 10,599 341 1,816,190 494,297 1,451 1,000 - 2,800Minnesota 1 15 1,357 42 327,549 94,410 2,254 1,400 - 2,900Missouri 2 29 9,243 229 1,469,386 399,666 1,744 610 - 2,800North Dakota 5 4 2,910 90 580,261 145,701 1,617 560 - 2,700South Dakota 0 2 477 11 77,464 20,801 1,913 1880 - 1,900Wisconsin 0 26 3,811 110 743,632 204,501 1,856 830 - 2,900 Total 19 181 46,658 1,279 8,262,722 2,228,985 1,743 560 - 2,900

SCR LNB Average Range

3-State Region

Michigan 7 4 5,675 42 315,643 75,466 1,785 1,100 - 2,700Minnesota 5 4 3,175 16 115,282 36,673 2,236 520 - 3,400Wisconsin 8 8 1,763 12 148,964 32,799 2,626 1,700 - 3,400 Total 20 16 10,613 71 579,889 144,938 2,037 520 - 3,400

9-State Region

Illinois 3 6 3,046 8 83,671 17,512 2,167 1,000 - 2,600Indiana 9 1 5,531 32 196,829 72,760 2,304 820 - 3,000Iowa 6 8 4,164 20 120,473 47,061 2,359 1,100 - 3,300Michigan 7 4 5,675 42 315,643 75,466 1,785 1,100 - 2,700Minnesota 1 4 3,171 15 62,982 31,038 2,103 520 - 3,200Missouri 13 2 3,475 25 165,185 46,975 1,904 690 - 3,000North Dakota 7 0 4,122 59 331,283 70,345 1,198 760 - 3,300South Dakota 1 0 477 13 53,045 10,038 775 760 - 2,300Wisconsin 7 8 1,577 11 128,463 28,068 2,536 1,700 - 3,300 Total 54 33 31,238 224 1,457,574 399,263 1,782 520 - 3,300

Estimated numbers of 

boilers needing 

control

Total 

capacity 

controlled 

(MW)

Cost effectiveness ($/ton)

Table 5.1-3. Estimated Costs of EGU1 SO2 Controls for the 3-State and 9-State Regions*

Table 5.1-4. Estimated Costs of EGU1 NOx Controls for the 3-State and 9-State Regions*

Emission 

reduction 

(1000 tons 

/year)

Capital cost 

($1000)

* These results do not take into account fuel switching or other secondary impacts, or potential constraints that may exist for installing various control technologies at specific facilities. Additionally, the EGU1 strategy, as analyzed here, would allow trading of emission credits across state boundaries within the three-state or the nine-state region. Thus, the results reflect only an estimate of the costs which would be incurred to attain the EGU1 or EGU2 emission reduction targets.

Total annual 

cost ($1000)

Total annual 

cost ($1000)

Cost effectiveness ($/ton)

Total 

capacity 

controlled 

(MW)

Emission 

reduction 

(1000 tons 

/year)

Capital cost 

($1000)

Estimated numbers of 

boilers needing 

control

28
LSFO LSD Average Range

3-State Region

Michigan 5 49 11,021 357 2,018,086 553,751 1,552 1,100 - 4,200Minnesota 2 19 2,620 57 543,859 155,016 2,743 1,400 - 4,400Wisconsin 0 32 4,245 119 842,255 235,523 1,981 830 - 4,200 Total 7 100 17,886 532 3,404,200 944,290 1,775 830 - 4,400

9-State Region

Illinois 2 37 9,659 183 1,796,774 466,945 2,557 660 - 4,200Indiana 13 37 11,545 282 2,223,006 594,395 2,108 600 - 4,300Iowa 2 25 5,229 122 940,070 253,579 2,074 630 - 4,100Michigan 5 49 11,021 357 2,018,086 553,751 1,552 1,100 - 4,200Minnesota 1 19 1,684 48 417,317 118,964 2,466 1,400 - 4,300Missouri 2 34 9,942 240 1,637,082 441,007 1,835 610 - 4,100North Dakota 5 6 2,998 93 610,686 154,657 1,668 560 - 3,600South Dakota 0 2 477 11 77,464 20,801 1,913 1,900 - 1,900Wisconsin 0 32 4,245 119 842,255 235,523 1,981 830 - 4,200 Total 30 241 56,800 1,455 10,562,740 2,839,622 1,952 560 - 4,300

SCR LNB Average Range

3-State Region

Michigan 38 0 8,012 60 898,882 164,478 2,734 1,100 - 7,000Minnesota 25 2 4,045 26 467,345 86,734 3,298 1,700 - 7,000Wisconsin 30 0 2,642 20 384,069 69,821 3,495 1,800 - 5,900 Total 93 2 14,699 106 1,750,296 321,033 3,016 1,100 - 7,000

9-State Region

Illinois 21 0 7,779 22 671,404 124,833 5,605 1,500 - 9,700Indiana 38 0 5,821 46 753,961 138,817 3,036 820 - 8,600Iowa 37 3 6,043 35 686,966 125,254 3,580 1,100 - 9,100Michigan 39 0 8,036 60 911,972 166,300 2,754 1,100 - 7,300Minnesota 29 0 4,045 27 514,675 94,752 3,456 1,700 - 8,200Missouri 33 0 5,007 37 636,464 117,302 3,162 1,000 - 9,800North Dakota 15 0 4,129 62 494,697 90,497 1,459 760 - 5,500South Dakota 2 0 477 13 56,906 10,554 807 760 - 3,000Wisconsin 40 0 4,173 25 610,076 110,532 4,418 1,800 - 8,600 Total 254 3 45,510 328 5,337,121 978,841 2,984 760 - 9,800

* These results do not take into account fuel switching or other secondary impacts, or potential constraints that may exist for installing various control technologies at specific facilities. Thus, they reflect only an estimate of the costs which would be incurred to attain the EGU1 or EGU2 emission reduction targets.

Cost effectiveness ($/ton)

Total annual Cost effectiveness ($/ton)

cost ($1000)

Table 5.1-5. Estimated Costs of EGU2 SO2 Controls for the 3-State and 9-State Regions*

Table 5.1-6. Estimated Costs of EGU2 NOx Controls for the 3-State and 9-State Regions*

Estimated numbers of 

boilers needing 

control

Total 

capacity 

controlled 

(MW)

Emission 

reduction 

(1000 tons 

/year)

Capital cost 

($1000)

Total annual 

cost ($1000)

Estimated numbers of 

boilers needing 

control

Total 

capacity 

controlled 

(MW)

Emission 

reduction 

(1000 tons 

/year)

Capital cost 

($1000)

29
30

The analysis in Appendix C does not include other progress factors besides cost (e.g. time

required for compliance, energy and other impacts, and remaining equipment life). In addition,

these analyses do not represent definitive assessments of what controls would be appropriate for

the selected individual facilities.

5.1.2 Factor 2 – Time Required for Compliance

Once a control strategy is selected, up to 2 years will be needed for states to develop the

necessary rules to implement the strategy. We have estimated that sources may then require up 

to a year to procure the necessary capital to purchase control equipment. The Institute of Clean

Air Companies (ICAC) has estimated that approximately 13 months is required to design,

X

fabricate, and install SCR or SNCR technology for NO control. However, state regulators’ 23

experience indicates that closer to 18 months is required to install this technology. In the CAIR 24

analysis, EPA estimated that approximately 30 months is required to design, build, and install

SO scrubbing technology for a single EGU boiler. The analysis also estimated that up to an 2

additional 12 months may be required for staging the installation process if multiple boilers are to

be controlled at a single facility. Based on these figures, the total time required for a single

2

facility to comply with one of the SO caps would be 61⁄2 years, in the absence of any constraints

on the capacity to produce and install scrubbers. The total time for a single facility to comply

with one of the NO caps would be about 51⁄2 years. X

Some stakeholders have commented that the large number of facilities requiring emission

add-on controls under a regional control strategy, coupled with the current requirements under

the CAIR program, would create a shortage of skilled laborers to build and install pollution

control equipment and required ancillary equipment, such as stacks. EPA analyzed such

constraints during the development of the CAIR rule. The Agency determined that the most

critical constraint would be the availability of “boilermaker” labor to build and install scrubbers,

SCR systems, and SNCR systems required under the rule. Therefore, EPA carried out a separate

analysis of boilermaker availability for the CAIR rule. EPA estimated that approximately 25

0.272 boilermaker-year/MW is required to fabricate and install scrubbers for SO , and 2

approximately 0.344 boilermaker-year/MW is required to fabricate and install SCR technology

X

for NO .

EPA also estimated that the tightest constraint on available boilermaker labor for the

CAIR program will occur prior to the 2010 interim deadline. Because of the 2 years of lead time

required to develop regulations to implement a regional EGU strategy and the additional year

needed for capital procurement, the boilermaker demands under the EGU1 or EGU2 control

strategies would occur after 2010. Based on the boilermaker availability information given in the

CAIR analysis, an estimated boilermaker-year/year will be available after 2010 for building and

installing pollution control equipment, beyond the equipment being built for Phase II of the

CAIR program. This labor supply would be adequate for all of the possible Midwest EGU

control strategies, with the exception of the EGU2 caps over the nine-state region. For the EGU2

cap over the nine-state region, we estimate that shortage of boilermaker labor could potentially

extend the time required for compliance to 7 years (instead of 61⁄2).
31

Based on the above figures, any of the EGU control strategies could be fully implemented

by 2018. However, none of the strategies could be implemented by 2012.

5.1.3 Factor 3 – Energy and Other Impacts

Scrubbers, SCR systems, and SNCR systems installed under the EGU control strategies

would require electricity to operate fans and other ancillary equipment. In addition, steam would

be required for some scrubbers and SCR systems. Additional fuel will be consumed at the

utilities to produce this electricity and steam, resulting in the generation of additional carbon

dioxide (CO ) emissions. CO is also released in the production of lime for LSD control systems 2 2

2

in the SO –limestone reaction in LSFO control systems.

We estimated the energy usage for EGU control technologies based on electricity and

2

steam consumption rates given in the CUECost model. The amount of increased CO was

estimated based on these increased electricity and steam demands, and on lime and limestone

flowrates given in CUECost. Solid waste generation rates and wastewater generation rates were

also estimated from the waste and wastewater factors in CUECost. Table 5.1-7 presents the

estimated energy usage, waste generation rate, and wastewater generation rate per Megawatt of

generating capacity controlled. The factors in Table 5.1-7 were used to estimate category-wide

energy, solid waste, and wastewater impacts, which are summarized in Table 5.1-8. 

As Table 5.1-8 shows, the electricity and steam required by controls installed to meet SO2

and NO emission caps would be less than 1% of the total electricity and steam production of X

EGUs in the region. Solid waste disposal and wastewater treatment costs are expected to be less

than 5% of the total operating costs of pollution control equipment. 

The SO and NO controls would have beneficial environmental impacts by reducing acid 2 X

deposition and nitrogen deposition to water bodies and natural landscapes. Reductions in these

gaseous pollutants are designed to reduce formation of fine particles that impair visibility. Such

2.5 reductions would also result in decreases in the ambient levels of PM , with corresponding

health benefits. In addition, broad regional reductions in NO would result in reductions in X

background levels of ambient ozone. These reductions in PM and ozone will reduce levels of 2.5

these pollutants in urban areas, and improve the potential for urban areas in the Midwest and

Northeast to attain the National Ambient Air Quality Standards (NAAQS).

The MRPO carried out a previous modeling effort to evaluate the benefits of

implementing the EGU1 and EGU2 emission caps over the 5-state MRPO region by 2012. In

2.5 this study, the CAMx model was used to estimate reductions in ambient levels of PM and

ozone as a result of SO and NO emission reductions. The EPA Environmental Benefits 2 X

Mapping and Analysis Program (BenMAP) was used to quantify health benefits. These benefits

would occur not just in the region where emissions limitations are implemented, but also in areas

downwind of this region. Table 5.1-9 summarizes the estimated benefits of implementing the

EGU1 and EGU2 caps in the 5-state MRPO region. The table shows benefits both in the MRPO

region, and in the modeling domain as a whole, including downwind areas.
Pollution control technique and 

impact produced

Magnitude of 

impact Units

LSD

Sludge 3.7 ton sludge / ton of SO2 reducedElectricity 7.0 kW / MW generating capacityCO2 for electricity 1.0 ton CO2 / MW-hr additional electricity neededCO2 to produce lime 0.69 ton CO2 / ton of SO2 reduced

LSFO

Sludge 2.8 ton sludge / ton of SO2 reducedElectricity 20 kW / MW generating capacitySteam 114 lb steam / MW-hr of electricity producedWastewater 3.7 1000 gal / ton SO2 emission reducedCO2 for electricity 1.0 ton CO2 / MW-hr additional electricity neededCO2 for steam 0.26 ton CO2 / ton of additional steam neededCO2 for control reaction 0.69 ton CO2 / ton of SO2 reduced

SCR

Sludge 0.10 ton sludge / kW-hr or electricity generatedElectricity 3.0 kW / MW generating capacitySteam 2.1 lb steam / MW-hr of electricity producedCO2 for electricity 1.0 ton CO2 / MW-hr additional electricity neededCO2 for steam 0.26 ton CO2 / ton of additional steam needed

Table 5.1-7. Factors Used to Calculate Energy and Non-Air 

Environmental Impacts of EGU Control Measures

32
Emission 

reduction (1000 

tons/year)

Additional 

electricity 

requirements 

(GW-hrs /year)

Steam 

requirements 

(1000 tons/yr)

Solid waste 

produced 

(1000 

tons/year)

Wastewater 

produced 

(million 

gallons/year)

Addit

CO2 em

(10

tons/y

EGU1 Emission Caps

3-State Region

SO2 466 706 510 1,323 192 1,0NOX 71 40 17 1.7 0 

Total 537 746 526 1,324 192 1,1

9-State Region

SO2 1,279 2,649 3,462 3,632 1,128 3,6NOX 224 110 46 4.6 0 1Total 1,503 2,759 3,508 3,637 1,128 3,7

EGU2 Emission Caps

3-State Region

SO2 532 1,106 1,722 1,511 237 1,5NOX 106 174 73 7.3 0 1Total 639 1,279 1,795 1,519 237 1,3

9-State Region

SO2 1,455 3,504 5,439 4,132 1,919 4,6NOX 328 608 255 25.4 0 6Total 1,783 4,113 5,695 4,157 1,919 5,3

Table 5.1-8. Estimated Energy and Non-Air Environmental Impacts of EGU Cont

Strategies

33
Health effect

Number of 

cases avoided

Value of 

benefit 

($1000)

Number of 

cases avoided

Value of 

benefit 

($1000)

Number of 

cases avoided

Value of 

benefit 

($1000)

Acute bronchitis 2,700 1,100 5,000 2,100 3,200 1,300 Acute myocardial infarction 3,400 270,000 6,100 480,000 3,900 310,000 Acute respiratory symptoms 1,223,000 140,000 2,168,000 250,000 1,473,000 170,000 Asthma exacerbation 73,300 3,700 131,400 6,700 86,200 4,400 Chronic bronchitis 1,000 410,000 1,900 770,000 1,200 480,000 Emergency room visits for respiratory symptoms 2,100 790 3,400 1,200 2,500 930 Hospital admissions for cardiovascular symptoms 600 15,000 1,200 29,000 700 18,000 Hospital admissions for respiratory symptoms 1,100 19,000 1,900 32,000 1,400 23,000 Lower respiratory symptoms 29,000 540 52,100 960 34,000 630 Premature mortality 1,570 10,000,000 3,010 20,000,000 1,860 12,000,000 School loss days 27,600 2,500 33,500 3,000 45,600 4,100 Work loss days 192,600 31,000 348,300 55,000 226,200 36,000 Worker productivity loss 960 1,300 1,700 

Total 11,000,000 22,000,000 13,000,000 Source: Stratus benefits studyNotes:

Benefit values have been updated to 2005 dollars.These estimates are taken from a study of the application of the EGU1 and EGU2 emission caps over a five-State region, including Illinois, InWisconsin

Table 5.1-9. Estimated Annual Health Benefits of EGU Control Strategies Applied to the 5-State 

EGU1 Control Strategy EGU2 Con

Benefits in the MRPO region

 Total benefits in the MRPO 

region and downwind 

regions Benefits in the MRPO region

34
Predicted emission reductions for the 5-state region outweigh those for the 9-state region for two reasons. a

First, the earlier study was performed for the year 2012, five years earlier in the implementation of the CAIR rule. 

Second, emissions from Ohio are large in comparison with the states that replace it in the 9-state region – Iowa,

Minnesota, Missouri, North Dakota, and South Dakota.

35

The 5-state region analyzed in the benefits study included Michigan, Wisconsin, Illinois,

2

Indiana, and Ohio. The estimated SO emission reductions for this region were about 10%

greater than the emission reductions estimated for the 9-state region in the current study. The a

estimated NO emission reductions for the 5 region were midway between the emission X

reduction estimates for the 3-state region and the 9-state region analyzed in the current study.

Although the earlier study is not directly comparable to the current analysis, it provides an

indication of the magnitudes of health benefits in comparison to costs. When benefits in the

entire modeling domain were considered, the estimated values of these benefits outweighed the

projected costs of control by more than a factor of 10 for both the EGU1 and EGU2 strategies. 

When only benefits in the MRPO were considered, the predicted benefit values exceeded

estimated costs by a factor of 6.

5.1.4 Factor 4 – Remaining Equipment Life

In calculating the costs of control, amortization periods were assumed to be 15 years for

LSFO and LSD, and 20 years for SCR, SNCR, and low-NO combustion modifications. The X

purpose of the Factor 4 analysis is to evaluate the increases in annualized costs that would occur

in cases where the remaining life of the emission source is less than the amortization period for

potential control equipment.

It is difficult to quantify the remaining equipment life for EGUs. Many units have been

refurbished multiple times. In the Midwest region, more than 150 units are over 60 years old,

and some units are more than 80 years old. In addition, since the EGU strategies are 20

market-based caps to be applied to a broad geographic region, it is assumed that controls will be

not be applied to units that are expected to be retired prior to the amortization period for the

control equipment. Therefore, remaining equipment life is not expected to be an important factor

for EGUs.

5.1.5 Factor 5 – Visibility Impacts

Table 5.1-10 presents the estimated visibility impacts at the four northern-Midwest

Class I areas for the EGU control strategies implemented over the three-state region and the nine2 X state region. Results are presented separately for the SO and NO caps. In addition, visibility

impacts are presented in terms of deciviews and in terms of the change in emissions per distance

(Q/d). 

Table 5.1-11 estimates the cost effectiveness of EGU controls, expressed in terms of cost

per visibility improvement. It must be noted that the estimates of visibility improvement are

subject to considerable uncertainty. These are based on rollback calculations using the results of

PSAT analyses and CAMx sensitivity analysis. These rollback calculations provide a
36

mechanism for evaluating the relative impacts of different strategies. However, they may overestimate or under-estimate the impacts of NO controls relative to SO controls. More detailed X 2

modeling using CAMx or other photochemical models is needed to fully quantify the impact of

any given control strategy.
Strategy and region

Boundary 

Waters

Voyageurs Isle Royale Seney Average Boundary Waters Voya- geurs Isle Royale Sene

EGU1 Emission Caps

3-State Region

SO2 0.30 0.12 0.44 0.41 0.32 1,383 1,135 1,476 1,7

NOX 0.07 0.05 0.06 0.04 0.06 302 244 287 3Total 0.38 0.17 0.50 0.45 0.37 1,685 1,378 1,762 2,0

9-State Region

SO2 0.77 0.35 0.84 1.01 0.74 2,961 2,661 3,036 3,3

NOX 0.18 0.24 0.15 0.12 0.17 604 555 565 5Total 0.95 0.59 1.00 1.13 0.92 3,565 3,216 3,601 3,9

EGU2 Emission Caps

3-State Region

SO2 0.46 0.21 0.52 0.46 0.41 1,647 1,385 1,760 2,0NOX 0.12 0.08 0.09 0.07 0.09 467 365 431 4Total 0.58 0.29 0.61 0.53 0.50 2,114 1,750 2,191 2,4

9-State Region

SO2 0.87 0.40 0.96 1.18 0.85 3,274 2,948 3,432 3,8NOX 0.26 0.30 0.23 0.19 0.24 918 819 858 8Total 1.13 0.69 1.18 1.37 1.09 4,192 3,767 4,291 4,7

Table 5.1-10. Estimated Visibility Impacts of EGU Control Strategies

*Q/d reflects the summation of the ratios of emissions to distance for individual sources in each region.

Estimated visibility improvement in 2018 

(deciviews)

Reductions in the summations of em

distance ratios (Q/d; tons/yr-m

37
Strategy and region

Cost effectiveness 

per visibility 

improvement 

($million/ 

deciview)

Cost 

effectiveness per 

change in Q/d 

($1000-mi/ton)*

EGU1 Emission Caps

3-State Region

SO2 2,249 499

NOX 2,585 508

Total 1,581 603

9-State Region

SO2 2,994 740

NOX 2,332 695

Total 2,177 733

EGU2 Emission Caps

3-State Region

SO2 2,281 553

NOX 3,604 748

Total 1,462 592

9-State Region

SO2 3,336 843

NOX 4,045 1,128

Total 2,578 901

*Q/d reflects the summation of the ratios of emissions to 

distance for individual sources in each region.

Table 5.1-11. Cost Effectiveness of EGU 

Control Strategies in Terms of Visibility 

Improvement

38
39

5.2 Industrial, Commercial, and Institutional Boilers

Source apportionment analyses identify SO and NO emissions from non-EGU point 2 X

sources as the second largest contributor to visibility impairment in Boundary Waters, Seney, and

Voyageurs, and the third largest contributor to visibility impairment in Isle Royale in 2018. ICI 7

boilers account for a large portion of SO and NO emission from non-EGU point sources. 2 X

Potential SO and NO regional control strategies and unit-level control technologies for 2 X

coal-, oil-, and gas-fired boilers are presented in Appendix B. From this list, the states identified

2 X two market-based control strategies that would reduce ICI boiler SO and NO emissions beyond

on-the-books controls. Both strategies target medium and large boilers (i.e., having a design

capacity at least 100 Mmbtu/hr, or emitting at least 100 tons/year of either NO or SO ). Coal- X 2

fired boilers were examined in particular, as they are estimated to contribute the largest fraction

of SO and NO boiler state-wide emissions in 2018. 2 X

The first strategy was adopted from Candidate Measure ID ICI1 in the ICI boiler white

paper, and requires a 40% SO reduction and a 60% NO reduction from 2018 baseline 2 X

26

emissions. Similar to EGU1, this strategy was previously analyzed for the 5-state MRPO region

with compliance timelines of 2009 and 2013. For this analysis, we have re-defined the

compliance timeline to 2018 and the geographic region to the states identified in Figure 3-1.

The second strategy (referred to as the ICI Workgroup Strategy) was prepared by the

MRPO’s Strategy Workgroup and identifies specific SO and NO emissions limitations as a 2 X

function of boiler type and size, and fuel type (see Table 5.2-3). This strategy provides

approximately a 77% reduction in SO emissions and a 70% reduction in NO emissions. 2 X

To achieve these reductions, the following control technologies were analyzed:

! For SO :2

" Spray-dry absorbers (SDA) (90% control)

" Fuel switching for oil-fired boilers

! For NO : X

" SCR for coal-fired boilers (80% control)

" LNB with OFA and Gas Reburn (80% control) for gas-fired boilers

" SCR (80% control) for oil-fired boilers

Table 5.2-1 provides a comparison of 2002 and 2018 SO baseline emissions for ICI 2

boilers from area and point sources. The table also presents the contribution of medium and

large boilers to the overall ICI boiler inventory, along with a comparison of emissions under the

proposed emission reduction strategies. Table 5.2-2 gives a similar summary for NO . ICI X

emissions from point sources contribute 63% of total SO ICI emissions, and 57% of total NO 2 X

ICI emissions in the 9-state region. 

Figure 5.2-1 presents a comparison of emissions under the proposed reduction strategies. 

Figure 5.2-2 shows the fraction of point source emissions from medium and large boilers by fuel

type for Illinois, Indiana, Michigan, Minnesota, and Wisconsin. Figure 5.2-2 indicates that the

majority of point source emissions can be attributed to solid fuel-fired medium and large boilers.
SO2 emissions 

from ICI sources 

in 2002 (1000 

tons/year) [a]

Projected SO2 

emissions from 

ICI sources in 

2018 (1000 

tons/year) [a]

Fraction of ICI 

SO2 emissions 

from ICI point 

sources

Projected SO2 

2018 Baseline 

(Boilers > 100 

MmBtu/Hr)

Estimated 

Allowable 

Emissions 

Under ICI1

Estimated 

Allowable 

Emissions 

Under ICI 

Workgroup

Michigan 44.2 42.8 44%

Minnesota 20.2 19.7 40%

Wisconsin 57.0 54.8 95%

3-State Subtotal 121.5 117.2 67% 69 41 16 

Illinois 58.9 59.0 96%

Indiana 108.9 105.2 48%

Iowa 32.2 30.6 100%

Missouri 53.0 52.5 19%

North Dakota 7.6 7.2 not avail.

South Dakota 0.7 0.7 not avail.

9-State Total 382.8 372.3 63% 220 132 51 

NOX emissions 

from ICI sources 

in 2002 (1000 

tons/year) [a]

Projected NOX 

emissions from 

ICI sources in 

2018 (1000 

tons/year) [a]

Fraction of ICI 

NOX 

emissions from 

ICI point 

sources

Projected 

NOX 2018 

Baseline 

(Boilers > 100 

MmBtu/Hr)

Estimated 

Allowable 

Emissions 

Under ICI1

Estimated 

Allowable 

Emissions 

Under ICI 

Workgroup

Michigan 27.0 26.5 60%

Minnesota 52.9 52.7 18%

Wisconsin 34.5 33.9 68%

3-State Subtotal 114.4 113.1 43% 37 15 11 

Illinois 49.5 48.0 73%

Indiana 54.2 52.5 69%

Iowa 16.3 16.2 100%

Missouri 18.8 18.7 23%

North Dakota 5.1 5.1 not avail.

South Dakota 0.3 0.3 not avail.

9-State Total 258.7 253.9 57% 122 49 36 

Table 5.2-2. Estimated Point and Area Source NOX Emissions from ICI Boilers 

[a] Includes emissions from all boiler sizes (< 50 MMBTU/Hr to > 250 MMBTU/HR)

Table 5.2-1. Estimated Point and Area Source SO2 Emissions from ICI Boilers

40
Projected NOX Emissions From ICI Boilers

0

50

100

150

200

250

300

2018 Baseline

3-State

ICI1 2018 Baseline

9-State

ICI1

Emissions Scenario By Region

Emissions (tons/year)

Area

Point

Figure 5.2-1. Projected SO2 Emissions From ICI Boilers

0

50

100

150

200

250

300

350

400

450

2018 Baseline

3-State

ICI1 2018 Baseline

9-State

ICI1

Emissions (tons/year)

Emissions Scenario By Region

Area

Point

41
*Note: While NOX emissions from medium and large boilers in Minnesota are predominately from solid fuel-fired boilers, emissions 

from small boilers are predominately from gas-fired boilers. Cumulatively, gas-fired NOX emissions predominate in Minnesota.

*

42
<50 millionbtu/hr 50-100 million- btu/hr 100 - 250 million-btu/hr >250 million- btu/hr

Natural Gas and other gaseous fuels

Combustion 

tuning

0.06 0.06

Fuel Oil (#2 – distillate) " 0.10 0.10

Fuel Oil (#6 – residual) " 0.20 0.20Coal-Wall " 0.14 0.14

Coal-Tangential " 0.12 0.12

Coal-Stoker " 0.22 0.22

Coal-FBC " 0.08 0.08Wood/Non-Fossil solid Fuel " 0.22 0.22

Distillate Oil (#1, #2)

Residual Oil (#4, #5, #6)Coal (and other solid fuels) 2.0 or 30% 1.2 or 85% 0.25 or 85%

Fuel Growth Factor

Gas-fired 1.02Oil-fired 1.01Solid fuel 1.01Coal 0.93Gas-fired 1.02Oil-fired 0.97Solid fuel 0.89Coal 0.93

Table 5.2-3. ICI Workgroup Proposed Emission Caps

Boiler and Fuel Type

Suggested Limit (lb/MMBTU)

Proposed NOx Emission Targets

SO2

Proposed SO2 Emission Targets

0.05% sulfur by weight 

0.5% sulfur by weight

Table 5.2-4. Average 

Growth Factors for the 

MRPO Region 

NOX

43
44

Baseline emissions for the 9-State region were calculated using the following information:

! Illinois, Indiana, Michigan and Wisconsin 2018 emissions summaries were obtained at

the state level by fuel type and categorized into medium and large boiler sizes using

percentages from 2002 emission summaries obtained from LADCO. Total emission 27

units were scaled to 2018 units using average growthfactors from the MRPO inventory.28

! Minnesota Pollution Control Agency provided 2002 unit-level emissions, which were

scaled to 2018 emissions using average growth factors from the MRPO inventory. 

Reported throughput was assumed to be 65% of total design capacity.

! Iowa, Missouri, and North and South Dakota unit-level emissions were obtained from the

2002 National Emission Inventory (NEI) and scaled to 2018 emissions using average

growth factors from the MRPO inventory. Reported throughput was assumed to be 65%

of total design capacity.

Table 5.2-4 shows the average growth and control factors used to scale 2002 emissions to 2018. 

5.2.1 Factor 1 – Costs

In analyzing costs for retrofit technology (e.g., SDA, SCR, and LNB/OFA/GR), we

developed cost curves using the SO and NO control cost methodology developed by EPA for 2 X

industrial boilers. This approach was chosen because it provided the most detailed cost 29,30

analysis for ICI boilers, and has been used in other cost analyses. The IPM approach used for

EGUs was not used here because it applies to larger boiler sizes. The EPA ICI boiler cost

documentation provides design parameters, economic factors, and initial investment for the

control technologies under analysis. Initial capital investment was scaled to 2005 dollars using

the Chemical Engineering Index. Fuel and energy costs were obtained in 2005 dollars from the

Energy Information Administration (EIA), and operator costs were obtained from the Bureau of

Labor and Statistics. Other economic factors (e.g., solid waste disposal, energy, catalyst) were

obtained in 2005 dollars from CUECost. The NACAA menu of control options was also used as

a point of comparison for cost estimates. This document gives estimates of potential control cost

effectiveness for broad ranges of boiler sizes.6

In analyzing costs for fuel switching in oil-fired boilers, we obtained fuel cost information

from the NACAA document. The incremental annual fuel cost of switching from high to low 6

sulfur fuel was calculated based on the price per million Btu of distillate and residual oil. We did

not attempt to calculate the costs of any equipment changes that may be necessary to switch from

high to low sulfur oil. The SCC codes reported in the emission inventories indicate that the

majority of SO emissions come from residual oil-fired boilers, with the exception of Indiana. 2

Table 5.2-5 details the estimated costs of achieving the ICI1 SO emission cap in the 2

three-state and nine-state regions. The table shows the total emission reduction, the installed

capital cost, the total annual cost of control (including capital amortization and operating costs),

the average cost effectiveness of control technologies, and the estimated range of costeffectiveness values for facilities in the region. We did not attempt to estimate the total boiler

capacity controlled due to insufficient information in the inventories. Table 5.2-6 provides
45

X

similar cost estimates for achieving the ICI1 NO emission cap in the three-state and nine-state

2

regions. Tables 5.2-7 and 5.2-8 estimate the costs of achieving the ICI Workgroup caps for SO

and NO , respectively. X

The ICI1 Strategy for SO emissions can be achieved in the 3-State and 9-State region by 2

controlling coal-fired boilers with SDA and oil-fired boilers with fuel switching to a lower sulfur

X

fuel. The strategy for NO emissions can be achieved by controlling coal- and oil-fired boilers

with SCR, and gas-fired boilers with LNB/OFA/GR. In the 3-State region, cost effectiveness

2 X ranges between $1,944 - $3,021 per ton of SO reduced and $1,149 - $5,478 per ton of NO

2

reduced. In the 9-State region, cost effectiveness ranges between $1,194 - $2,696 per ton of SO

X X reduced, and $699 - $3,911 per ton of NO reduced. The NO ranges fall within costeffectiveness ranges reported in the NACAA report.6

The ICI Workgroup Strategy for SO emissions can be achieved by controlling coal-fired 2

boilers with SDA and oil-fired boilers with fuel switching to a lower sulfur fuel. The strategy for

NO emissions can be achieved by controlling coal- and oil-fired boilers with SCR, and gas-fired X

boilers with LNB/OFA/GR. In the 3-State region, cost effectiveness ranges between

$1,944 - $6,584 per ton of SO reduced, and $1,149 - $9,250 per ton of NO reduced. In the 2 X

9-State region, cost effectiveness ranges between $1,194 - $9,403 per ton of SO reduced and 2

$699 - $5,488 per ton of NO reduced. These values are above the ranges given in the NACAA X

report, in terms of the cost per ton of emission reduction. This is because our projections

indicate that this strategy may require control of smaller emission sources, which are outside of

the boiler size ranges analyzed in the NACAA report.

Individual facility analyses used the same EPA cost equations derived for the sector-level

analysis, and also drew on a number of additional data sources (similar to the EGU analyses).

However, the ICI facility analyses omit the use of CUECost because the model is only applicable

to units $ 100 MW. See Appendix C for the results of the individual facility factor analysis. The

analysis in Appendix C does not include an analysis for time required for compliance, energy and

other impacts, or remaining equipment life. In addition, this analysis does not represent

assessments of BART for the selected individual facility.
Fuel Type

Control 

Technology

Potential 

Emission 

Reduction (1000 

Tons/yr)

Average Capital 

Costs ($1000)

Average O&M 

Cost ($1000)

Average 

Annualized Cost 

($1000)

 Average CostEffectiveness 

($/ton) 

Coal SDA 32 360,313 42,931 96,904 2,998 Oil Fuel Switching 1 -- -- 1,459 2,643 

 Grand Total 33 360,313 42,931 98,363 2,992 Coal SDA 93 749,979 98,544 210,887 2,258 Oil Fuel Switching 12 -- -- 27,800 2,414 Grand Total 105 749,979 98,544 238,687 2,275 

Fuel Type

Control 

Technology

Potential 

Emission 

Reduction (1000 

Tons/yr)

Average Capital 

Costs ($1000)

Average O&M 

Cost ($1000)

Average 

Annualized Cost 

($1000)

 Average CostEffectiveness 

($/ton) 

Coal SCR 19 181,776 21,043 45,472 2,410Gas LNB/OFA/GR 3 48,497 2,408 8,925 2,909Oil SCR 1 11,905 947 2,547 4,992

Grand Total 22 242,178 24,397 56,944 2,537 

Coal SCR 35 326,145 38,650 82,482 2,358Gas-fired LNB/OFA/GR 27 263,852 12,529 47,989 1,757Oil-fired SCR 11 36,835 3,647 8,598 785

Grand Total 73 626,833 54,827 139,068 1,899 

Table 5.2-5. Estimated Costs of ICI1 SO2 Controls for the 3-State and 9-State Reg

3-State Region

 9-State Region 

9-State Region

Table 5.2-6. Estimated Costs of ICI1 NOX Controls for the 3-State and 9-State Reg

3-State Region

46
Fuel Type

Control 

Technology

Potential 

Emission 

Reduction (1000 

Tons/yr)

Average Capital 

Costs ($1000)

Average O&M 

Cost ($1000)

Average 

Annualized Cost 

($1000)

 Average CostEffectiveness 

($/ton) 

Coal SDA 50 489,325 61,616 134,915 2,683Oil Fuel Switching 2 -- -- 8,579 3,779Grand Total 53 489,325 61,616 143,493 2,731 

 Coal SDA 145 1,549,160 194,981 427,037 2,953 Oil Fuel Switching 24 -- -- 35,739 1,482

Grand Total 169 1,549,160 194,981 462,776 2,743 

Fuel Type

Control 

Technology

Potential 

Emission 

Reduction (1000 

Tons/yr)

Average Capital 

Costs ($1000)

Average O&M 

Cost ($1000)

Average 

Annualized Cost 

($1000)

 Average CostEffectiveness 

($/ton) 

 Coal SCR 23 352,042 38,183 85,495 3,682Gas LNB/OFA/GR 5 108,523 4,984 19,569 4,103 Oil SCR 1 20,180 1,766 4,479 6,144 Grand Total 29 480,745 44,933 109,543 3,814 

 Coal SCR 45 508,902 60,083 128,476 2,879Gas LNB/OFA/GR 29 315,868 14,966 57,417 1,970 Oil SCR 11 48,741 4,594 11,145 972 Grand Total 85 873,511 79,643 197,038 2,311 

9-State Region3-State Region9-State Region

Table 5.2-7. Estimated Costs of ICI Workgroup SO2 Controls for the 3-State and 9-Stat

Table 5.2-8. Estimated Costs of ICI Workgroup NOX Controls for the 3-State and 9-Stat

3-State Region

47
48

5.2.2 Factor 2 – Time Necessary for Compliance

Similar to the EGU Factor 2 analysis, we estimate that a facility may achieve both ICI1

and the ICI Workgroup SO strategies in six and a half years, in the absence of any constraints on 2

the capacity to produce and install scrubbers. The total time for a single facility to comply with

one of the NO strategies would be about five and a half years. This estimate is based on the X

following information:

! Two years for rule development and implementation

! Up to a year for industry to procure the necessary capital to purchase control equipment.

! Eighteen months to design, fabricate, and install SCR or SNCR technology for NOX

control, and approximately 30 months to design, build, and install SO scrubbing 2

technology. 

! An additional 12 months for staging the installation process if multiple boilers are to be

controlled at a single facility. 

5.2.3 Factor 3 – Energy and Other Impacts

Similar to the EGU Factor 3 analysis, we estimated the energy usage for SDA and SCR

based on electricity and steam consumption rates given in the CUECost model. The amount of

2

increased CO was estimated based on these increased electricity and steam demands, and on

lime and limestone flowrates given in CUECost. Solid waste generation rates and wastewater

generation rates were also estimated from the waste and wastewater factors in CUECost. 

Electricity estimates for LNB/OFA/GR were obtained from the EPA ICI control report.28, 30, 30

Table 5.2-9 presents the estimated energy usage, waste generation rate, and wastewater

generation rate per ton of pollutant controlled. The factors in Table 5.2-9 were used to estimate

category-wide energy, solid waste, and wastewater impacts, which are summarized in

Table 5.2-10.

As Table 5.2-10 shows, the electricity and steam required by controls installed to meet

SO and NO emission caps would be less than 1% of the total electricity and steam production 2 X

in the region. Solid waste disposal and wastewater treatment costs are expected to be less than

5% of the total operating costs of pollution control equipment. 

5.2.4 Factor 4 – Remaining Equipment Life

Similar to EGUs, ICI boilers have no set equipment life. In fact, many units have been

refurbished multiple times. Of the boilers reporting installation dates in the Midwest, over 45%

are more than 50 years old. In addition, since the ICI strategies are market-based reductions to 31

be applied to a broad geographic region, it is assumed that controls will be not be applied to units

that are expected to be retired prior to the amortization period for the control equipment. 

Therefore, remaining equipment life is not expected to affect the cost of control for ICI boilers.
Pollution control technique and 

impact produced

Magnitude of 

impact Units

SDA

Sludge 3.7 ton sludge / ton of SO2 reduced

Electricity 0.4 MW-hr / ton SO2 reduced

CO2 for electricity 1.0 ton CO2 / MW-hr additional electricity needed

CO2 to produce lime from 

limestone

0.69 ton CO2 / ton of SO2 reduced

SCR

Sludge 0.021 ton spent catalyst / ton of NOX reduced

Electricity 0.89 MW-hr / ton of NOX removed

Steam 0.25 ton steam / ton of NOX removed

CO2 for electricity 1.0 ton CO2 / MW-hr additional electricity needed

CO2 for steam 0.26 ton CO2 / ton of additional steam needed

LNB/OFA/GR

 Electricity 6.4 MW-hr / ton NOX reduced

CO2 for electricity 1.0 ton CO2 / MW-hr additional electricity needed

Table 5.2-9. Factors Used to Calculate Energy and Non-Air Environmental 

Impacts of ICI Control Measures

49
Emission 

reduction (1000 

tons/year)

Additional 

electricity 

requirements (GWhrs /year)

Steam requirements (1000 

tons/yr)

Solid waste 

produced (1000 

tons/year)

Additional CO2 

emitted (1000 

tons/year)

ICI1 Strategy

3-State Region

SO2 33 13 - 120 35

NOX 22 37 5 0 38

Total 55 50 5 120 74

9-State Region

SO2 105 37 - 346 102

NOX 73 214 12 1 217

Total 178 251 12 347 319

ICI Workgroup Strategy

3-State Region

SO2 53 20 - 186 55

NOX 29 53 6 1 55

Total 81 73 6 187 110

9-State Region

SO2 169 58 - 537 158

NOX 85 235 14 1 239

Total 254 293 14 538 397

Table 5.2-10. Estimated Energy and Non-Air Environmental Impacts of ICI 

Control Strategies

50
51

5.2.5 Factor 5 – Visibility Impacts

Table 5.2-11 presents the estimated visibility impacts at the four northern-Midwest

Class I areas for the ICI control strategies implemented over the three-state region and the nine2 X state region. Results are presented separately for the SO and NO reductions. 

Table 5.2-12 estimates the cost effectiveness of ICI controls, expressed in terms of cost

per visibility improvement. It must be noted that the estimates of visibility improvement are

subject to considerable uncertainty. These are based on rollback calculations using the results of

PSAT analyses and CAMx sensitivity analysis. These rollback calculations provide a

mechanism for evaluating the relative impacts of different strategies. However, they may overestimate or under-estimate the impacts of NO controls relative to SO controls. More detailed X 2

modeling using CAMx or other photochemical models is needed to fully quantify the impact of

any given control strategy.
Strategy Region Pollutant

Boundary 

Waters Voyageurs Isle Royale Seney Ave

ICI1 3-State SO2 0.07 0.03 0.07 0.05 

NOX 0.07 0.05 0.03 0.02 

9-State SO2 0.09 0.05 0.09 0.11 

NOX 0.10 0.07 0.05 0.06 

3-State SO2 0.10 0.06 0.11 0.09 

NOX 0.10 0.06 0.03 0.03 

9-State SO2 0.15 0.08 0.15 0.18 

NOX 0.11 0.08 0.06 0.07 

per emission 

reduction 

($/ton)

per visibility 

improvement 

($million /dv)

ICI1

3-State Region

SO2 2,992 1,776NOX 2,537 1,327

9-State Region

SO2 2,275 2,825NOX 1,899 2,034

ICI Workgroup 

3-State Region

SO2 2,731 1,618NOX 3,814 1,993

9-State Region

SO2 2,743 3,397NOX 2,311 2,473

Strategy/Region

Average cost effectiveness 

values

Table 5.2-11. Estimated Visibility Impacts of ICI Control Strategies

Estimated visibility improvement in 2018 (deciviews)

Table 5.2-12. Cost Effectiveness of ICI 

Control Strategies in Terms of Visibility 

Improvement

ICI Workgroup

52
53

5.3 Reciprocating Engines and Turbines

Internal combustion engines at industrial, commercial, and institutional facilities are

projected to account for about 22% of NO emissions from non-EGU stationary sources in 2018. X

Reciprocating engines represent the largest share of this figure, at about 17%, with the remaining

5% attributed to turbines. Table 5.3-1 shows estimated emissions for reciprocating engines in

turbines in 2002, and projected emissions in 2018. The emissions estimates for MRPO states –

Michigan, Wisconsin, Illinois, and Indiana – are taken from the MRPO Base K 2002 emissions

inventory and the MRPO Base K/Round 4 Strategy Modeling Inventory for 2018. Emissions

estimates for Minnesota, Iowa, Missouri, North Dakota, and South Dakota in 2002 were taken

from the National Emissions Inventory. Emissions in 2018 were estimated assuming growth

rates similar to those projected for the MRPO states.

An update to EPA’s Alternative Control Techniques (ACT) guidance for reciprocating

engines identifies a Low-Emission Combustion (LEC) retrofit technology which can reduce

emissions from these sources by an average of 89%. LEC involves modifying the combustion 32

system to achieve very lean combustion conditions (high air-to-fuel ratios). AirControlNET also

X

identifies a number of combustion modification measures to reduce NO emissions from

reciprocating engines and turbines. Ignition retarding technologies are estimated to reduce

emissions from reciprocating engines by 25%. Water injection or steam injection can reduce 33

emissions from turbines by 68 to 80%, and low-NO burners can reduce turbine emissions X

by 84%. In addition, SCR can be used either alone or in conjunction with the above technologies

X

to reduce NO emissions from reciprocating engines or turbines by over 90%.

The NEI indicates that over half of the non-EGU internal combustion sources in the

stationary source inventory emit less than 1 ton/year; however, almost 75% of emissions emanate

from engines or turbines emitting 100 or more tons/year. Over 95% of emissions are from

sources emitting 10 or more ton/year.

We have evaluated two strategies for this category. The first would affect reciprocating

engines and turbines emitting 100 tons/year or more, and the second would affect sources

emitting 10 tons/year or more. Both strategies would reduce the emissions from affected

reciprocating engines by 89% and from affected turbines by 84%. These emission reduction

X

levels were selected because they can be achieved by either low-NO combustion technology or

by SCR.

Table 5.3-2 estimates the potential emission reduction impacts of these two control

strategies for states in the region. The table gives the estimated emissions in each state above the

size cutoffs of 100 tons/year and 10 tons/year. These are the emissions that would be covered by

the two potential control strategies. The affected fractions were estimated based on state-specific

distributions of emission source sizes from the NEI. Table 5.3-2 then estimates potential

emission reductions based on emission reductions of 89% for reciprocating engines and 84% for

turbines. These estimates represent reductions beyond the levels of control expected from onthe-books measures. (MRPO strategy modeling estimates reductions of 8 to 15% for

reciprocating engines in different states.) 
Reciprocating 

engines Turbines Total

Reciprocating 

engines Turbines Total

Michigan 44.1 11.4 55.5 41.4 11.5 52.9 229.3 Minnesota 18.3 5.9 24.3 17.6 6.3 23.9 182.6 Wisconsin 8.1 1.9 10.0 7.2 1.9 9.2 93.8 

3-State Subtotal 70.5 19.2 89.8 66.2 19.7 85.9 505.7 

Illinois 112.5 14.3 126.8 110.6 15.9 126.4 342.7 Indiana 25.1 1.7 26.8 23.0 1.8 24.7 225.4 Iowa 26.3 1.6 27.9 25.2 1.7 26.9 121.7 Missouri 21.0 3.2 24.3 20.2 3.4 23.6 111.2 North Dakota 8.7 1.3 10.0 8.3 1.4 9.7 36.1 South Dakota 0.0 1.0 1.0 0.0 1.1 1.1 24.0 

9-State Total 264.1 42.5 306.6 253.6 44.9 298.4 1,366.9 

*Excludes reciprocating engines and turbines classified as EGUs.

Table 5.3-1. Estimated Emissions from Reciprocating Engines and Turbines in Relatio

Non-EGU Emissions in 2018

NOX emissions from stationary 

internal combustion sources in 2002 

(tons/day)*

Projected NOX emissions from 

stationary internal combustion 

sources in 2018 (tons/day)* Projected NOX 

emissions from all 

non-EGU point 

sources (tons/day)

Stat

com

frac

EGU 

i

54
Size cutoff and state

Reciprocating 

engines Turbines

Reciprocating 

engines Turbines Total

100 tons/year or more

Michigan 8.2 9.4 7.1 7.9 15.0

Minnesota 11.6 3.6 10.3 3.1 13.4

Wisconsin 5.3 1.2 4.6 1.0 5.6

Subtotal for 3-State 

region

25.0 14.2 22.0 11.9 34.0

Illinois 93.6 6.6 82.3 5.6 87.9

Indiana 16.5 0.9 14.7 0.7 15.4

Iowa 16.5 0.0 14.7 0.0 14.7

Missouri 12.7 0.0 11.3 0.0 11.3

North Dakota 8.2 1.4 7.3 1.2 8.5

South Dakota 0.0 1.1 0.0 0.9 0.9

Total for 9-State region 172.6 24.2 152.4 20.3 172.7

10 tons/year or more

Michigan 38.4 11.4 33.6 9.6 43.1

Minnesota 15.6 6.1 13.9 5.1 19.1

Wisconsin 6.5 1.8 5.7 1.5 7.2

Subtotal for 3-State 

region

60.6 19.2 53.2 16.2 69.4

Illinois 108.7 14.3 95.6 12.0 107.6

Indiana 22.3 1.3 19.6 1.1 20.7

Iowa 24.4 1.0 21.7 0.8 22.5

Missouri 19.1 2.7 17.0 2.2 19.2

North Dakota 8.3 1.4 7.4 1.2 8.6

South Dakota 0.0 1.1 0.0 0.9 0.9

Total for 9-State region 243.4 40.9 214.5 34.4 248.9

Table 5.3-2. Potential Emission Reductions for Candidate Internal 

Combustion Control Measures

Estimated emissions 

covered in 2018 

(tons/day)

Potential emission reductions from 

on-the-books levels (tons/day)

55
56

5.3.1 Factor 1 – Costs

EPA’s updated ACT guidance for reciprocating engines estimates the cost estimates of 

installing Low Emission Combustion technology on existing engines of various sizes (based on

their brake-horsepower rating). The 100 ton/year emission cutoff level is estimated to 32

correspond to an engine size of about 800 brake-horsepower, for which the cost-effectiveness of

would be about $980/ton of NO emission reduction (in 2005 dollars). The cost-effectiveness at X

the 10 ton/year emission cutoff level (about 80 brake-horsepower) is estimated to be about

$8,200/ton.

AirControlNET estimates that low-NO burner technology can be installed on emission X

X

sources larger than 34 million BTU with a cost-effectiveness of about $750/ton of NO emission

reduction. This turbine size corresponds to an uncontrolled emission rate of about 40 tons/year. 33

At the 10 ton/year emission cutoff, we have estimated a cost effectiveness of about $1,600/ton,

based on scaling factors used in AirControlNET for similar sources.

Table 5.3-3 gives estimated average cost-effectiveness values and cost-effectiveness

ranges for the internal combustion control strategies. The average cost effectiveness values were

calculated using emission engine and turbine size distributions from the NEI. These costeffectiveness values are based on the modification of engines and turbines to use low-NOX

combustion technologies. SCR systems could also be used attain the candidate emission

X

reduction targets, however these systems are expected to be less cost-effective than low-NO

combustion modifications.

5.3.2 Factor 2 – Time Necessary for Compliance

Based on information developed for the EGU and ICI emission source categories, we

have estimated the time required for compliance with internal combustion control strategies at

between 51⁄2 and 61⁄2 years. This estimate includes the following components:

• 2 years for states to develop the necessary rules to implement the strategy

• Up to 1 year to procure the necessary capital to modify burners or purchase control

equipment

• 18 to 30 months required to make burner modifications or install control technology for a

single engine or turbine

• An additional 12 months for staging the installation process if multiple sources are to be

controlled at a single facility. 

5.3.3 Factor 3 – Energy and Other Impacts

Low-NO combustion technologies are expected to be the most cost-effective methods X

for achieving the candidate emission reduction targets for both reciprocating engines and

X

turbines. Some low-NO combustion technologies require electricity for turbocharging or steam

for steam injection. However, the candidate emission limits are based on systems which require

only modifications to alter fuel-air mixing and combustion temperatures. These changes are 32,33

not expected to produce any additional electricity or steam demands, or generate wastewater or

solid waste.
Sources covered Average Range

Control of sources emitting over 100 tons/year

3-State region

Reciprocating engines 538 310 - 980Turbines 754 750 - 750

Total 614 310 - 980

9-State region

Reciprocating engines 506 240 - 980

Turbines 754 750 - 750

Total 535 240 - 980

Control of sources emitting over 10 tons/year

3-State region

Reciprocating engines 1,286 310 - 8,200Turbines 800 750 - 1,600

Total 1,172 310 - 8,200

9-State region

Reciprocating engines 1,023 240 - 8,200Turbines 819 750 - 1,600

Total 995 240 - 8,200

Table 5.3-3. Estimated Cost Effectiveness of 

Controls for Internal Combustion Sources

Cost effectiveness ($/ton of 

NOX emission reduction)

57
58

NO emission reductions from reciprocating engines and turbines would have beneficial X

environmental impacts by reducing acid deposition and nitrogen deposition to water bodies and

natural landscapes. Regional haze control strategies for NO are designed to reduce formation of X

fine particles that impair visibility. Such reductions would also result in decreases in the ambient

2.5 levels of PM , with corresponding health benefits. In addition, broad regional reductions in

NO would result in reductions in background levels of ambient ozone. These reductions in X

PM and ozone could improve the potential for urban areas in the Midwest to attain the NAAQS 2.5

for these pollutants.

5.3.4 Factor 4 – Remaining Equipment Life

Information was not available on the age of reciprocating engines and turbines in the

Midwest region. Older equipment may not be amenable to low-NO combustion modifications. X

For these sources, the candidate emission reduction targets could be achieved with SCR;

however, costs would be up to 3.5 times the estimated cost of low-NO combustion X

modifications. In addition, if the remaining equipment life is less than the 15 year amortization 33

period for an SCR system, the annual cost of control would be further increased. The combined

impact of these factors could increase the cost-effectiveness to $10,000 per ton for older engines.

5.3.5 Factor 5 – Visibility Impacts

Table 5.3-4 presents the estimated visibility impacts at the four northern-Midwest Class I

areas for the internal combustion control strategies implemented over the three-state region and

the nine-state region. Table 5.3-5 estimates the cost effectiveness of the candidate internal

combustion control measures in terms of cost per visibility improvement. 

It must be noted that the estimates of visibility improvement are subject to considerable

uncertainty. These are based on rollback calculations using the results of PSAT analyses and

CAMx sensitivity analysis. These rollback calculations provide a mechanism for evaluating the

relative impacts of different strategies. However, they may over-estimate or under-estimate the

X 2 impacts of NO controls relative to SO controls. More detailed modeling using CAMx or other

photochemical models is needed to fully quantify the impact of any given control strategy.
Region

Boundary 

Waters

Voyageurs Isle Royale Seney Average

Control of sources emitting over 

100 tons/year

3-State region

Reciprocating engines 0.027 0.017 0.009 0.008 0.015

Turbines 0.014 0.009 0.005 0.005 0.008

Total 0.041 0.026 0.015 0.013 0.024

9-State region

Reciprocating engines 0.074 0.053 0.036 0.044 0.052

Turbines 0.010 0.007 0.005 0.006 0.007

Total 0.084 0.060 0.041 0.050 0.059

Control of sources emitting over 

10 tons/year

3-State region

Reciprocating engines 0.064 0.041 0.023 0.020 0.037

Turbines 0.019 0.013 0.007 0.006 0.011

Total 0.084 0.054 0.030 0.026 0.048

9-State region

Reciprocating engines 0.105 0.075 0.051 0.062 0.073

Turbines 0.017 0.012 0.008 0.010 0.012

Total 0.121 0.087 0.059 0.072 0.085

Table 5.3-4. Estimated Visibility Improvements from Internal 

Combustion Control Measures

Estimated visibility improvement in 2018 (deciviews)

59
Strategy and region

Cost effectiveness 

per visibility 

improvement 

($million/ 

deciview)

Control of sources emitting over 100 tons/year

3-State region

Reciprocating engines 282

Turbines 395

Total 677

9-State region

Reciprocating engines 542

Turbines 810

Total 1,352

Control of sources emitting over 10 tons/year

3-State region

Reciprocating engines 673

Turbines 419

Total 1,092

9-State region

Reciprocating engines 1,095

Turbines 880

Total 1,975

Table 5.3-5. Cost Effectiveness of Internal 

Combustion Control Strategies in Terms of 

Visibility Improvement

60
61

5.4 Ammonia Emissions from Agricultural Sources

Agricultural sources account for an estimated 99% of ammonia emissions in the threestate region, and 97% in the nine-state region. The bulk of these emissions are from livestock;

while a smaller portion, about 5%, results from the use of synthetic nitrogen fertilizers. 

Ammonia emissions from livestock emanate from urea and other nitrogen compounds in their

waste. Microbes convert the urea to ammonium compounds, which can then produce ammonia

emissions at a number of different points within the farm. These include animal houses, waste

collection and storage systems, waste treatment systems, pastures, and fields on which the waste

is used.

The most widely used synthetic nitrogen fertilizer is anhydrous ammonia, which is

injected into the soil in gaseous form. Other nitrogen fertilizers include synthetic urea,

ammonium compounds, and nitrate compounds, all of which can be used in solid form or in

solutions. Ammonia, urea, and ammonium fertilizers give off ammonia gas after they are applied

to crops. 

States have identified Best Management Practices (BMPs) for the management of animal

waste and for the use of nitrogen fertilizers. These practices are designed to reduce water

pollution and groundwater pollution impacts, but many BMPs also act to mitigate ammonia

emissions. BMPs in the Midwest states include the following.

! For animal houses and waste collection systems:

" Conveyor belts for removal of waste

" Daily scrape and haul of manure

" Transfer pipes to transfer manure to storage or treatment structure

" Leaving manure to mix with bedding to form manure pack

" Hopper to transfer manure

" Outdoor housing of cattle (outwintering)

! For manure storage systems:

" Stockpiling manure in one area

" Deep pits to store manure

" Treatment of waste in lagoons

" Walled storage facilities or storage tanks

" Covered storage facilities

! For application of manure to crop lands and grasslands:

" Incorporation of manure into the soil after apreading

" Injection of manure using sweeps or knives

" For general manure management:

" Planning for manure management

" Solid-liquid manure separating system

" Composting of manure
62

! For nitrogen fertilizer usage:

" Reduction nitrogen fertilizer usage – through the use of realistic crop yield goals

when calculating fertilizer needs, improved recordkeeping, and soil nitrogen tests

" Adjusting the timing of fertilizer application to meet crop needs

" Maintaining optimal soil pH

" Injection or incorporation of fertilizer into the soil

" Crop rotation and and use of nitrogen-fixing crops in place of nitrogen fertilizer

Other techniques have also been evaluated for controlling ammonia emissions. Feed

adjustments have been proposed which would reduce the amount of nitrogen compounds

excreted by farm animals. This is generally done by improving the mix of amino acids eaten by

the animal, reducing the animal’s consumption of crude protein, and matching the animal’s

protein consumption to its needs during different stages of growth. Researchers have also

evaluated use of trees to absorb ammonia emissions. These trees would be planted near the

ventilation systems of animal houses, or as a buffer around other ammonia emission sources.

Some researchers have proposed the use of additives such as alum to reduce emissions

from animal waste. In addition, research has been performed on the use of urease inhibitors to

delay the conversion of urea to ammonia. The purpose of this control measure is to allow crops

to more effectively absorb nitrogen from the animal waste before the nitrogen compounds are

converted to ammonia and lost to the atmosphere.

For the current study, the Midwest RPO and the states opted to analyze a 10–15%

reduction in ammonia emissions from agricultural sources. The methods of achieving this

emission reduction and the distribution of the reduction among different types of farms would be

flexible.

5.4.1 Factor 1 – Costs

Limited information is available on the cost of control measures for agricultural ammonia

emissions. Table 5.4-1 analyzes control measures from the previous list for which cost

information is available. The table shows the estimated fraction of the overall ammonia

inventory which could be controlled, the emission control efficiency, the potential emission

reduction, and the cost effectiveness of each control measure. The options are sorted in

increasing order of cost effectiveness.

The costs of tree plantings are based on an analysis by the Iowa Agricultural Extension

Service. The potential effectiveness of trees for reducing ammonia emissions is based on 34

measurements by the University of Delaware over a four year period at a poultry house. The

wide range of cost effectiveness values for this control measure result from the variability of

emission reductions during the measurement study. At least one other research group has been 35

investigating the effectiveness of tree plantings for reducing ammonia emissions, but quantitative

emission reduction results are not yet available.36
Description

Fraction of the overall 

NH3 emissions 

inventory that can be 

controlled using this 

option

Estimated 

reduction efficiency 

for the affected 

category (%)

Potential 

reduction in 

overall inventory 

(%)

Co

Vegetative buffers for houses and storage facilities 57 15 - 77 9 - 44 Vegetative buffers for entire farms 100 9 - 21 9 - 21 

Feed adjustments for swine 20 4 - 16 1 - 3 

Reduce usage of nitrogen fertilizer 5 50 2 poIncorporation of pig slurry by disc 4 36 - 70 2 - 3 Replace urea with lower emission fertilizer 2 75 - 95 2 

Incorporation of poultry manure by disc 4 36 - 80 2 - 3 Incorporation of beef cattle manure by disc 4 36 - 70 1 - 3 Incorporation of dairy slurry by disc 12 70 9 Incorporation of dry dairy manure by disc 7 36 - 70 3 - 5 

Table 5.4-1. Estimated Cost Effectiveness of Control Measures for Agricultural Ammonia 

63
64

Cost estimates for feed adjustments varied over a broad range. One U.S. researcher

indicated that a diet adjustment designed to reduce the amount of crude protein could be made at

little or no cost. However, a British study estimated the cost of a staged feeding program to 37

reduce the levels of nitrogen compounds in waste at $21,000 per ton of ammonia emission

reduced. 38

The British cost study also estimated the cost effectiveness of a number of other control

options, including the incorporation of animal waste into the soil. However, the emission

reduction reported for these measures in the British study were considerably higher than those

reported in BMP guidelines from the Minnesota Agricultural Extension Service. The broad

ranges of cost effectiveness values for these measures generally reflect the differences in

estimated efficiencies between the British study and the BMP guideline estimates. For instance,

the British study estimates that an emission reduction of 70% can be achieved by incorporating

pig slurry into the soil when it is applied to crop lands. With an emission reduction of 70%, the

cost effectiveness of this control measure is estimated at $600/ton of emission reduction. 

However, the Minnesota Agricultural Extension service estimates the efficiency of this control

measure at only 36%. This lower estimate would increase the cost per unit of emission control to

about $1200/ton.

Based on the information presented in Table 5.4-1, the cost effectiveness of achieving a

10–15% reduction in agricultural emissions could be as low as $31 per ton, corresponding with

the low end of the cost estimate and a moderate efficiency for tree plantings. A number of other

options are available for less than $2,700 per ton.

5.4.2 Factor 2 – Time Necessary for Compliance

As discussed above, the use of trees to absorb ammonia emissions could be the most

effective control measure for agricultural sources. The cost estimates for Factor 1 are based on

planting trees at about $25 each, with a height of about 6 feet. These trees would require a

number of years to reach their full emission reduction effectiveness. Taller trees, at about 12

feet, could be purchased for about $150 each. The trees tested in the Delaware study were 14 to

18 feet tall. 

We have estimated the time required for tree plantings to reach their full effectiveness at

3–10 years, depending on the size of trees planted. The other control options for agricultural

ammonia emissions could be achieved within a year. 

5.4.3 Factor 3 – Energy and Other Impacts

The control options involving incorporation of animal waste into the soil would require

additional energy usage to run farm tractors for the incorporation step. The British cost study

quantified the numbers of hours of tractor usage which would be required to incorporate a given

volume of animal waste, and we have used these figures to estimate the amount of additional

diesel fuel that would be required. We have also estimated the amount of additional CO which 2

would be produced in the burning of this fuel (Table 5.4-2).
Description

Additional diesel 

requirements (gal/Mg 

NH3 reduced)

Carbon dioxide 

generated (tons/ton NH3 

reduced)

Vegetative buffers for houses and storage facilities 0 reductionVegetative buffers for entire farms 0 reductionFeed adjustments for swine 0 0Incorporation of pig slurry by disc 200 - 500 300 - 600Replace urea with lower emission fertilizer 0 0Incorporation of poultry manure by disc 200 - 600 200 - 700Incorporation of beef cattle manure by disc 200 - 400 200 - 500Incorporation of dairy slurry by disc 1300 - 1500 1400 - 1700Incorporation of dry dairy manure by disc 400 - 900 400 - 1000

Table 5.4-2. Estimated Energy and Non-Air Environmental Impacts of 

Agricultural Ammonia Emission Control Measures

65
66

Control measures which involve the use of additives, such as alum, in animal wastes may

have adverse impacts when the waste is spread on fields. However, these options do not appear

to be as cost effective as other available options, and are not expected to be used to attain a

10–15% emission reduction.

Vegetative buffers, animal feed adjustments, and measures to reduce fertilizer usage

would require no additional energy usage and would produce no additional solid waste. In fact,

2

trees planted to absorb ammonia would also have the benefit of absorbing CO . 

Any control measure to reduce emissions of ammonia will have the benefit of reducing

nitrogen deposition. In addition, although ammonia acts as an alkaline buffer in the atmosphere,

it can be oxidized to form nitrate once it is deposited to natural landscapes. Thus, control

measures to reduce ammonia can also reduce the acidification of soils and waterbodies. The

ammonia control measures considered in the current study are designed to reduce the formation

of fine particles that impair visibility. Such reductions would also result in decreases in the

ambient levels of PM , with corresponding health benefits. 2.5

5.4.4 Factor 4 – Remaining Equipment Life

Factor 4 does not generally apply to agricultural emissions of ammonia. Livestock are

generally replaced when they are slaughtered, and the fields on which animal waste and fertilizer

are spread do not have a service life in the same sense as a piece of equipment. Animal houses

and waste storage facilities do have a limited service life; however, the controls which appear to

be the most cost effective for these sources are not typical add-on controls. Tree plantings would

be effective for the replacement facilities as long as they are built in the same place. Nor are

animal feed adjustments tied to the building or the waste storage facility. Add-on controls such

as covers and ammonia capture devices are more expensive, and are not expected to be used to

obtain a 10–15% emission reduction.

5.4.5 Factor 5 – Visibility Impacts

Table 5.4-3 presents the estimated visibility impacts at the four northern-Midwest Class I

areas for the agricultural ammonia control strategy, implemented over the three-state region and

the nine-state region. Table 5.4-3 estimates the cost effectiveness of ammonia emission

reductions in terms of the cost per emission reduction and the cost per visibility improvement. It

must be noted that the estimates of visibility improvement are subject to considerable

uncertainty. These are based on rollback calculations using the results of PSAT analyses and

CAMx sensitivity analysis. These rollback calculations provide a mechanism for evaluating the

relative impacts of different strategies. However, they may over-estimate or under-estimate the

3 2 X

impacts of NH controls relative to SO or NO controls. More detailed modeling using CAMx

or other photochemical models is needed to fully quantify the impact of any given control

strategy.
Strategy and region

Boundary 

Waters Voya-geurs Isle Royale Seney Averag

10% Ammonia reduction in the 3-State region 0.09 0.11 0.10 0.10 0.1010% Ammonia reduction in the 9-State region 0.15 0.18 0.15 0.17 0.115% Ammonia reduction in the 3-State region 0.14 0.17 0.15 0.14 0.115% Ammonia reduction in the 9-State region 0.23 0.27 0.23 0.26 0.2

Strategy and region

10% Ammonia reduction in the 3-State region10% Ammonia reduction in the 9-State region15% Ammonia reduction in the 3-State region15% Ammonia reduction in the 9-State region 31 - 2,700

Average cost 

effectiveness per 

emission reduction 

($/ton)

8 - 750

18 - 1,500

8 - 750

18 - 1,500

Average cost 

effectiveness per 

visibility improveme

($million/dV)

31 - 2,70031 - 2,70031 - 2,700

Table 5.4-3. Estimated Visibility Impacts of Agricultural Ammonia Emission 

Control Measures

Table 5.4-4. Cost Effectiveness of Agricultural Ammonia Emission Control 

Measures in Terms of Visibility Improvement

Estimated visibility improvement in 2018 (deciviews)

67
68

5.5 Mobile Sources

Despite projected NO reductions from on-the-books Federal and state-wide programs X

targeting on- and non-road mobile source sectors as well as locomotives and marine engines,

source apportionment analyses demonstrate that mobile sources still contribute significantly to

visibility impairment in 2018 in the northern Midwest Class I areas. Potential additional control

strategies were identified that could be applied on a regional level (see Appendix A). From this

list, the following strategies were analyzed:

! For on-road engines:

" Low-NO Reflash X

" Anti-Idling

" Midwest Clean Diesel Initiative (MCDI)

" Cetane Additive Program

! For non-road and locomotive engines:

" Anti-Idling

" Cetane Additive Program

" MCDI

In addition to the above strategies, we also include a qualitative discussion of using biodiesel as

an alternative fuel (see Section 5.5.6). Studies have shown that biodiesel does not reduce NOX

emissions, and may in fact show an increase of 2-4%. However, biodiesel blends have been 39,40,41

implemented in several states as part of the MCDI, or as an alternative fuel strategy to reduce PM

emissions. 

We relied primarily on the Evaluation of Candidate Mobile Source Control Measures for

LADCO States in 2009 and 2012 (ENVIRON report) for the factor analyses of these strategies. 42

This report provides example reduction strategies and discussion for Low-NO Reflash, MCDI X

projects, and anti-idling strategies. We obtained information on the cetane program from various

X

studies that examine the effect of cetane additives on NO emissions.43,44,45

Low-NO Reflash affects 1993-1999 model year Class 7 and 8 heavy-duty diesel vehicles X

(HDDV) with model year 1993-1998 engines manufactured by Caterpillar, Cummins, Detroit

Diesel, Mack/Renault, Volvo, and International. These seven corporations implemented

advanced computer controls that, while maximizing fuel economy, also increased NO emissions X

during certain duty cycles. Consent decrees require these manufacturers to install low-NOX

software upgrades free of charge. The program has not progressed as quickly as anticipated, so

additional mandatory programs or voluntary incentives are being explored to hasten installation

of the software.

The MCDI is a collaborative organization between federal, state, and local agencies, and

funds projects that will reduce diesel emissions through operational changes, technological

improvements, and cleaner fuels. The initiative has been funded since 2002 by federal, state,

local, and private agencies for the states of Illinois, Indiana, Michigan, Minnesota, Ohio, and

Wisconsin. It has been assumed for this analysis that funding will continue at a constant level at

least through 2018 for similar projects, and will be expanded to the 9-state region. Because the

majority of projects to date target on-road engines, the factor analysis has only been conducted on

that sector. 
The ENVIRON report provided alternate 2012 emissions data for the LADCO states and Minnesota, but a

the Base K inventory was used for consistency between 2012 and 2018.

69

Anti-idling strategies have been implemented in approximately 15 states and dozens of

counties (including Minnesota and Wisconsin) to reduce emissions from on-road, non-road and

locomotive engines. These strategies take the form of enforced shutdown policies, auxiliary

power units (APUs), automatic engine shut-off technology, and truck stop electrification (TSE).

The on- and non-road cetane program would introduce additives to diesel fuel at the

distribution source to increase the cetane number to approximately 50. This program has been

X

shown to improve fuel economy and decrease NO emissions in all non-road engines and in 2002

and earlier model year on-road engines.116

5.5.1 Factor 1 – Costs

Table 5.5-1 summarizes the estimated cost effectiveness of various control measures for

mobile source emissions. The table also shows the estimated effectiveness of each control

measure, the approximate contribution of the affected emission source to the overall inventory

(where available), and the estimated potential reduction in the overall inventory.

NO emissions were obtained from the 2012 and 2018 Base K Strategy 1 inventory for X

the 3-state and 9-state regions. Emissions data for 2018 were not available for Missouri, Iowa, a

North Dakota, or South Dakota.

Cost-effectiveness and emission reductions for low-NO reflash, MCDI, and anti-idling X

programs were obtained primarily from the ENVIRON report. It was assumed that percentage of

emissions reduced and cost-effectiveness achieved in the LADCO region would be applicable to

the 3-state and 9-state regions examined in this analysis. Potential emission reductions for the

cetane program were obtained from the southeast Michigan fuels study, and cost-effectiveness 43

was obtained from a study conducted in Nashville, TN.44

The ENVIRON report presents a combined PM, VOC, and NO cost-effectiveness for the X

MCDI and anti-idling strategies. Cost-effectiveness for NO was calculated based on the X

percentage of NO reductions achieved by each strategy. For this analysis, it was assumed that X

the amount of funding for MCDI projects would be distributed in a similar fashion to current

projects. This assumption resulted in a high cost-effectiveness for NO reductions, especially for X

the 3-state region, because MCDI projects focused primarily on PM emissions. Specifically, the

ENVIRON report did not identify any NO reductions for programs in Wisconsin or Minnesota, X

as those states focused on diesel retrofits and biofuels for PM reductions. However, the 9-state

X

region achieved larger NO reductions and lower cost-effectiveness due largely to the amount of

funding devoted to idling restrictions in the Chicago, IL metropolitan area.42

While anti-idling policies and technologies were included as part of the MCDI strategy, a

separate analysis was also conducted by ENVIRON for idle reduction strategies for on-road and 

non-road engines, and line haul and switching locomotives. The majority of emission reductions

achieved by anti-idling policies were NO reductions, resulting in a cost-effectiveness of $1,400- X

$3,600 per ton. Cost-effectiveness was calculated assuming that automatic shut-off and/or APU
70

technology would be installed to reduce idling. Truck-stop electrification (TSE) was also

factored into on-road idle reduction strategies. 

The cost-effectiveness of anti-idling strategies for on-road engines reflects a net

annualized savings of $200-430 per vehicle for APUs and/or automatic shutoff technology, and

$1,700 per ton for TSE. Fuel and maintenance savings were not calculated for non-road or

locomotive shutoff technology, but one study estimated a payback period of approximately 2.5

years due to fuel and maintenance savings.46

For the cetane program, the fraction of emissions reduced from the on-road inventory

accounts for the fact that reductions would only apply to 2002 and older model years. It was

assumed that the percentage of emission reductions possible in southeast Michigan would be

applicable to the regional inventory. 
Table 5.5-1. Estimated Cost Effectiveness and Emission Reduction Potential

of Mobile Source Controls for the 3-State and 9-State Regions

2012 2018 

Low-NOX Reflash On-Road All MDDV and HDDV 

Class 8 Vehicles

23% 25% 5.8% 5.8% 

MCDI On-Road Class 8 Vehicles 2% in 2012, 5% in 2018 36% 0.7% 1.8% 

Non-Road Diesels 2% in 2012, 5% in 2018 71% 1.4% 3.6% M/A/R Switching and Line-Haul 

Locomotives

2% in 2012, 5% in 2018 42% 0.8% 2.1% 

Anti-Idling M/A/

R Switching Locomotives 9% in 2012, 18% in 2018 5% 0.4% 0.9% 

Line-Haul Locomotives 2% in 2012, 4% in 2018 37% 0.7% 1.5% 

On-Road All MDDV and HDDV 

Class 8 Vehicles

2.6% 36% 0.9% 0.9% 

Non-road Non-road diesel engines 1.5% 71% 1.1% 1.1% 

Cetane Additive Program

Non-road All diesel engines 1.0% 2.9% 2.9% 

On-Road MY2002 and earlier 

MDDV and HDDV

2.9% 1.6% 1.5% 

Low-NOX Reflash On-Road All MDDV and HDDV 

Class 8 Vehicles

23% 25% 5.8% 5.8% 

MCDI On-Road Class 8 Vehicles 2% in 2012, 5% in 2018 36% 0.7% 1.8% 

Non-Road Diesels 2% in 2012, 5% in 2018 75% 1.5% 3.7% 

M/A/R Switching and Line-Haul 

Locomotives

2% in 2012, 5% in 2018 56% 1.1% 2.8% 

Anti-Idling M/A/

R Switching Locomotives 9% in 2012, 18% in 2018 2% 0.2% 0.4% 

Line-Haul Locomotives 2% in 2012, 4% in 2018 24% 0.5% 1.0% 

On-Road All MDDV and HDDV 

Class 8 Vehicles

2.6% 36% 0.9% 0.9% 

Non-road Non-road diesel engines 1.5% 75% 1.1% 1.1% 

Cetane Additive Program

Non-road All diesel engines 1.0% 2.9% 2.9% 

On-Road MY2002 and earlier 

MDDV and HDDV

2.9% 1.6% 1.4% 

[b] Assumes equipment life of 20 years at an interest rate of 7%

Potential fraction 

of overall 

inventory affected 

(%)

Potential reduction for 

inventory (%) 

Strategy Inventory Affected Category 

Estimated reduction 

efficiency for the affected 

category (%) 

3-State Region

9-State Region

[c] Cost-effectiveness taken from Davis, W. T., and T. L. Miller. “Estimates of potential emissions reductions for the Nashville ozone early actReport,” prepared for the Nashville Department of Environment and Conservation, March 2004. [a] Reduction efficiency depends on market penetration, funding, and/or regulatory development for these control measures

71
72

5.5.2 Factor 2 – Time Necessary for Compliance

Overall, the strategies chosen for analysis could be implemented in a relatively short time

X

frame. For the low-NO reflash program, the ENVIRON report assumes that all emission

reductions from the program would be implemented by 2012, or 4 years from the first SIP

implementation in 2008. The groundwork is in place to adopt a mandatory or voluntary program

X

to accelerate installation of low-NO software. Although California’s efforts to establish a

mandatory program have stalled due to recent court action, NESCAUM with the support of the 47

Ozone Transport Commission (OTC) has developed a model rule that the Midwest could adopt. 

Cooperative efforts could also be pursued with engine manufacturers to coordinate software

downloads with routine engine maintenance. 48

The Midwest Clean Diesel Initiative’s primary goal is to decrease emissions from 1

million diesel engines by 2010. However, this analysis assumes that the MCDI would receive a

constant amount of funding and implement similar emission reduction programs through at least

2018.49

Anti-idling policies have been implemented by local agencies in Illinois, Missouri,

Minnesota and Wisconsin. We estimate a time frame of 16-20 months to adopt a regional anti- 50

idling policy, based on the time required to develop a program in California. Voluntary efforts 51

could also be undertaken to establish anti-idling corridors, such as the Everybody Wins strategy

developed by LRAPA. Depending on funding, an anti-idling corridor could be established 52

within 2-5 years.

A cetane program targeting on- and non-road diesel fuel may require the need for

regulatory action. According to EPA guidance, States have the authority to implement a program

that will increase the cetane number with additives as long as it does not change the cetane index

or aromatics properties of the fuel. Extrapolating from the southeast Michigan study, a cetane 53

program could be potentially implemented in a two-year time frame.

5.5.3 Factor 3 – Energy and Other Impacts

Table 5.5-2 qualitatively summarizes energy and other impacts of the mobile source

strategies. Fuel economy benefits can be seen as a result of the MCDI, anti-idling, and cetane

programs, while a negligible disbenefit can be seen from installation of the low-NO reflash X

software. Co-benefits of greenhouse gas and other criteria pollutant reductions can be seen as a

X

result of all programs except low-NO reflash, which may result in a 7% PM emissions increase

per vehicle. 116

5.5.4 Factor 4 – Remaining Equipment Life

Remaining useful life of mobile sources may have some effect on control strategy

effectiveness, particularly those that target older model vehicles. Vehicle turnover would affect

X

the on-road cetane program and the low-NO reflash program, because they target model years

2002 and earlier, and model years 1993-1999, respectively. All emission reductions from the

X

low-NO program are expected to be achieved by 2012 either through installation of software or

engine retirement. The cetane program is projected to achieve a lower emission reduction in the

overall inventory due to vehicle turnover (see Table 5.5-1.)
73

5.5.5 Factor 5 – Visibility Impacts

Table 5.5-3 presents the estimated visibility impacts at the four northern-Midwest Class I

areas for the candidate mobile source control strategies, implemented over the three-state region

and the nine-state region. Table 5.5-4 estimates the cost effectiveness of mobile source controls,

expressed in terms of cost per visibility improvement in deciviews. 

It must be noted that the estimates of visibility improvement are subject to considerable

uncertainty. These are based on rollback calculations using the results of PSAT analyses and

CAMx sensitivity analysis. These rollback calculations provide a mechanism for evaluating the

relative impacts of different strategies. However, they may over-estimate or under-estimate the

X 2 impacts of NO controls relative to SO controls. More detailed modeling using CAMx or other

photochemical models is needed to fully quantify the impact of any given control strategy.

5.5.6 Biofuels

Biofuels, including biodiesel (i.e., alkyl esters made from the transesterification of

vegetable oils or animal fats), and ethanol (i.e., a biomass alternative to gasoline manufactured

primarily from corn, sugar beets, and sugar cane), have positive impacts on greenhouse gases and

PM, but may have some negative impacts on NO . Although several studies have shown an X

X

increase in NO emissions from biodiesel, use of this fuel results in other environmental benefits,

including a significant net reduction in solid waste and wastewater production. Biodiesel in a 54

20% blend with petroleum diesel (B20) has been shown to reduce PM emissions by 10%, HC

emissions by 21% and CO emissions by 11% in heavy-duty on-road engines. However, it may

reduce fuel economy by 1-2%. Emission reductions of PM, HC, and CO generally increase as

the percentage of biodiesel blend increases.41

Approaches have been studied that would mitigate NO emissions from biodiesel. These X

approaches include lowering the base fuel aromatic content from 31.9% to 7.5%, using kerosene

as a base fuel in a B40 blend, and using cetane enhancers. All approaches result in a “NO - X

neutral” biofuel, with cetane enhancers proving the most cost-effective at an incremental cost of

$0.05 - $0.16 per gallon for a 4% reduction in NO . X

40

The effect of ethanol blends on NO emissions also remains uncertain. The southeast X

Michigan fuels study demonstrated an increase of 2-4 tons per day in NO emissions from the X

use of an E10 gasoline blend, for example. Studies conducted by CARB also indicate a NOX

43

disbenefit in vehicles model year 1988-1995. However, the effect of ethanol blends on NOX

emissions in vehicles newer than 1996 is uncertain, as the EPA Complex Model shows a slight

decrease in NO emissions in those vehicles. X
Strategy Affected Category Fuel Impacts Other Air Quality Impacts Envi

Low-NOX Reflash On-Road <1% fuel economy penalty 7% increase in PM emissions per vehicle. None

MCDI On-Road Anti-idling strategies funded 

by MCDI result in a fuel savings. (HDDV Idling generally uses 1 gallon/hr of fuel.)

Reductions in GHG, PM, VOC, and CO. Biodiesel strategies have a NOX emission penalty of up to 2% and a GHG reduction of 78% over petroleum diesel.

Anti-idling straenvironmental iproductions reswastewater and waste over petr

Anti-Idling M/A/R

On-Road

Non-road

Cetane Additive Program

Non-roadOn-Road

Table 5.5-2. Estimated Energy and Non-Air Environmental Impacts of Mobile Source Cont

Fuel savings Reductions in GHG, PM, VOC, and CO. EPA 

cites a reduction of 22 pounds of GHG for every 

gallon of diesel fuel saved by anti-idling policies.

Improved fuel economy PM2.5 emissions benefit

74
Boundary 

Waters

Voyageurs Isle Royale Sene

Low-NOX Reflash All MDDV and HDDV Class 

8 Vehicles

On-Road 5.8 0.006 0.007 0.009 0.0

MCDI Class 8 Diesel Vehicles On-Road 1.8 0.002 0.002 0.003 0.0

Diesel Engines Non-road 3.6 0.009 0.012 0.008 0.0

Switching and Line-Haul Locomotives

M/A/R 2.1 0.004 0.005 0.003 0.0

Anti-Idling Switching Locomotives M/A/R 1.0 0.002 0.002 0.002 0.0

Line-Haul Locomotives 1.7 0.003 0.004 0.003 0.0

All MDDV and HDDV Class 8 Vehicles

On-Road 0.9 0.001 0.001 0.001 0.0

Non-road diesel engines Non-road 1.1 0.003 0.004 0.003 0.0

Cetane Additive Program

All diesel engines Non-road 2.9 0.007 0.010 0.007 0.0MY2002 and earlier MDDV and HDDV

On-Road 1.4 0.002 0.002 0.002 0.0

Low-NOX Reflash All MDDV and HDDV Class 

8 Vehicles

On-Road 5.8 0.008 0.009 0.012 0.0

MCDI Class 8 Vehicles On-Road 0.7 0.001 0.001 0.001 0.0

Diesel Engines Non-road 3.6 0.010 0.013 0.009 0.0

Switching and Line-Haul Locomotives

M/A/R 2.1 0.003 0.004 0.003 0.0

Anti-Idling Switching Locomotives M/A/R 0.2 0.000 0.000 0.000 0.0

Line-Haul Locomotives 0.5 0.001 0.001 0.001 0.0

All MDDV and HDDV Class 8 Vehicles

On-Road 0.9 0.001 0.001 0.002 0.0

Non-road diesel engines Non-road 1.1 0.003 0.004 0.003 0.0

Cetane Additive Program

All diesel engines Non-road 2.9 0.004 0.005 0.006 0.0MY2002 and earlier MDDV and HDDV

On-Road 1.6 0.002 0.003 0.003 0.0

3-State Region9-State Region

Table 5.5-3. Estimated Visibility Impacts of Mobile Sources Control Strategies

Estimated visibility improvements (

Emission 

reduction in 

inventory 

sector (%)

Inventory 

Control strategy Equipment covered sector

75
Strategy Mobile Sources Affected Inventory

Cost effectiveness 

per visibility 

improvement 

($million/ 

deciview)

Low-NOX Reflash All MDDV and HDDV Class 8 Vehicles On-Road 516 

MCDI Class 8 Diesel Vehicles On-Road 22,947 

Diesel Engines Non-Road 5,032 

Switching and Line-Haul Locomotives M/A/R 5,033 

Anti-Idling Switching Locomotives M/A/R 659 

Line-Haul Locomotives 659 

All MDDV and HDDV Class 8 Vehicles On-Road (920) - 3,600

Non-road diesel engines Non-Road 1,683 

Cetane Additive Program All diesel engines Non-Road 1,938 

MY2002 and earlier MDDV and HDDV On-Road 8,836 

Low-NOX Reflash All MDDV and HDDV Class 8 Vehicles On-Road 616 

MCDI Class 8 Vehicles On-Road 6,171 

Diesel Engines Non-Road 3,952 

Switching and Line-Haul Locomotives M/A/R 3,954 

Anti-Idling Switching Locomotives M/A/R 2,299 

Line-Haul Locomotives M/A/R 2,299 All MDDV and HDDV Class 8 Vehicles On-Road (1,100) - 4,400

Non-road diesel engines Non-Road 5,872 

Cetane Additive Program All diesel engines Non-Road 10,552 

MY2002 and earlier MDDV and HDDV On-Road 10,554 

3-State Region9-State Region

Table 5.5-4. Cost Effectiveness of Mobile Source Control Strategies in Terms 

of Visibility Improvement

76
77

5.6 Miscellaneous Facility Analyses

In addition to the analyses of EGUs, ICI boilers, and individual EGU and ICI facilities

(see sections 5.1, 5.2, and Appendix C, respectively for those analyses), we also examined

several other facilities in various sectors. The purpose is to determine the cost effectiveness of

controlling these facilities in an effort to meet the reasonable progress goals set for 2008-2018.

The facilities examined fall into the following categories: cement manufacturing (Holcim, Inc. in

Dundee, MI), glass manufacturing (Cardinal FG in Menomonie, WI), lime manufacturing

(Rockwell Lime Company in Manitowoc, WI; CLM Corporation in Superior, WI), and oil

refineries (Murphy Oil in Superior, WI). Most of these are not subject to BART, and some had

been identified by stakeholders due to their close proximity to the Class I areas.

5.6.1 Cement Plants

The main emission unit of interest at cement plants are the cement rotary kilns. There are

two major types, wet and dry kilns, and subcategories within each type. On the whole, wet kilns

tend to produce more tons of cement (or “clinker”) but also require more energy than dry process

kilns. At the Holcim, Inc. plant, there are two long wet kilns producing approximately 1.2 55

million tons of clinker per year. The kilns use a mixture of coal, coke, oil, natural gas, and tires 56

as fuel. Table 5.6-1 lists the various control options for NO , and whether those options can be X

applied to the Holcim kilns. In Holcim’s permit, they stated that they have begun testing a

scrubber/oxidizer system at their plant (likely similar to the LoTOx system, a scrubber/oxidation

process designed to lower the temperature needed to produce clinker), although no conclusions

had yet been reported. There was limited information on SO controls for cement kilns, 2

particularly long wet kilns. Process modification and replacement of the kiln with a dry process

kiln are the most feasible options for SO control. SNCR is another control technology available 2

to preheater or precalciner cement kilns . SNCR has been tested primarily in European facilities 57

and on at least one facility in the United States. However, the kilns at the facility in question are

long wet rotating kilns which cannot use SNCR as a control method.50,52
CemSTAR is a process that introduces steel slag into the rotary kiln, lowering the temperature necessary to a

produce clinker, thus reducing both NO and SO emissions. X 2

78

Table 5.6-1. Control Technologies Available to Long Wet Kilns

Control Technology

Percent

Efficiency

Applicable at Holcim

plant

NOX

Process modification (i.e., CemSTAR ,a

fuel switching)

9-70 Yes

Conversion to dry process kilns 65 Yes

LoTox (lower temperature oxidation TM

techology)

85 Yes

SO2

Process modification 9-70 Yes

Conversion to dry process kilns 65 Yes

5.6.1.1 Factor 1 - Costs

A 2006 report analyzed Texas wet kiln cement facilities, providing cost effectiveness

figures for kilns of similar size and production as the Holcim plant in Michigan (the Ash Grove

facility produces approximately 160 tons of clinker per hour versus Holcim’s 137 tons of clinker

per hour). Table 5.6-2 shows the cost effectiveness figures for NO control at the Holcim facility X

using the Ash Grove cost figures. Due to the limited amount of information available for SO2

controls we were only able to determine a cost effectiveness figure for conversion to dry process.
CemSTAR requires little additional equipment and the steel slag may replace other materials used in the a

clinker process (such as shale or clay). The greatest amount of NO reductions for wet kilns can be achieved by X

CemSTAR because it greatly reduces the amount of heat required to produce clinker. Since the Holcim plant already

burns a mixture of fuels fuel switching will likely not provide substantial emissions reductions at a cost effective rate.

2

(Natural gas tends to produce higher NOX emissions than coal although coal increases the amount of SO

emissions. Petroleum coke produces fewer NOX emissions although it must be burned in tandem with other fuels,

and contains a high percentage of sulfur.)

79

Table 5.6-2. Cost Effectiveness of NO and SO Control X 2

Technologies for Holcim, Inc. Facility

Control Technology

Percent

Efficiency

Emissions

Reduction

(tons/year)

Cost

Effectiveness

($/ton reduced)

NOX

Conversion to Dry Process

Kiln 65 946 9848

LoTOx 85 1237 1399 TM

Process Modification 9-70 131-1019 NAa

SO2

Conversion to Dry Process

Kiln

65 4644 2010

5.6.1.2 Factor 2 - Time Necessary for Compliance

It is anticipated that states will require two years to create and promulgate the rule.

X

Installation of a single NO system typically takes less than 18 months. However, since LoTOxTM

requires a scrubber, it will take approximately 26 months to procure the necessary capital, plan,

and construct the system. Similarly, we assume it will take approximately two years if the plant

decides to replace the wet kilns with dry kilns. Therefore, it will take the facility a maximum of

five years to come into compliance.

5.6.1.3 Factor 3 - Energy and Other Impacts

Information and data on the candidate control strategies for the Holcim facility were not

available to determine energy and other impacts. LoTOx , a relatively recent control strategy, TM

does not require additional catalysts and will not likely add additional water or solid waste. It is

also unclear whether process modifications (such as CemSTAR) or a conversion to a dry process

kiln would add additional waste (solid or liquid), although dry process kilns tend to use less

energy than wet kilns since water does not need to be heated to produce clinker.
80

5.6.1.4 Factor 4 - Remaining Equipment Life

Cement kilns have no set equipment life. The units, whether wet or dry, can be

refurbished to extend their lives. In addition, it is assumed that controls will be not be applied to

units that are expected to be retired prior to the amortization period for the control equipment. 

Therefore, remaining equipment life is not expected to affect the cost of control for cement kilns.

5.6.1.5 Factor 5 - Visibility Impacts

Visibility impacts are presented in terms of the change in emissions per distance (Q/d).

Deciview information for this facility was not available and thus not calculated. Table 5.6-3

presents the estimated visibility impacts at the four northern-Midwest Class I areas for the

candidate cement kiln control strategies in terms of the change in emissions per distance (Q/d).

The average visibility impact for each technology is also calculated along with the cost

effectiveness. 

The conversion to a dry kiln process is more expensive on a per mile basis than the EGU1

or EGU2 NO and SO costs for the 3- and 9-state regions (Table 5.1-11). LoTox, on the other X 2

hand, is greater than the 3-state regional EGU1 cap, less than the 9-state EGU1 cap, and less than

the 3- and 9-state EGU2 regional caps.
Strategy

Boundary 

Waters Voyageurs Isle Royale Seney Average 

Boundary 

Waters Voyageurs Isle Royale Seney A

Conversion to Dry Process Kiln (NOx)

2.56 2.28 3.01 4.62 3.12 1.67 1.48 1.96 3.00 

LoTOx 2.56 2.28 3.01 4.62 3.12 2.18 1.94 2.56 3.93 Process Modification 2.56 2.28 3.01 4.62 3.12 1.01 0.901 1.19 1.82 

Conversion to Dry Process Kiln (SO2)

13 11 15 23 15 8 7 10 15 

Reductions in the summations of emission-to-dis

ratios (Q/d; tons/yr-mi)*

Table 5.6-3. Estimated Visibility Impacts of Control Strategies for Holcim Cement 

Baseline summations of emission-to-distance ratios (Q/d; 

tons/yr-mi)

81
World Bank Group. 1998. “Glass Manufacturing.” Pollution Prevention and Abatement Handbook.

a

82

5.6.2 Glass manufacturing plant

The majority of NO and SO emissions come from the melting furnace in glass plants X 2

due to the high temperatures and the fuels used. The facility under analysis (Cardinal FG in

Wisconsin) is a flat glass manufacturing plant. Flat glass includes plate and architectual glass,

mirrors, and automotive windscreens . The Cardinal FG facility uses natural gas as the primary a

fuel in its melting furnace, and produces 600 tons per day. A dry scrubber system is already

2

installed at the plant; therefore, SO emissions will not need to be controlled at this facility.

The available NO control technologies available at glass manufacturing plants are listed X

in Table 5.6-4.58

5.6.2.1 Factor 1 - Costs

Due to insufficient information to determine cost equations for cost effectiveness figures,

we provide the cost effectiveness figures from the Alternative Control Techniques document

(U.S. EPA, 1994) for a model plant of comparable size to the Cardinal FG facility. The model

plant produces 750 tons of flat glass per day; the Cardinal FG facility produces 600 tons of flat

glass per day. Table 5.6-5 provides the capital costs, annual costs, annualized costs, and cost

effectiveness for the above-listed technologies..

5.6.2.2 Factor 2 - Time Necessary for Compliance

It is anticipated that states will require two years to create and promulgate the rule.

X

Installation of a single NO system typically takes less than 18 months. Again, the facility has

already installed a scrubber system so SO is not analyzed. Thus to bring the one furnace at the 2

plant into compliance it will take a maximum of 3 years.

Table 5.6-4. NO Control Technologies X

Available for Melting Furnaces at the Cardinal

FG Facility

Control Technology

Percent

Efficiency

Applicable to

Cardinal FG Facility

LNB 40 Yes

Oxy-firing 85 Yes a

Electric boost 10 Yes b

SCR 75 Yes

SNCR 40 Yes

2

a Process that uses oxygen and CO to combust with fuel instead of air

b Electricity currents are added to the gas to aid in combustion in the furnace
83

Table 5.6-5. Costs and Cost Effectiveness for NO Control Technologies X

Available to Cardinal FG Facility

Control Technology

Emissions

reductions

(tons/year)

Capital Cost

(m$2005)

Annual Cost

(m$2005)

Annualized Costs

(m$2005)

Cost Effectiveness

($2005/ton)*

LNB 1014 1765 818 1055 1041

Oxy-firing 2283 12925 4730 6467 2833

Electric boost 202 - 692 692 3426

SCR 1951 3544 1581 2057 1054

SNCR 1048 2055 870 1146 1094

* Cost effectiveness values are from EPA’s ACT documentation for NOX emissions from glass manufacturing, and reflect a

model glass manufacturing plant producing 750 tpd. Cardinal FG facility produces 600 tpd.

5.6.2.3 Factor 3 - Energy and Other Impacts

The following factors were used to determine the non-air impacts of SCR and SNCR.

Sufficient information for LNB, Oxy-firing, and electric boost was not available. For SCR:

X

• 0.021 tons of catalyst waste are generated for each ton of NO reduced

X

• 0.89 mWh electricity used/ton NO reduced

X

• 0.25 tons of steam produced/ton NO reduced

2

• 1 ton of CO produced/mWh of electricity used

2

• 0.6 tons of CO produced/ton steam produced

The results are presented in Table 5.6-6.

Table 5.6-6. Estimated Energy and Non-Air Environmental Impacts of

Control Strategies at Cardinal FG Glass Manufacturing Facility

Strategy Additional

electricity

requirements

(GW-hrs /year)

Steam

requirements

(1000 tons/yr)

Wastewater

produced

(million

gallons/year)

Solid waste

produced

(1000

tons/year)

Additional

CO2

emitted

(1000

tons/year)

SCR 0.8 0.2 - 0.9 0.9

SNCR 0.007 - - 0.007 0.01

5.6.2.4 Factor 4 - Remaining Equipment Life

Glass furnaces have no set equipment life. The units can be refurbished to extend their

lives. In addition, it is assumed that controls will be not be applied to units that are expected to be

retired prior to the amortization period for the control equipment. Therefore, remaining

equipment life is not expected to affect the cost of control for glass furnaces.
84

5.6.2.5 Factor 5 - Visibility Impacts

Visibility impacts are presented in terms of the change in emissions per distance (Q/d). 

Deciview information for this facility was not available and thus not calculated. Table 5.6-7

presents the estimated visibility impacts at the four northern-Midwest Class I areas for the

candidate glass furnace control strategies. The average visibility impact for each technology is

also calculated along with the cost effectiveness.

LNB and SCR are less expensive on a per mile basis than the EGU1 or EGU2 costs of

potential control measures for the 3- and 9-state regions (see Table 5.1-11 for regional costs).

Oxy-firing and electric boost, on the other hand, are more expensive than the 3- and 9-state

EGU1 and EGU2 regional caps. Finally, SNCR is more expensive than the 3-state EGU1

regional cap, and is less expensive than the costs 9-state EGU1 regional cap and the 3- and 9-

state EGU2 regional caps.
Strategy

Boundary 

Waters Voyageurs Isle Royale Seney Average 

Boundary 

Waters Voyageurs Isle Royale Seney Aver

LNB 6.44 5.51 5.33 4.45 5.43 2.58 2.20 2.13 1.78 2.1Oxy-firing 6.44 5.51 5.33 4.45 5.43 5.48 4.68 4.53 3.78 4.6Electric Boost 6.44 5.51 5.33 4.45 5.43 0.644 0.551 0.533 0.445 0.54SCR 6.44 5.51 5.33 4.45 5.43 4.83 4.13 3.99 3.33 4.0SNCR 6.44 5.51 5.33 4.45 5.43 2.58 2.20 2.13 1.78 2.1

Reductions in the summations of emission-to-distanc

ratios (Q/d; tons/yr-mi)*

Table 5.6-7. Estimated Visibility Impacts of Control Strategies for Cardinal FG Glass F

Baseline summations of emission-to-distance ratios 

(Q/d; tons/yr-mi)

85
86

5.6.3. Lime Manufacturing Plants

Lime manufacturing is the product of the calicination of limestone, and is created in kilns.

These kilns are fueled by coal, oil, and/or natural gas. The primary source of SO emissions is the 2

kiln fuel, and a large portion of the fuel sulfur is not emitted as it reactions with calcium oxides

produced in the kiln during the lime production process. Table 5.6-8 presents the control

technologies available for lime manufacturing plants (Pechan, 1998), their reduction efficiencies,

and their applicability to the two individual facilities analyzed: Rockwell Lime Company and

CLM Corporation, both located in Wisconsin.

Table 5.6-8. Control Technologies Available for

Lime Manufacturing Plants

Control Technology Percent

Efficiency

Applicable

at

Rockwell 

Applicable at

CLM

NOX

Mid-kiln

firing

30 Yes Yes

LNB 30 Yes Yes

SNCR 50 Yes Yes

SCR 80 Yes Yes

SO2

FGD 90 Yes Yes

The only SO control technology for which information was available for lime manufacturing 2

plants is flue gas desulfurization (FGD).

5.6.3.1 Factor 1 - Costs

AirControlNET documentation provided cost equations for the capital, and operations

and maintenance costs for SO controls. Cost equations were not available for NO controls, 2 X

although AirControlNET did provide default cost effectiveness values, and should be considered

conservative estimates for the CLM Corporation and Rockwell facilities. The results are

presented in tables 5.6-9.
Facility

Control 

Technology

Percent 

Efficiency

Emissions 

Reduction 

(tons)

Total Annualized 

Costs ($M2005)

Cost Effectiveness 

($2005/ton)

CLM Corp.

Mid-kiln firing

30 84.4 58 688

LNB 30 84.4 71 837SCR 50 141 710 5,037SNCR 80 225 272 1,211FGD 90 127 641 4,828

Rockwell

Mid-kiln firing

30 4.14 2.85 688

LNB 30 4.14 3.47 837SCR 50 6.90 34.8 5,037SNCR 80 11.03 13.4 1,211FGD 90 152 19.4 128

Table 5.6-9. Costs and Cost Effectiveness for NOx and SO2 

Control Technologies at Rockwell and CLM Corporation Lime 

Manufacturing Facilities*

* Cost effectiveness numbers were taken from AirControlNET documentation and may not reflect the actual cost effectiveness for these two particular facilities.

87
88

5.6.3.2 Factor 2 - Time Necessary for Compliance

It is anticipated that states will require two years to create and promulgate the rule.

X

Installation of a single NO system typically takes less than 18 months. The typical amount of

2 2 time to set up a SO system is 26 months. Each additional SO emissions unit requires 3 more

months. It is anticipated it will take the CLM Corporation facility 5 years to come into

compliance, and Rockwell five and a half years to come into compliance.

5.6.2.3 Factor 3 - Energy and Other Impacts

The following factors were used to determine the non-air impacts of SCR and SNCR.

Sufficient information for LNB, Oxy-firing, and electric boost was not available. For SCR:

• 0.021 tons of catalyst waste are generated for each ton of NOX reduced

• 0.89 mWh electricity used/ton NOX reduced

• 0.25 tons of steam produced/ton NOX reduced

2

• 2.8 tons of sludge/ton SO reduced

2

• 3.7 gallons of water/ton SO reduced

2

• 1 ton of CO produced/mWh of electricity used

2

• 0.6 tons of CO produced/ton steam produced

The results are presented in Table 5.6-10.

Table 5.6-10. Estimated Energy and Non-Air Environmental Impacts of

Control Strategies at Rockwell and CLM Corporation Lime Manufacturing

Facilities

Facility Strategy

Additional

electricity

requirements

(GW-hrs /year)

Steam

requirements

(1000 tons/yr)

Wastewater

produced

(million

gallons/year)

Solid

waste

produced

(1000

tons/year)

Additional

CO2

emitted

(1000

tons/year)

CLM Corp. SCR 0.25 0.07 NA 6 0.292

SNCR 0.004 - NA - 0.004

FGD 0.133 0.332 0.0005 0 0.332

Rockwell SCR 12.3 3.45 - 0.290 14.3

SNCR 0.349 - - - 0.349

FGD 0.071 0.202 0.0003 0.227 0.202

5.6.3.4 Factor 4 - Remaining Equipment Life

Lime kilns, like cement kilns, have no set equipment life. The units can be refurbished to

extend their lives. In addition, it is assumed that controls will be not be applied to units that are

expected to be retired prior to the amortization period for the control equipment. Therefore,

remaining equipment life is not expected to affect the cost of control for lime kilns.
89

5.6.3.5 Factor 5 - Visibility Impacts

Visibility impacts are presented in terms of the change in emissions per distance (Q/d). 

Table 5.6-11 presents these impacts at the four northern-Midwest Class I areas for the candidate

lime kiln control strategies. The average visibility impact for each technology is also calculated

along with the cost effectiveness. Again, the cost effectiveness values for NOX technologies

were presented by AirControlNET without background information on the size of the kilns, and

so while the numbers reflect inexpensive technologies (and visibility cost effectiveness), these

are conservative estimates. Additionally, the emissions are already low for the Rockwell facility.

With the exception of FGD and SNCR for the CLM Corporation facility, all other

candidate technologies are less expensive than the EGU1 and EGU2 3- and 9-state regional caps

costs (Table 5.1-11).
Facility Strategy

Boundary 

Waters Voyageurs Isle Royale Seney Average 

Boundary 

Waters Voyageurs Isle Royale Seney 

CLM Corporation Mid-kiln firing 3.21 2.34 1.65 0.98 2.04 0.964 0.702 0.494 0.293 

LNB 3.21 2.34 1.65 0.98 2.04 0.964 0.702 0.494 0.293 SCR 3.22 2.34 1.65 0.98 2.04 2.57 1.87 1.32 0.781 SNCR 3.21 2.34 1.65 0.98 2.05 1.61 1.17 0.824 0.488 

FGD 1.10 0.800 0.563 0.333 0.698 0.988 0.720 0.507 0.300 

Rockwell Mid-kiln firing 0.189 0.157 0.229 0.356 0.233 0.0566 0.047 0.069 0.107 

LNB 0.189 0.157 0.229 0.356 0.233 0.0944 0.078 0.114 0.178 SCR 0.189 0.157 0.229 0.356 0.233 1.69 1.40 2.05 3.19 SNCR 0.189 0.157 0.229 0.356 0.233 0.151 0.125 0.183 0.285 FGD 1.81 1.50 2.19 3.41 2.23 0.0566 0.047 0.069 0.107 

Reductions in the summations of emission-t

ratios (Q/d; tons/yr-mi)

Table 5.6-11. Estimated Visibility Impacts of Control Strategies for Rockwell and CLM Corpor

Baseline summations of emission-to-distance ratios 

(Q/d; tons/yr-mi)

90
91

5.6.4. Oil Refinery

For our analysis the emissions units of interest at oil refineries are the process heaters and

the fluid catalytic cracking unit (FCCU). Process heaters transfer the heat created through the

burning of fuels to other processes in the production line. FCCUs convert heavy hydrocarbons

into lighter hydrocarbons (ExxonMobil, 2006). Of the three process heaters at Murphy Oil, one

runs on oil and the other two run on natural gas. Table 5.6-12 presents the control technologies

available for oil refineries, their reduction efficiencies, and their applicability to the facility

analyzed: Murphy Oil, USA in Wisconsin.

Table 5.6-12. Control Technologies Available for

the Murphy Oil Refinery

Control Technology Percent Efficiency Applicable at

Murphy Oil 

NOX

LNB 50 Yes

SNCR 60 Yes

SCR 75 Yes

LNB+FGR 55 Yes a

ULNB 75 Yes

SO2

FGD 90 Yes b

a FGR is flue gas recirculation

b FGD is flue gas desulfurization

5.6.3.1 Factor 1 - Costs

AirControlNET documentation provided cost equations for the capital, and operations

and maintenance costs for SO controls. Cost equations were not available for NO controls, 2 X

although AirControlNET did provide default cost effectiveness values. Tables 5.6-13 and 5.6-14

present the results.
92

Table 5.6-13. Cost Effectiveness of NO Control X

Technologies at Model Oil Refinery

Control Technology Percent Efficiecy

Total Emissions

Reduction (tons)

Cost

Effectiveness

($/ton)

LNB 50 159 3288

SNCR 60 191 4260

SCR 75 239 17997

LNB+FGR 55 175 4768

ULNB 75 239 2242

Table 5.6-14. Cost Effectiveness for SO2 Control

Technologies for Murphy Oil Refinery Facility

Control

Technology

Percent

Efficiency

Total Emissions

Reduction (tons)

Total Annualized

Costs (M$2005)

Cost Effectiveness

($2005/ton)

FGD 90 538 580,390 1078

5.6.3.2 Factor 2 - Time Necessary for Compliance

It is anticipated that states will require two years to create and promulgate the rule.

X

Installation of a single NO system typically takes less than 18 months. The typical amount of

2 2 time to set up a SO system is 26 months. Each additional SO emissions unit requires 3 more

months. It is anticipated it will take the Murphy Oil facility a maximum of 6 years to come into

compliance.

5.6.2.3 Factor 3 - Energy and Other Impacts

The following factors were used to determine the non-air impacts of SCR, SNCR, and

FGD. Sufficient information for LNB, Oxy-firing, and electric boost was not available. For SCR:

X

• 0.021 tons of catalyst waste are generated for each ton of NO reduced

X

• 0.89 mWh electricity used/ton NO reduced

X

• 0.25 tons of steam produced/ton NO reduced

2

• 2.8 tons of sludge/ton SO reduced

2

• 3.7 gallons of water/ton SO reduced

2

• 1 ton of CO produced/mWh of electricity used

2

• 0.6 tons of CO produced/ton steam produced

The results are presented in Table 5.6-15.
93

Table 5.6-15. Estimated Energy and Non-Air Environmental

Impacts of Control Strategies at Murphy Oil Refinery Facility

Strategy

Additional

electricity

requirements

(GW-hrs /year)

Steam

requirements

(1000

tons/yr)

Wastewater

produced

(million

gallons/year)

Solid

waste

produced

(1000

tons/year)

Additional

CO2 emitted

(1000

tons/year)

SCR .0009 .0003 - .02 .9

SNCR .00002 - - - .02

FGD 1 1 0.002 2 1

5.6.3.4 Factor 4 - Remaining Equipment Life

Process heaters and FCCUs have no set equipment life. The units can be refurbished to

extend their lives. In addition, it is assumed that controls will be not be applied to units that are

expected to be retired prior to the amortization period for the control equipment. Therefore,

remaining equipment life is not expected to affect the cost of control for oil refineries

.

5.6.3.5 Factor 5 - Visibility Impacts

Visibility impacts are presented in terms of the change in emissions per distance (Q/d). 

Table 5.6-16 presents the estimated visibility impacts at the four northern-Midwest Class I areas

for the candidate oil refinery control strategies. The average visibility impact for each technology

is also calculated along with the cost effectiveness.

All control technologies, with the exception of SCR, are less expensive than the costs to

reach the 3- and 9-state EGU1 and EGU2 regional caps. SCR is more expensive for both the 3-

and 9-state EGU1 and EGU2 regional caps (see Table 5.1-11).
Strategy

Boundary 

Waters Voyageurs Isle Royale Seney Average 

Boundary 

Waters Voyageurs Isle Royale Seney Average

LNB 3.51 2.59 1.84 1.10 2.26 1.75 1.30 0.921 0.552 1.13 SCR 3.51 2.59 1.84 1.10 2.26 2.10 1.56 1.10 0.662 1.36 SNCR 3.51 2.59 1.84 1.10 2.26 2.63 1.95 1.38 0.828 1.70 LNB+FGR 3.51 2.59 1.84 1.10 2.26 1.93 1.43 1.01 0.607 1.24 ULNB 3.51 2.59 1.84 1.10 2.26 2.63 1.95 1.38 0.828 1.70 FGD 6.57 4.86 3.45 2.07 4.24 5.92 4.38 3.11 1.86 3.82 

Reductions in the summations of emission-to-distance 

ratios (Q/d; tons/yr-mi)*

Table 5.6-16. Estimated Visibility Impacts of Control Strategies for Murphy Oil Refi

Baseline summations of emission-to-distance ratios 

(Q/d; tons/yr-mi)

94
95

6. Summary and Conclusions

This study has analyzed several possible control strategies intended to improve visibility

in four northern-Midwest Class I areas. These are the Boundary Waters Canoe Area Wilderness,

Voyageurs National Park, Isle Royale National Park, and the Seney Wilderness Area. Potential

control strategies were evaluated for two geographic regions, a 3-state region and a 9-state

region. As shown in Figure 6-1, the 3-state region includes Michigan, Minnesota, and

Wisconsin, which are the three states immediately surrounding the northern-Midwest Class I

areas. The 9-state region includes these three states and adds six surrounding states – North and

South Dakota, Iowa, Missouri, Illinois, and Indiana.

The potential control strategies would address priority pollutants and emission sources

which have been identified in previous modeling efforts by the MRPO and the Midwest States as

significant contributors to visibility impairment in the region. Control strategies for the

following emissions and emission source categories have been evaluated:

2 X • SO and NO emissions from electric generating units (EGUs)

2 X • SO and NO emissions from Industrial, commercial and institutional (ICI) boilers

X

• NO emissions from reciprocating engines and turbines

• Ammonia from agricultural operations

X

• NO emissions from onroad and nonroad mobile sources

Figure 6-1. Geographic regions for the factor analysis.
a

 The EGU projections used in this study are taken from the VISTAS 2.1.9 version of IPM, which was

developed in July 2005. In January 2007, EPA prepared new EGU projections (i.e., 3.0 version of IPM). The new

EGU projections reflect lower 2018 SO2 emissions for the 3-state region (about 500 TPD less). The MRPO is

currently updating its regional modeling inventory to reflect a more current base year (2005) and improved future

year emission estimates, including use of the new EGU projections. The new inventory will be available in mid2007.

96

The impacts of on-the-books and on-the-way Federal regulatory programs impacting

these priority sectors have been analyzed. These programs include the following:

• Clean Air Interstate Rule (CAIR)a

• BART for available states (Michigan, Minnesota, Wisconsin, and North Dakota)

• Maximum Achievable Control Technology (MACT) standards for combustion turbines

and industrial boilers

• On-road mobile source programs (i.e., 2007 Highway Diesel Rule, Tier II emission

standards, and low sulfur gasoline standards)

• Non-road mobile source programs (i.e., Non-road Diesel Rule, Control of Emissions

from Unregulated Non-road Engines, and the Locomotive/Marine Advance Notice of

Proposed Rulemaking)

The on-the-books analysis serves both to (1) assess progress toward the reasonable further

progress goal with existing control measures, and (2) provide a frame of reference for estimating

the amounts of emissions available for additional control.

Figure 6-2 illustrates the visibility improvements expected with on-the-books control

measures for the four northern-Midwest Class I areas. The figure shows the projected impacts of

existing control measures in 2009, 2012, and 2018 (blue circles), based on CAMx modeling

studies performed by the MRPO. These projected impacts of on-the-books measures are

superimposed on a line representing the target glide path to natural visibility conditions. 

Figure 6-2 shows that the on-the-books control measures give some improvement over baseline

conditions (in 2002), but fall short of achieving the glide path.

Table 6-1 describes the potential emission control strategies which have been evaluated

for improving visibility in the northern-Midwest Class I areas. The following subsections

summarize the estimated impacts of these candidate control strategies. The subsections address

each of the four regional haze progress factors: cost, time required for compliance, energy and

other environmental impacts, and the impact of remaining equipment life. The final subsection

analyzes the impacts of the potential control measures on visibility, and summarizes the costeffectiveness of these measures in terms of visibility improvement.

6.1 Factor 1 – Costs

Table 6.1-1 gives estimated average cost-effectiveness values (in terms of the cost per ton

of emissions reduced) for potential control strategies for priority emission sources categories.

The table also shows estimated cost effectiveness values for controlling the selected individual

facilities outside of priority source categories. For comparison, Table 6.1-2 shows costeffectiveness estimates previously published for different on-the-books control programs. 
Figure 6-2. Estimated visibility impacts of on-the-books controls in comparison with reasonable progress goals for the northern-Midwest

Class I areas.
Emission category Control strategy Description

EGU EGU1 SO2 limited to 0.15 lb/MM-BTU

NOX limited to 0.10 lb/MM-BTU

EGU2 SO2 limited to 0.10 lb/MM-BTU

NOX limited to 0.07 lb/MM-BTU

ICI boilers ICI1 40% SO2 reduction from 2018 baseline emissions

60% NOX reduction from 2018 baseline emissions

ICI Workgroup 77% SO2 reduction from 2018 baseline emissions

70% NOX reduction from 2018 baseline emissions

Reciprocating engines and turbines

Reciprocating engines emitting 100 tons/year or more

89% NOX reduction from 2018 baseline emissions

Turbines emitting 100 tons/year or more

84% NOX reduction from 2018 baseline emissions

Reciprocating engines emitting 10 tons/year or more

89% NOX reduction from 2018 baseline emissions

Turbines emitting 10 tons/year or more

84% NOX reduction from 2018 baseline emissions

Agricultural sources

Mobile sources Low-NOX Reflash Install low-NOX software to counteract advanced 

computer controls installed on MY 1993-1998 HDDV that increase NOX emissions

Midwest Clean Diesel Initiative (MCDI)

A collaborative organization between federal, state, and local agencies funding projects that will reduce diesel emissions through operational changes, technological improvements, and cleaner fuels

Anti-Idling Strategies to reduce NOX emissions that take the form 

of enforced shutdown policies, auxiliary power units (APUs), automatic engine shut-off technology, and truck stop electrification (TSE).

Cetane Additive Program Introduces additives to diesel fuel at the distribution 

source to increase the cetane number to approximately 50.

Cement Plants Process Modification Fuel switching, CEMStar (a process that introduces 

steel slag into the rotary kiln, lowering the temperature necessary to produce clinker)

Conversion to dry kilnLoToxTM Lower temperature oxidation technology

Table 6-1. Summary of Candidate Future Control Measures Evaluated for Regional 

Haze

Achieve a 10-15% NH3 reduction through the use of a variety of best management 

98
Glass Manufacturing LNB Low-NOX Burner

Oxy-firing Process that uses oxygen and CO2 to combust with 

fuel instead of air

Electric boost Electricity currents are added to the gas to aid in 

combustion in the furnace

SCR Selective catalytic reduction

SNCR Selective non-catalytic reduction

Lime Manufacturing Mid-kiln firing A form of staged combustion of fuels in which a 

specially designed fuel injection system introduces a second fuel source at a midpoint in the kiln.

LNB Low-NOX Burner

SNCR Selective non-catalytic reductionSCR Selective catalytic reductionFGD Flue Gas Desulfurization

Oil Refinery LNB Low-NOX Burner

SNCR Selective non-catalytic reductionSCR Selective catalytic reductionLNB+FGR Low-NOX Burner with Flue Gas RecirculationULNB Ultra Low-NOX BurnerFGD Flue Gas Desulfurization

Table 6-1. Summary of Candidate Future Control Measures Evaluated for Regional 

Haze (continued)

99
Emission category Control strategy Region SO2 NOX NH3

EGU EGU1 3-State 1,540 2,037

9-State 1,743 1,782

EGU2 3-State 1,775 3,016

9-State 1,952 2,984

ICI boilers ICI1 3-State 2,992 2,537

9-State 2,275 1,899

ICI Workgroup 3-State 2,731 3,814

9-State 2,743 2,311

3-State 538

9-State 506

3-State 754

9-State 754

3-State 1,286

9-State 1,023

3-State 800

9-State 819

10% reduction 3-State 31 - 2,700

9-State 31 - 2,700

15% reduction 3-State 31 - 2,700

9-State 31 - 2,700

Mobile sources Low-NOX Reflash 3-State 241

9-State 241

MCDI 3-State 10,697

9-State 2,408

Anti-Idling 3-State (430) - 1,700

9-State (430) - 1,700

Cetane Additive Program 3-State 4,119

9-State 4,119

Cement Plants Process Modification Michigan -

Conversion to dry kiln Michigan 9,848

LoToxTM Michigan 1,399

Glass Manufacturing LNB Wisconsin 1,041

Oxy-firing Wisconsin 2,833

Electric boost Wisconsin 3,426

SCR Wisconsin 1,054

SNCR Wisconsin 1,094

Lime Manufacturing Mid-kiln firing Wisconsin 688

LNB Wisconsin 837

SNCR Wisconsin 1,210

SCR Wisconsin 5,037

FGD Wisconsin 128 - 4,828

Oil Refinery LNB Wisconsin 3,288

SNCR Wisconsin 4,260

SCR Wisconsin 17,997

LNB+FGR Wisconsin 4,768

ULNB Wisconsin 2,242

FGD Wisconsin 1,078

Average Cost effectiveness ($/ton)

Table 6.1-1. Estimated Cost Effectiveness for Potential Control Measures in 

Terms of Emission Reductions

Agricultural sources

Reciprocating engines 

and turbines

Reciprocating engines 

emitting 100 tons/year or 

Turbines emitting 100 

tons/year or more

Reciprocating engines 

emitting 10 tons/year or more

Turbines emitting 10 

tons/year or more

100
101

 Most of the projected cost-effectiveness values for potential additional controls

(Table 6.1-1) are within the range of cost-effectiveness values estimated for on-the-books

controls (Table 6.1-2). Cost-effectiveness values for additional EGU controls are somewhat

higher than those estimated for the CAIR program. This is to be expected, since the EGU

controls require emission reductions beyond those projected for CAIR in the Midwest region. 

ICI control measures are estimated to be somewhat more expensive than EGU control measures

per ton of emission reduction.

Table 6.1-2. Estimated Cost-effectiveness of On-the-Books Programs

Cost-effectiveness ($/ton)

Control Program SO2 NOX

CAIR 720–1,200 1,400–2,600

BART 300–963 248–1,770

MACT 1,500 7,600

Onroad mobile source programs 1,300–2,300

Nonroad mobile source programs (1,000)–1,000

Emission controls for reciprocating engines and turbines are comparably cost-effective,

especially for sources emitting 100 tons/year or more of NOX. However, overall potential

emission reductions for these sources (in terms of tons per year) are considerably less than the

potential emission reductions for EGUs and ICI boilers.

The cost-effectiveness estimates for reducing ammonia emissions from agricultural

operations cover a wide range. This range results from uncertainties in the effectiveness of one

potential control measure, which is the planting of trees to absorb ammonia emissions from

animal houses and other strong sources of emissions. A four-year measurement study has

indicated that trees can be effective for removing ammonia, but the measured effectiveness

varied widely during the course of the study.

Cost-effectiveness estimates for mobile source programs also vary widely depending on

the specific program. Some programs, such as anti-idling measures, programs are very costeffective for reducing NOX emissions, even showing a potential cost savings. It must be noted

that all of the mobile source control programs are designed to control other pollutants in addition

to NOX. In fact, the cetane additive program and the Midwest Control Diesel Initiative are

focused on reducing primary emissions of diesel particulate matter, and reduce NOX emissions as

a collateral benefit. Therefore, the costs of these programs should not be judged on the basis of

cost-effectiveness values for NOX alone.

Analyses of selected individual analyses in the lime manufacturing facilities, cement,

petroleum refining, and glass manufacturing industries indicated that control options generally

are available within the same cost-effectiveness range found for the priority emission source
102

categories included this analysis. Comparison of different cost models in some Individual

facility analyses indicated that control cost estimates for any particular facility can vary by at

least a factor of 2.

2 X It must also be noted that the health benefits of reducing SO and NO emissions are

generally expected to outweigh the costs of control (as discussed in Section 6.3). These health

benefits stem from the reduced ambient levels of PM and ozone which would result from the 2.5

control of SO and NO . 2 X

6.2 Factor 2 – Time Necessary for Compliance

Table 6.2-1 summarizes the estimated time required for sources to comply with the

potential regional haze control measures. As the Table shows, all of the control measures can be

attained by 2018. It must be noted that if tree plantings are used to reduce ammonia emissions,

these trees would require up to 10 years to grow, depending on the size of trees planted. Larger

trees would take less time to have a significant impact on ammonia emissions, but would cost up

to 6 times as much as small plants.

6.3 Factor 3 – Energy and Other Impacts

Table 6.3-1 summarizes the estimated energy, solid waste, and wastewater impacts for the

candidate future regional haze control measures. The table also shows estimated increases in

carbon dioxide emissions which would result from the implementation of these control measures. 

This increased CO stems from the generation of electricity and steam to meet the needs of add- 2

on control devices such as scrubbers and SCR. In addition, CO is generated as a byproduct of 2

most SO control systems, either in the reaction of SO with limestone or in the production of 2 2

2

lime to absorb SO .

The energy and other environmental impacts of the potential control measures are

believed to be manageable. For instance, the largest energy demand is the electricity and steam

requirement for EGU control measures. This increased energy demand would be less than 1% of

the total electricity and steam production of EGUs in the region. Solid waste disposal and

wastewater treatment costs are expected to be less than 5% of the total operating costs of

pollution control equipment. Wastewater is generally expected to be treated in existing

wastewater treatment facilities at the affected emission sources.

The SO , NO , and ammonia controls would have beneficial environmental impacts by 2 X

reducing acid deposition and nitrogen deposition to water bodies and natural landscapes. 

Reductions in these gaseous pollutants for regional are designed to reduce formation of fine

particles that impair visibility. Such reductions would also result in decreases in the ambient

2.5 levels of PM , with corresponding health benefits. In addition, broad regional reductions in

NO would result in reductions in background levels of ambient ozone. These reductions in X

PM and ozone will reduce levels of these pollutants in urban areas, and improve the potential 2.5

for urban areas in the Midwest and Northeast to attain the National Ambient Air Quality

Standards (NAAQS).
Emission category SO2 NOX NH3

EGU (all strategies) 6.5 5.5

ICI boilers (all strategies) 6.5 5.5

Reciprocating engines and 

turbines 5.5 - 6.5

Agricultural sources

 Trees

 Other strategies

3-10

<1

Mobile sources

 Low-NOX

 MCDI

 Anti-Idling

 Cetane

4

ongoing

1.6-5

2

Cement Plants 5 5

Glass Manufacturing 3 3

Lime Manufacturing 5.5 5.5

Oil Refinery 6 6

Time Necessary for Compliance 

(years)

Table 6.2-1. Estimated Time Required for 

Compliance with Potential Control Measures

103
Emission 

category Control strategy Region Pollutant

Emission 

reduction 

(1000 

tons/year)

Additional 

electricity 

requirements 

(GW-hrs /year)

Additional 

diesel fuel 

requirements 

(1000 gal/year)

Steam 

requirements (1000 

tons/yr)

Solid wa

produce

(1000 

tons/yea

EGU EGU1 3-State SO2 466 706 - 510 - 

NOX 71 40 - 17 - 

9-State SO2 1,279 2,649 - 3,462 - 

NOX 224 110 - 46 - 

EGU2 3-State SO2 532 1,106 - 1,722 - 

NOX 106 174 - 73 - 

9-State SO2 1,455 3,504 - 5,439 - 

NOX 328 608 - 255 - 

ICI boilers ICI1 3-State SO2 33 13 - - 120 

NOX 22 37 - 5 0 

9-State SO2 105 37 - - 346 

NOX 73 214 - 12 1 

ICI Workgroup 3-State SO2 53 20 - - 186 

NOX 29 53 - 6 1 

9-State SO2 169 58 - - 537 

NOX 85 235 - 14 1 

Reciprocating engines and turbines

Reciprocating engines emitting 100 tons/year or more

3-State NOX -9-State NOX -

Turbines emitting 100 tons/year or more

3-State NOX -9-State NOX -

Reciprocating engines emitting 10 tons/year or more

3-State NOX -9-State NOX -

Turbines emitting 10 tons/year or more

3-State NOX -9-State NOX -

Not significant, the most cost effective control technology combustion technologies.Not significant, the most cost effective control technology combustion technologies.Not significant, the most cost effective control technology combustion technologies.Not significant, the most cost effective control technology combustion technologies.Not significant, the most cost effective control technology combustion technologies.

Table 6-3.1. Estimated Energy and Non-Air Environmental Impacts of Potential Control M

Not significant, the most cost effective control technology combustion technologies.Not significant, the most cost effective control technology combustion technologies.Not significant, the most cost effective control technology combustion technologies.

104
Agricultural 

sources

10% reduction 3-State NH3 27 - 6 - 13 - - 

9-State NH3 91 - 19 - 42 - - 

15% reduction 3-State NH3 41 - 9 - 19 - - 

9-State NH3 137 - 29 - 63 - - 

Mobile sources Low-NOX Reflash 3-State NOX -

9-State NOX -

MCDI 3-State NOX -

9-State NOX -

Anti-Idling 3-State NOX -

9-State NOX -

Cetane Additive Program 3-State NOX -

9-State NOX -

No other environmental impacts.No other environmental impactsAnti-idling strategies have no quantifiable environmental productions results in a 79% reduction in wastewater and No other environmental impactsNo other environmental impactsNo other environmental impactsNo other environmental impacts.

Table 6-3.1. Estimated Energy and Non-Air Environmental Impacts of Potential Control Measur

105
106

The MRPO carried out a previous modeling effort to evaluate the benefits of

2 X implementing the EGU emission caps for SO and NO over the five-state MRPO region. In this

2.5 study, the CAMx model was used to estimate reductions in ambient levels of PM and ozone as

a result of SO and NO emission reductions. The EPA Environmental Benefits Mapping and 2 X

Analysis Program (BenMAP) was used to quantify health benefits. These benefits would occur

not just in the region where emissions limitations are implemented, but also in areas downwind

of this region. 

The earlier benefits study provides an indication of the magnitudes of health benefits in

comparison to costs. When benefits in the entire modeling domain were considered, the

estimated values of these benefits outweighed the projected costs of control by more than a factor

of 10. When only benefits in the MRPO were considered, the predicted benefit values exceeded

estimated costs by a factor of 6.

6.4 Factor 4 – Remaining Equipment Life

Most of the control strategies evaluated in this study for regional haze are market-based

caps to be applied to a broad geographic region. It is assumed that controls will be not be applied

to units that are expected to be retired prior to the amortization period for the control equipment. 

Therefore, remaining equipment life is not expected to affect the cost of control for most control

measures. In addition, large emission sources such as EGUs and ICI boilers generally have no

set equipment life. In fact, many units have been refurbished multiple times. In the Midwest

region, more than 150 units are more than 60 years old, and some units are more than 80 years

old.

6.5 Factor 5 – Visibility Impacts

Table 6.5-1 shows the estimated incremental improvements that would be needed beyond

the impacts of on-the-books controls in 2018 in order to achieve the glide path natural visibility

at the four northern-Midwest Class I areas. Table 6.5-2 presents the estimated visibility impacts

of potential control strategies for the priority emission source categories. (Light extinction values

have not been modeled for the selected individual facilities outside the priority emission source

categories.) Because of the non-linear relationship between light extinction and deciviews (see

Section 3-5), the visibility improvement values in Table 6.5-2 are not strictly additive. However,

in these ranges – visibility improvements of 1 deciview or less with a baseline of about 20 – the

values can be added with only a small error (<1%).

Table 6.5-3 summarizes the average visibility impacts and cost-effectiveness information

for the potential control strategies. Cost-effectiveness values are given in terms of the cost per

pollutant reduction and also the cost per unit of visibility improvement. Figure 6.5-1 illustrates

the estimated impacts of potential regional haze strategies in relation to the impacts of on-thebook control measures, and in relation to the glide path to natural visibility conditions.
107

Table 6.5-1. Comparison of Visibility Goals in 2018 with Projected

Impacts for On-the-Books Controls

Pollutant

Estimated visibility impairment on the 20%

worst-visibility days (deciviews)a

Boundary

Waters Voyageurs

Isle

Royale Seney

Baseline conditions (2000–2004) 19.86 19.48 21.62 24.48 a

Projected conditions in 2018 with

on-the-books controls 18.94 19.18 20.04 22.38 b

Net change 0.92 0.30 1.58 2.10

Glide path goal for 2018 17.70 17.56 19.21 21.35

The baseline condition values reflect the recent adjustments proposed by the Midwest RPO to a

include several missing days. The adjusted values are, on average, less than 0.5 deciviews greater

than those provided on the IMPROVE website."

Based on CAMx modeling by the MRPO. These modeling analyses used preliminary estimates of b

the impacts of BART controls, which are generally larger than the impacts estimated in industry

BART analyses.

It must be noted that the estimates of visibility improvement are subject to considerable

uncertainty. These are based on rollback calculations using the results of PSAT analyses and

CAMx sensitivity analysis. These rollback calculations provide a mechanism for evaluating the

relative impacts of different strategies. However, they may over-estimate or under-estimate the

3 X 2

impacts of NH or NO controls relative to SO controls. More detailed modeling using CAMx

or other photochemical models is needed to fully quantify the impact of any given control

strategy.

A detailed analysis of cost per deciview for on-the-books control measures was beyond

the scope of this project. However, the most of the measures in Table 6.5-3 are within the range

of cost effectiveness values for on-the-books control measures. 

Based on the cost-effectiveness estimates in Table 6.5-3, the least expensive control

measure in terms of cost unit of per visibility improvement is the control of NO emissions from X

X

large reciprocating engines in the 3-state region. This measure is followed by the low-NO

X

reflash measure for mobile sources. Some anti-idling measures (to reduce NO and diesel

particulate matter) could result in cost savings; however, the overall control measure has a broad

of potential cost effectiveness values for NO reductions. The visibility improvements calculated X

for all of these measures are small. The cost effectiveness of reducing ammonia from

agricultural sources is very uncertain, but this measure may be comparably cost-effective

(depending on the effectiveness of tree plantings for removing ammonia).

EGU and ICI boiler control measures have somewhat higher cost-per-deciview values

than the above measures. However, the visibility impacts of these measures are much larger. In

addition, costs of EGU and ICI measures per ton of emission reduction are within the range of

values incurred for on-the-books control measures. Further, a previous benefits analysis for EGU
108

control measures has indicated that the monetary health benefits from EGU controls outweigh the

cost of control by a factor of 6 to 10 (depending on the geographic region covered in the health

benefits analysis). The EGU1 limits for SO in the 3-state region could be sufficient to reach the 2

glide path line at Boundary Waters, Seney, and Isle Royale. 

Additional control measures are expected to be needed to reach the glide path line for the

Voyageurs Class I area. Based on MRPO modeling studies, the on-the-books control measures

also have been less effective in improving visibility at Voyageurs than at the other northernMidwest Class I areas. This appears to be due to differences in source region culpabilities. In

particular, the influence from the major Midwest source regions, especially those with the largest

change (decrease) in emissions, decreases with distance, i.e., the most impact occurs at Seney

(the closest Class I area) and the least impact occurs at Voyageurs (the farthest Class I area).
Strategy and 

region

Boundary 

Waters Voya-geurs Isle Royale Seney Average

EGU EGU1 3-State SO2 0.30 0.12 0.44 0.41 0.32

NOX 0.07 0.05 0.06 0.04 0.06

9-State SO2 0.77 0.35 0.84 1.01 0.74

NOX 0.18 0.24 0.15 0.12 0.17

EGU2 3-State SO2 0.46 0.21 0.52 0.46 0.41

NOX 0.12 0.08 0.09 0.07 0.09

9-State SO2 0.87 0.40 0.96 1.18 0.85

NOX 0.26 0.30 0.23 0.19 0.24

ICI boilers ICI1 3-State SO2 0.065 0.035 0.067 0.055 0.055

NOX 0.074 0.048 0.026 0.023 0.043

9-State SO2 0.090 0.047 0.092 0.109 0.084

NOX 0.098 0.070 0.048 0.058 0.068

ICI Workgroup 3-State SO2 0.105 0.055 0.107 0.088 0.089

NOX 0.095 0.061 0.034 0.030 0.055

9-State SO2 0.145 0.075 0.148 0.176 0.136

NOX 0.114 0.082 0.056 0.067 0.080

3-State NOX 0.027 0.017 0.009 0.008 0.015

9-State NOX 0.074 0.053 0.036 0.044 0.052

3-State NOX 0.014 0.009 0.005 0.005 0.008

9-State NOX 0.010 0.007 0.005 0.006 0.007

3-State NOX 0.064 0.041 0.023 0.020 0.037

9-State NOX 0.105 0.075 0.051 0.062 0.073

3-State NOX 0.019 0.013 0.007 0.006 0.011

9-State NOX 0.017 0.012 0.008 0.010 0.012

10% reduction 3-State NH3 0.09 0.11 0.10 0.10 0.10

9-State NH3 0.15 0.18 0.15 0.17 0.16

15% reduction 3-State NH3 0.14 0.17 0.15 0.14 0.15

9-State NH3 0.23 0.27 0.23 0.26 0.25

Mobile sources Low-NOX Reflash 3-State NOX 0.006 0.007 0.009 0.006 0.007

9-State NOX 0.008 0.009 0.012 0.012 0.010

MCDI 3-State NOX 0.015 0.019 0.014 0.013 0.015

9-State NOX 0.014 0.018 0.013 0.013 0.015

Anti-Idling 3-State NOX 0.008 0.011 0.008 0.008 0.009

9-State NOX 0.005 0.007 0.006 0.006 0.006

Cetane Additive Program 3-State NOX 0.009 0.011 0.009 0.008 0.009

9-State NOX 0.006 0.007 0.009 0.010 0.008

Reciprocating engines emitting 

10 tons/year or more

Turbines emitting 10 tons/year or 

more

Agricultural 

sources

Table 6.5-2. Estimated Visibility Impacts of Potential Control Strategies

Estimated visibility improvement on the 20% worst-visibility 

days in 2018 (deciviews)

Reciprocating 

engines and 

turbines

Reciprocating engines emitting 

100 tons/year or more

Turbines emitting 100 tons/year 

or more

109
Emission category Control strategy Region Pollutant

Average estimated 

visibility improvement for the four 

Midwest Class I 

areas (deciviews)

Cost 

effectiveness 

($/ton)

Cost effectiveness 

per visibility 

improvement 

($million/ 

deciview)

EGU EGU1 3-State SO2 0.32 1,540 2,249

NOX 0.06 2,037 2,585

9-State SO2 0.74 1,743 2,994

NOX 0.17 1,782 2,332

EGU2 3-State SO2 0.41 1,775 2,281

NOX 0.09 3,016 3,604

9-State SO2 0.85 1,952 3,336

NOX 0.24 2,984 4,045

ICI boilers ICI1 3-State SO2 0.055 2,992 1,776

NOX 0.043 2,537 1,327

9-State SO2 0.084 2,275 2,825

NOX 0.068 1,899 2,034

ICI Workgroup 3-State SO2 0.089 2,731 1,618

NOX 0.055 3,814 1,993

9-State SO2 0.136 2,743 3,397

NOX 0.080 2,311 2,473

3-State NOX 0.015 538 282

9-State NOX 0.052 506 542

3-State NOX 0.008 754 395

9-State NOX 0.007 754 810

3-State NOX 0.037 1,286 673

9-State NOX 0.073 1,023 1,095

3-State NOX 0.011 800 419

9-State NOX 0.012 819 880

10% reduction 3-State NH3 0.10 31 - 2,700 8 - 750

9-State NH3 0.16 31 - 2,700 18 - 1,500

15% reduction 3-State NH3 0.15 31 - 2,700 8 - 750

9-State NH3 0.25 31 - 2,700 18 - 1,500

Mobile sources Low-NOX Reflash 3-State NOX 0.007 241 516

9-State NOX 0.010 241 616

MCDI 3-State NOX 0.015 10,697 7,595

9-State NOX 0.015 2,408 4,146

Anti-Idling 3-State NOX 0.009 (430) - 1,700 (410) - 1,600

9-State NOX 0.006 (430) - 1,700 (410) - 1,600

Cetane Additive Program 3-State NOX 0.009 4,119 3,155

9-State NOX 0.008 4,119 10,553

Agricultural 

sources

Table 6.5-3. Summary of Visibility Impactes and Cost Effectiveness of Potential Control Measures

Reciprocating 

engines and 

turbines

Reciprocating engines emitting 

100 tons/year or more

Turbines emitting 100 tons/year or 

more

Reciprocating engines emitting 10 

tons/year or more

Turbines emitting 10 tons/year or 

more

110
Figure 6-5-1. Estimated overall visibility impacts of control strategies in comparison with reasonable progress

goals for the northern-Midwest Class I areas.
112

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114

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Summary ladco so2. xls, January 23, 2007 e-mail from Teresa Walker

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Farrokh Ghorreshi (Wisconsin)

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Crude Protein on Gaseous Emissions and Swine Performance.” Workshop on

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by the Southwest Research Institute for the National Renewabl Energy

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Technical Report. U.S. Environmental Protection Agency, Office of

Transportation and Air Quality, Assessment and Standards Division. EPA420-P02-001, October 2002.

42. Chan, Lit-Man et al. Evaluation of Candidate Mobile Source Control Measures

for LADCO States in 2009 and 2012. Prepared for LADCO by ENVIRON,

March 21, 2007.

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and Diesel Specifications and Diesel Engine Retrofits in the Southeast Michigan

Area. Prepared for the Southeast Michigan Council of Governments, the Alliance

of Automobile Manufacturers, and the American Petroleum Institute. 

February 23, 2005.

44. Davis, W. T., and T. L. Miller. Estimates of potential emissions reductions for

the Nashville ozone early action compact area, Final Report. Prepared for the

Nashville Department of Environment and Conservation, March 2004. 

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Heavy-Duty Highway Engines, final technical report. U.S. Environmental

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Standards Division. EPA 420-R-03-002. February 2003.

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Protection Agency, Office of Transportation and Air Quality, Certification and

Compliance Division. EPA420-R-04-003. March 2004.
116

47. Sacramento County Superior Court Ruling, available

http://www.saccourt.com/courtrooms/trulings/d45archives/d45-10.16.06-

05cs00386.doc 

48. “Achieving Compliance with the Diesel Reflash Program.” Prepared for the

Bureau of Equity and Environmental Services by CTC & Associates LLC,

WisDOT Research and Communication Services. August 30, 2006.

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http://www.epa.gov/midwestcleandiesel.org 

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Environmental Protection Agency, Office of Transportation and Air Quality,

Transportation and Regional Programs Division. EPA420-B-06-004. April 2006.

51. California anti-idling program. Information available:

http://arb.ca.gov/regact/idling/idling.htm 

52. Everybody Wins information available at the LRAPA website:

http://www.lrapa.org/projects/everybody_wins/ 

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Cement Industry.” Prepared for the U.S. Environmental Protection Agency/Office

of Air Quality Planning and Standards.

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number MI-ROP-B1743-2004.

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Document - NOX Emissions from Glass Manufacturing.” EPA-453/R-94-037
Contents

Table A-1. Summary of Current and Projected Emissions in the for States in the Study

 Region .......................................................... A-1

Table A-2. Estimated Cost of Control for Facilities Subject to BART .................. A-2

Table A-3. Projected Emission Reductions from EGUs as a Result of CAIR and Other

 Existing Regulations ............................................... A-3
EGU

ICI 

boilers

Reciprocating 

engines Turbines

Other 

point

Area 

sources

Onroad 

mobile 

sources

Nonroad 

mobile 

sources

Marine, 

aircraft, 

railroad Total

Michigan 1,103 55 107 71 19 1 1,355

Minnesota 318 23 36 33 19 8 437

Wisconsin 602 149 14 9 13 13 800

3-State Subtotal 2,023 227 156 113 51 21 2,592

Illinois 1,310 161 213 11 31 0 1,725

Indiana 2,499 148 144 158 17 0 2,966

Iowa 412 88 50 2 12 8 571

Missouri 835 28 227 117 12 12 1,231

North Dakota 376 21 22 142 0 3 564

South Dakota 35 1 3 50 0 1 90

9-State Total 7,489 676 813 594 123 44 9,739

Michigan 448 45 44 11 116 49 926 205 114 1,959

Minnesota 271 26 18 6 117 126 455 208 100 1,327

Wisconsin 294 65 8 2 24 32 481 145 79 1,129

3-State Subtotal 1,013 136 71 19 256 208 1,862 557 294 4,416

Illinois 712 101 112 14 129 62 890 324 277 2,622

Indiana 830 105 25 2 106 63 703 178 123 2,133

Iowa 254 45 26 2 39 7 304 174 89 941

Missouri 458 12 21 3 63 64 602 199 133 1,555

North Dakota 196 14 9 1 7 45 75 2 46 395

South Dakota 44 1 0 1 14 14 92 2 8 176

9-State Total 3,507 413 264 42 616 462 4,529 1,437 969 12,239

Michigan 1,093 51 134 68 0 1 1,347

Minnesota 236 22 48 34 4 2 346

Wisconsin 426 142 15 10 0 9 601

3-State Subtotal 1,755 215 196 112 4 11 2,294

Illinois 661 155 94 13 0 0 923

Indiana 1,033 138 152 153 3 0 1,479

Iowa 404 83 74 3 1 2 567

Missouri 770 26 395 120 3 7 1,321

North Dakota 298 20 32 137 4 0 491

South Dakota 33 2 4 51 3 0 94

9-State Total 4,952 641 948 588 19 20 7,168

Michigan 273 43 41 11 133 54 385 94 110 1,145

Minnesota 115 25 18 6 134 136 205 175 54 867

Wisconsin 126 64 7 2 21 35 118 69 57 500

3-State Subtotal 514 132 66 20 287 225 708 338 222 2,512

Illinois 199 96 111 16 121 73 176 154 186 1,131

Indiana 262 100 23 2 101 69 105 141 84 887

Iowa 140 44 25 2 50 9 67 141 47 525

Missouri 213 12 20 3 75 74 119 161 99 777

North Dakota 196 14 8 1 12 50 34 204 24 545

South Dakota 40 1 0 1 22 15 42 148 5 273

9-State Total 1,564 400 254 45 669 515 1,250 1,288 666 6,650

SO2 in 2018

NOX in 2018

Table A-1. Summary of Current and Projected Emissions in the for States in the Study 

Region

Estimated missions (tons/day)

SO2 in 2002

NOX in 2002

A-1
State Source name County SO2 NOX SO2 NOX SO2 NOX SO2 NOX

Minnesota Ipsat Inland (Mittal) St. Louis 155 3,254 a a a a a a

EVTAC-Fairlane (United 

Taconite)

St. Louis 3,222 1,771 a a a a a a

National Steel (USS Keetac) St. Louis 704 6,049 34 a a a a a

Hibbing Taconite St. Louis 593 6,203 0 13 a a a a

USS Minntac St. Louis 1,946 14,924 0 10 a 612 a 705

Northshore Mining^ Lake 2,291 3,649 0 40 a 640 a 1,439

North Dakota Great River Energy – Coal Creek McLean 34,578 11,114 78 30 7,870 420 531 248

Basin Electric Power – Leland 

Olds

Mercer 88,462 16,136 93 44 49,000 9,300 963 1,770

Great River Energy – Stanton Mercer 8,592 2,139 90 26 9,330 1,275 300 504

Minnkota Power – MR Young Oliver b b 84 62 b 18,877 b 1,248

^ The facility proposed additional control as BART only for the power boiler at the facility, not the indurating furnaces. The power boiler is a CAIR unit

Table A-2. Estimated Cost of Control for Facilities Subject to BART*

Cost effectiveness ($/ton)

a The facility proposed that existing controls and operations were BART and therefore cost estimates are not included

b Information not available in facility's BART analysis

* Other State's BART analyses are not listed as they had not yet been completed at the time of this report

Baseline emissions 

(tons/year)

Estimated 

reductions (%)

Total annualized cost 

($1000/year)

A-2
2002 2012 2018 2026 2012 2018 2026

SO2 emissions

Michigan 403 398 399 185 1 1 54

Minnesota 116 86 86 73 26 26 37

Wisconsin 220 153 155 137 31 29 38

3-state total 739 636 641 395 14 13 47

Illinois 478 239 241 214 50 50 55

Indiana 912 462 377 336 49 59 63

Iowa 150 144 147 146 4 2 3

Missouri 305 281 281 224 8 8 27

North Dakota 137 108 109 91 21 21 34

South Dakota 13 12 12 12 5 5 3

Region total 2,734 1,883 1,808 1,418 31 34 48

NOX emissions

Michigan 164 91 100 93 45 39 43

Minnesota 99 41 42 43 58 58 57

Wisconsin 107 44 46 47 59 57 56

3-state total 370 176 188 182 52 49 51

Illinois 260 73 73 68 72 72 74

Indiana 303 141 95 93 54 68 69

Iowa 93 49 51 51 47 45 45

Missouri 167 81 78 75 52 53 55

North Dakota 72 72 72 72 0 0 0

South Dakota 16 15 15 15 9 9 8

Region total 1,280 606 571 556 53 55 57

Table A-3. Projected Emission Reductions from EGUs as a Result of CAIR and 

Other Existing Regulations

Baseline and projected emissions from EGU 

(1000 tons/year) Emission reductions from 2002 (%)

A-3
Appendix B

Potential SO2 and NOX Regional Control

Strategies and Unit-level Control

Technologies
Contents

Table B-1. Control Strategies for Mobile Sources ................................... B-1

Table B-2. Control Strategies for EGUs .......................................... B-5

Table B-3. Control Strategies for ICI Boilers ...................................... B-8

Table B-4. Control Strategies for Reciprocating Engines ............................ B-10

Table B-5. Control Strategies for Turbines ....................................... B-11

Table B-6. Control Strategies for Ammonia ...................................... B-12

Table B-7. References for Control Strategies ..................................... B-17

Table B-8. Notes on Control Strategies .......................................... B-19
Appendix B-1. Control Strategies for Mobile Sources

Technology Processes Covered

Estimated NOX Control 

Efficiency 

 1993 to 1998 MHDDV 24% reduction in tailpipe 

emissions

 1993 to 1998 HHDDV 24% reduction in tailpipe 

emissions

1995 and older enhanced IM tailpipe test

8-9% annual inventory reduction

1996 and newer OBDII equipped 

gasoline vehicles

0.1 gram/mile reduction for post-repair vehicles

1997 and newer OBDII equipped lightduty diesel vehicles 0.6% reduction in tailpipe emissions 

2007 and newer heavy-duty diesel trucks (on the books)

Smoking vehicles (identification, repair, and/or replace)

up to 53% decrease in NOX emissions for all vehicles 

participating in the program

Use 7.0 RVP fuel in urban areas; e.g., Detroit area LDGV Fuel Switching: Biodiesel B100 HDDV +10% pre-1998, +30% 98-04 

increase in tailpipe emissions

Fuel Switching: Biodiesel B20 HDDV +2% pre-1998, +4% 98-04 

increase in tailpipe emissions

Low NOX Calibration/Reflashing. Adopt regulations similar to the CARB Low NOx Software Upgrade program with a set phase in schedule that would require all low NOx rebuild engines to have low NOx rebuild kit installed by 2009.Emissions Inspections Program. Implement a State emissions inspection program for passenger vehicles and heavy duty diesel trucks.Alternative Fuels. Increase use of alternative fuels including biodiesel-petroleum diesel blends, ethanol-gasoline blends, and liquid or compressed (*Recommendation may be restricted to fuels already available in the Petroleum Administration for Defense District.)

B-1
Appendix B-1. Control Strategies for Mobile Sources

Technology Processes Covered

Estimated NOX Control 

Efficiency 

Fuel Switching: Biodiesel B20 Bulldozer, Motor Grader unknown 

Fuel Switching: Biodiesel B30 Bulldozer, Motor Grader unknown Fuel Switching: Biodiesel B20 Locomotive (line haul or switching) +5-6% increase in tailpipe 

emissions

Fuel Switching: Biodiesel B20 Marine Port applications unknown 

Locomotive (line haul or switching) 1-2% reduction in tailpipe 

emissions

Harbor craft 15% inventory reduction 

Large deep draft marine vessels 15% inventory reduction Harbor craft (ferries, tugs) 15% inventory reduction Large deep draft marine vessels 15% inventory reduction 

Increase use of E10 LDGV +5% increase in tailpipe 

emissions

Fuel Switching: Convert public fleets to Flex Fuel Vehicles fueled with E85. LDGV tailpipe control efficiency 

unavailable

Fuel Switching: LNG or CNG LDGV 60% reduction in tailpipe 

emissions

Fuel Switching: LNG Locomotive (line haul or switching) tailpipe control efficiency 

unavailable

Fuel Switching: LNG or CNG MDGV, HDGV 50% reduction in tailpipe 

emissions

1993 to 1998 MHDDV unknown 

Switching locomotives 50% reduction in tailpipe 

emissions

Line-haul locomotives 75% reduction in tailpipe 

emissions

[continued]

Use lower sulfur fuel: CARB Diesel*Use lower sulfur fuel: Highway or ULSD*Anti-Idling. Reduce idling emissions from heavy-duty diesel trucks and locomotives using truck stop electrification and locomotive anti-idling technology.

B-2
Appendix B-1. Control Strategies for Mobile Sources

Technology Processes Covered

Estimated NOX Control 

Efficiency 

Upgrade to 1990 Engine MY 1989 and earlier HDDV 43% reduction 

MY 1989 and earlier HDDV 63% reduction MY 1990 HDDV 33% reduction MY 1991-1997 HDDV 20% reduction MY 1989 and earlier HDDV 78% reduction MY 1990 HDDV 66% reduction MY 1991-1997 HDDV 52% reduction MY 1998-2001 HDDV 95% reduction MY 2002-2006 HDDV 92% reduction 

Upgrade construction and agricultural equipment to Tier 2, 3, or 4 Excavators, Rubber Tire Loaders, 

Crawler Tractors/Dozers, Tractors/Loaders/Backhoes, OffHighway Trucks, Agricultural Tractors, Combines

Dependent on model year and horsepower. See Reference 11 for engine standard schematic.

Fleet turnover to 2007 and newer engines (On the books) HDDV unknown

[continued]

Fleet Modernization (all percentages are reductions in tailpipe emissions). Replace equipment or rebuild engines to meet new engine standards.Upgrade to 2002/4 EngineUpgrade to 2007 EngineUpgrade to 2001/2 Engine

B-3
Appendix B-1. Control Strategies for Mobile Sources

Technology Processes Covered

Estimated NOX Control 

Efficiency 

MY pre-1989 through 2006 HDDV up to 80% reduction 

Excavators, Rubber Tire Loaders, Crawler Tractors/Dozers, Tractors/Loaders/Backhoes, OffHighway Trucks

up to 80% reduction 

Locomotive (line haul or switching) 90% reduction Agricultural Tractors, Combines up to 80% reduction 

Lean NOX Catalyst (LNC) combined with Diesel Particulate Filter (DPF) MY pre-1989 through 2006 HDDV 15-25% reduction 

Excavators, Rubber Tire Loaders, Crawler Tractors/Dozers, Tractors/Loaders/Backhoes, OffHighway Trucks

15-25% reduction 

Agricultural Tractors, Combines 15-25% reduction 

Excavators, Rubber Tire Loaders, Crawler Tractors/Dozers, Tractors/Loaders/Backhoes, OffHighway Trucks

up to 50% reduction 

Agricultural Tractors, Combines up to 50% reduction Excavators, Rubber Tire Loaders, Crawler Tractors/Dozers, Tractors/Loaders/Backhoes, OffHighway Trucks

up to 80% reduction 

Agricultural Tractors, Combines up to 80% reduction Excavators, Rubber Tire Loaders, Crawler Tractors/Dozers, Tractors/Loaders/Backhoes, OffHighway Trucks

up to 80% reduction 

Agricultural Tractors, Combines up to 80% reduction 

[continued]

SCR combined with DPFSelective Catalytic Reduction (SCR)LNCExhaust Gas Recirculation (EGR) combined with DPFDiesel Oxidation Catalyst combined with SCRRetrofit Technology (all percentages are reductions in tailpipe emissions). Install aftertreatment NOX controls on on-road heavy-duty diesel vehiconstruction, cargo-handling, and marine equipment.

B-4
Appendix B-2. Control Strategies for EGUs

Technology Processes Covered Efficiency of Control No

Baseline and On-the-books regional programsBaseline 2002: (MRPO average SO2 is 1.16 lbs/mmBtu, NOx is 0.43 lbs/mmBtu): NSPS; PSD/NSR; State RACT Rules; Title IV SO2 Program 

EGUs MRPO average SO2 is 1.16 

lbs/mmBtu, NOx is 0.43 lbs/mmBtu

bb 

2009 On-the-Books measures: CAIR EGUs EPA CAIR levels are estimated at 

0.13 lbs/mmBtu NOX and 0.26 lbs/mmBtu SO2 in 2015.

bb 

2009 On-the-Books measures: CAIR -- Michigan Impacts EGUs EPA estimates a 10% reduction in 

SO2 and a 29% reduction in NOX from 2003 levels.

bb 

2009 On-the-Books measures: CAIR -- Minnesota Impacts EGUs EPA estimates a 36% reduction in 

SO2 and a 59% reduction in NOX from 2003 levels.

bb 

2009 On-the-Books measures: CAIR -- Wisconsin Impacts EGUs EPA estimates a 32% reduction in 

SO2 and a 61% reduction in NOX from 2003 levels.

bb 

Additional regional programs

Adopt Emission Caps Based on “Retrofit SO2 BACT Level” of 0.15 lbs/mmBtu by 2013 (with Interim Cap Based on 0.36 lbs/mmBtu in 2009)

EGUs Additional 0.11 lbs/mmBtu reduction 

in SO2 from original CAIR emissions cap

v 

Adopt Emission Caps Based on “Retrofit NOx BACT Level” of 0.10 lbs/mmBtu by 2013 (with Interim Cap Based on 0.15 lbs/mmBtu in 2009)

EGUs Additional 0.03 lbs/mmBtu reduction 

in NOX from original CAIR emissions cap

Adopt Emission Caps Based on “SO2 BACT Level for New Plants” of 0.10 lbs/mmBtu by 2013 (with Interim Cap Based on 0.24 lbs/mmBtu in 2009)

EGUs Additional 0.16 lbs/mmBtu reduction 

in SO2 from original CAIR emissions cap

w 

Adopt Emission Caps Based on “NOx BACT Level for New Plants” of 0.07 lbs/mmBtu by 2013 (with Interim Cap Based on 0.12 lbs/mmBtu in 2009)

EGUs Additional 0.06 lbs/mmBtu reduction 

in NOX from original CAIR emissions cap

Replace old boilers to boost efficiency by 50-60% EGUs Not Available Implement Consumer Education programs to promote energy efficiency and reduce demand.

Not Available 

B-5
Appendix B-2. Control Strategies for EGUs

Technology Processes Covered Efficiency of Control No

Fuel Options

Use fuel oil with a sulfur content of 0.05% or less for all boiler sizes (<50 - >250 MmBtu/hr)

#1 and #2 fuel oil 

Use fuel oil with a sulfur content of 0.5% or less #4 and #6 fuel oil Use coal with low sulfur content Coal for units between 50-100 

mmBtu/hr

2.0 lb/MmBtu or 30% SO2 reduction 

Use coal with low sulfur content Coal for units between 100-250 

mmBtu/hr

1.2 lb/MmBtu or 85% SO2 reduction 

Use coal with low sulfur content

Coal for units >250 MmBtu/hr

0.25 lb/MmBtu or 85% SO2 reduction 

Retrofit Technologies for individual emission units

Burner Modifications Most units 10 to 30% NOx reduction Fuel Reburn Most units. Furnace height (residence 

time) may restrict some applications 

20 to 30% NOx reduction for FuelLean Gas Reburning (no OFA), and 30 to 60% reduction for conventional reburning. 

Hydrocarbon-enhanced SNCR Most units. Can use more NH3 with 

less slip. 

 40 to 60% NOx reduction 

Low-NOx Burners Most boilers already have LNB. 30 to 50% NOx reduction 

Overfire Air Most units. Furnace height may restrict 

some applications 

 20 to 40% NOx reduction 

Oxygen-enhanced combustion modification Best applied with new OFA system 

designed to achieve stoichiometric airfuel ratio < 0.8. 

 30-50% beyond OFA 

Rich Reagent Injection Most units. Modeling required to 

determine injection locations. 

 20 to 30% additional NOx reduction 

beyond OFA. 

Selective Catalytic Reduction (SCR) Most units. Space availability may 

constrain some options. High sulfur fuels more challenging

 70 to 90+% NOx reduction 

Selective Non-catalytic Reduction (SNCR) Most units. Residence time and 

temperature characteristics are important

 25 to 50% NOx reduction, depending on the furnace temperature and time for reaction. 

[continued]

B-6
Appendix B-2. Control Strategies for EGUs

Technology Processes Covered Efficiency of Control No

Physical Coal Cleaning Available for all units 10-40% SO2 reduction 

Chemical Coal Cleaning Available for all units 50-85% SO2 reduction 

Switch to Low Sulfur Coal Available for all units 50-80% SO2 reduction Limestone forced oxidation system (LSFO) Generally used for >100 MW units 

units firing high-sulfur (>2 percent) 

bituminous coals. 

 52 – 98% reduction in SO2, with median reduction of 90%; EPA used 95% in CAIR analysis 

Magnesium enhanced lime system (MEL) Generally used for 100-550 MW units 

units firing low-sulfur (<2 percent) 

bituminous, sub-bituminous, and lignite coals. 

 52 – 98% reduction in SO2, with median reduction of 90%; EPA used 96% for CAIR analysis 

Lime spray dryer system (LSD) Can be used for both low-and highsulfur coals, depending on the 

economics of each application. 

 70 - 96% reduction in SO2, with median reduction of 90%; EPA used 90% for CAIR analysis 

Dry or wet FGD Coal-burning units >250 mmBtu/hr 90% SO2 reduction 

Combustion Tuning All units 50-100 mmBtu/hr 5-35% NOX reduction 

[continued]

B-7
Appendix B-3. Control Strategies for ICI Boilers

Technology Processes Covered

Efficiency of Control (% at 

the unit) Note

Baseline and On-the-books re

gional 

pro

grams

Baseline 2002: NSPS; PSD/NSR; State RACT Rules ICI Boilers

N

A

bb 

2009 On-the-Books (OTB) measures: Enforcement settlements and Alcoa announced scrubbers 

ICI Boilers 18% SO2 reduction from 

2002 levels

bb 

2009 OTB measures: NOx SIP Call for large boilers, enforcement settlements 

ICI Boilers 3% NOX reduction from 

2002 levels

bb 

Additional regional 

programs

OTB measures plus 40% SO2 Reduction and 60% Reduction (similar to NOx SIP Call) to All Medium and Large ICI Boilers

ICI Boilers 29% SO2 reduction and 

19% NOX reduction from 2002 levels 

x 

OTB Measures plus Likely Controls to ICI Boilers subject to the proposed BART requirements Emission Reductions. 

ICI Boilers 8% NOX reduction and 

40% SO2 reduction from 2002 levels

y 

OTB Measures plus 90% SO2 Reduction and 80% NOX reduction (similar to BART) to All Medium and Large ICI Boilers Emission Reductions. 

ICI Boilers 66% SO2 reduction and 

31% NOX reduction from 2002 levels

z 

Fuel O

ptions

Use fuel oil with a sulfur content of 0.05% or less for all boiler sizes (<50 - >250 MmBtu/hr)

#1 and #2 fuel oil 

Use fuel oil with a sulfur content of 0.5% or less #4 and #6 fuel oil Use coal with low sulfur content Coal for units between 50-100 

mmBtu/hr

2.0 lb/MmBtu or 30% SO2 reduction

Use coal with low sulfur content Coal for units between 100-250 

mmBtu/hr

1.2 lb/MmBtu or 85% SO2 reduction

Use coal with low sulfur content

Coal for units >250 MmBtu/hr

0.25 lb/MmBtu or 85% SO2 reduction

B-8
Appendix B-3. Control Strategies for ICI Boilers

Technology Processes Covered

Efficiency of Control (% at 

the unit) Note

Retrofit Technolo

gies for individual emission units

LNB (Low NOX Burner) Coal Sub-bituminous fueled boiler 51% NOX reduction 

Coal Sub-bituminous fueled boiler 65% NOX reduction Coal Bituminous fueled boiler 51% NOX reduction Gas fueled boiler 60% NOX reduction Oil fueled boiler 30% NOX reduction 

LNB + OFA + FGR (Flue Gas Recirculation) Gas fueled boiler 80% NOX reduction 

LNB + OFA + FGR (0.5 lbs/mmBtu inlet NOx) Oil fueled boiler 50% NOX reduction 

Coal fueled boiler 80% NOX reduction 

Gas fueled boiler 80% NOX reduction 

Oil fueled boiler 80% NOX reduction 

Coal fueled boiler 40% NOX reduction 

Oil fueled boiler 40% NOX reduction 

Wood/Non-fossil solid fuel not available Gas fueled boiler 40% NOX reduction Coal High Sulfur fueled boiler 40% SO2 reduction Coal Low Sulfur fueled boiler 40% SO2 reduction 

SDA Coal fueled boiler 90% SO2 reduction 

Coal High Sulfur fueled boiler 90% SO2 reduction Coal Low Sulfur fueled boiler 90% SO2 reduction Oil fueled boiler 90% SO2 reduction 

Water Injection Gas fueled boiler 75% NOX reduction 

[continued]

LNB + OFA (Over-fire air)In-duct Dry Sorbent Injection (IDSI) Wet FGD SNCR SCR 

B-9
Control Measure Sources Covered

Estimated Efficiency 

(%) Notes Reference

Low-Emission Combustion Internal Combustion 80-90% reduction 27

Prestratified Charge Internal Combustion 75-90% reduction 27High Energy/Plasma Ignition Systems Internal Combustion 80% reduction cc 27SCONOx Technology Internal Combustion 95% reduction dd 27

NOxTech System Internal Combustion 90-95% reduction 27

High-pressure Fuel Injection Internal Combustion 80% reduction 27Air Fuel w/Ignition Retard Internal Combustion - Gas 53 tons/30% reduction hh 28, 29

Air Fuel w/Ignition Retard IC Engines - Gas 53 tons/30% reduction hh 28, 29Air Fuel Ratio Adjustment Internal Combustion - Gas 36 tons/20% reduction hh 28, 29Air Fuel Ratio Adjustment IC Engines - Gas 38 tons/20% reduction hh 28, 29Ignition Retard IC Engine - Oil 6 tons/25% reduction hh 28, 29Ignition Retard IC Engines - Gas, Diesel, LPG 9 tons/25% reduction hh 28, 29L-E (Low Speed) IC Engine - Gas 148 tons/87% reduction hh 28, 29L-E (Medium Speed) IC Engine - Gas 98 tons/87% reduction hh 28, 29

NSCR IC Engine - Oil 19 tons/90% reduction ee, hh 27, 28, 29NSCR IC Engine - Gas, Diesel, LPG 26 tons/90% reduction ff, hh 27, 28, 29

SCR IC Engine - Gas 150 tons/90% reduction gg, hh 27, 28, 29SCR IC Engine - Gas, Diesel, LPG 23 tons/80% reduction hh 27, 28, 29SCR IC Engine - Oil 17 tons/80% reduction hh 27, 28, 29

Appendix B-4. Control Strategies for Reciprocating Engines

B-10
Control Measure Sources Covered

Estimated Efficiency 

(%) Notes Reference

External Flue Gas Recirculation Turbine N/A ii 30

Overfire Air Turbine N/A 30

Low NOx Burners Turbine 25-50% reduction 30Selective Catalytic Reduction (High Dust) Turbine 70-90% control efficiency ii 30Selective Catalytic Reduction (Low Dust) Turbine 80-90% control efficiency 30Selective Non-Catalytic Reduction Turbine 25-50% control efficiency 30Low Temperature Oxidation (Tri-NOx) Turbine 99% control efficiency 30Low Temperature Oxidation (LoTox) Turbine 80-95% control efficiency 30

Non Selective Catalytic Reduction Turbine N/A ii 30

Novel Multi-Pollutant Controls (ElectroCatalytic Oxidation) Turbine N/A 30

Novel Multi-Pollutant Controls (Pahlman Process)

Turbine N/A ii 30

SCONOx Technology Gas Turbines 95% reduction 27

Dry Low NOx Combuster Combustion Turbines - Natural Gas 102 tons/50% reduction hh 28, 29

Dry Low NOx Combuster Combustion Turbines - Natural Gas 102 tons/84% reduction hh 28, 29SCR w/Low NOx Burner Combustion Turbines - Natural Gas 143 tons/94% reduction hh 28, 29SCR w/Steam Injection Combustion Turbines - Natural Gas 145 tons/95% reduction hh 28, 29SCR w/Water Injection Combustion Turbines - Natural Gas 145 tons/95% reduction hh 28, 29SCR w/Water Injection Combustion Turbines - Oil 31 tons/90% reduction hh 28, 29SCR w/Water Injection Combustion Turbines - Jet Fuel 13 tons/90% reduction hh 28, 29Steam Injection Combustion Turbines - Natural Gas 119 tons/80% reduction hh 28, 29Water Injection Combustion Turbines - Natural Gas 112 tons/76% reduction hh 28, 29Water Injection Combustion Turbines - Oil 23 tons/68% reduction hh 28, 29Water Injection Combustion Turbines - Jet Fuel 10 tons/68% reduction hh 28, 29Dry Low NOx Combuster Combustion Turbines - Natural Gas 102 tons/50% reduction hh 28, 29Dry Low NOx Combuster Combustion Turbines - Natural Gas 102 tons/84% reduction hh 28, 29

Appendix B-5. Control Strategies for Turbines

B-11
Appendix B-6. Control Strategies for Ammonia

Control Measure Sources Covered

Estimated 

Efficiency (%) N

Floor housing s

ystem with stockpiling of manure Storage and handling of 

poultr

y manure (solid) N/A 

Cage housing s

ystem with conve

yor belts Storage and handling of 

poultr

y manure (solid) N/A 

Cage housing s

ystem with dee

p

pits Storage and handling of 

poultr

y manure (solid) N/A 

Lagoons/concrete tanks for storage of poultry manure Storage of poultry manure (storage) N/A Spread manure and incor

porate within 3 da

ys Application of 

poultr

y manure (solid) 36 - 80% reduction jj

Spread manure and incor

porate within 3 da

ys Application of dair

y manure (solid and li

quid) 70% reduction jj

Spread manure and incor

porate within 3 da

ys Application of beef manure (solid and li

quid) 36-70% reduction jj

Spread manure and incor

porate within 3 da

ys Application of swine manure (solid and li

quid) 36-70% reduction jj

Inject manure using tank wagon and incorporate with knives or disks

Application of dairy and beef manure (liquid) N/A 

Above-ground manure storage tanks Storage of dair

y and beef manure (solid and li

quid) N/A 

Walled enclosures to store manure Storage of dair

y and beef manure (solid and li

quid) N/A

m

Outwinter cattle by rotating through pastures to "store" manure in frozen form until it can be used in the spring

Housing cattle (winter) N/A 

Outwinter cattle by keeping them outside in one paddock (sacrifice paddock) to store manure in one location

Housing cattle (winter) N/A 

Com

post manure before applying Treatment of livestock manure (solid and li

quid) N/A 

Daily scraping and hauling of manure for collection and storage

Storage and handling of swine manure (solid) 42-63% reduction jj

Leaving manure to mix with bedding to form manure pac

k

for collection and storage

Storage and handling of swine manure (solid) 33-50% reduction jj

Storing manure in lined 

pit Storage and handling of swine manure (li

quid) jj

Storing manure in above-ground storage facilit

y Storage and handling of swine manure (li

quid) 25-50% reduction jj

Broadcasting manure w/incorporation into soil within 12 hours

Application of swine manure (solid) 80% reduction jj

B-12
Appendix B-6. Control Strategies for Ammonia

Control Measure Sources Covered

Estimated 

Efficiency (%) N

Broadcasting manure w/incorporation into soil within 4 da

ys

Application of swine manure (solid) 40% reduction jj

Injection of manure with sweeps

Application of swine manure (li

quid) 87% reduction jj

Injection of manure with knives Application of swine manure (li

quid) 62% reduction jj

Collection 

ponds to store manure Storage and handling of swine manure (li

quid) N/A 

Deep pits to store manure and minimize gas concentrations

Storage and handling of swine manure (solid) N/A 

Stockpile manure on concrete or cla

y

pad Storage and handling of swine manure (solid) N/A 

System than se

parates li

quid and solid manure Storage and handling of swine manure (solid) N/A 

Com

posting manure Treatment of swine manure (li

quid and solid) N/A 

Anaerobic lagoons and digesters to store and "treat" manure

Treatment of swine manure (liquid and solid) N/A 

Oxidation ditches and aerated lagoons to store and "treat" manure

Treatment of swine manure (liquid and solid) N/A 

Daily scraping and hauling of manure for collection and storage

Storage and handling of poultry manure (solid) 42-63% reduction jj

Leaving manure to mix with bedding to form manure pac

k

for collection and storage

Storage and handling of poultry manure (solid) 33-50% reduction jj

Broadcasting manure w/incorporation into soil within 12 hours

Application of poultry manure (solid) 83% reduction jj

Broadcasting manure w/incorporation into soil within 4 da

ys

Application of poultry manure (solid) 33% reduction jj

[continued]

B-13
Appendix B-6. Control Strategies for Ammonia

Control Measure Sources Covered

Estimated 

Efficiency (%) N

Daily scraping and hauling of manure for collection and storage

Storage and handling of dairy manure (solid) 42-62% reduction jj

Leaving manure to mix with bedding to form manure pac

k

for collection and storage

Storage and handling of dairy manure (solid) 30-50% reduction jj

Storing manure in lined 

pit Storage and handling of dair

y manure (li

quid) 25% reduction jj

Storing manure in above-ground storage facilit

y Storage and handling of dair

y manure (li

quid) 25-50% reduction jj

Broadcasting manure w/incorporation into soil within 12 hours

Application of dairy manure (solid) 75% reduction jj

Broadcasting manure w/incorporation into soil within 4 da

ys

Application of dairy manure (solid) 50% reduction jj

Injection of manure with sweeps

Application of dair

y manure (li

quid) 86% reduction jj

Injection of manure with knives Application of dair

y manure (li

quid) 71% reduction jj

Daily scraping and hauling of manure for collection and storage

Storage and handling of beef manure (solid) 42-63% reduction jj

Leaving manure to mix with bedding to form manure pac

k

for collection and storage

Storage and handling of beef manure (solid) 33-50% reduction jj

Storing manure in lined 

pit Storage and handling of beef manure (li

quid) 25% reduction jj

Storing manure in above-ground storage facilit

y Storage and handling of beef manure (li

quid) 25-50% reduction jj

Broadcasting manure w/incorporation into soil within 12 hours

Application of beef manure (solid) 87% reduction jj

Broadcasting manure w/incorporation into soil within 4 da

ys

Application of beef manure (solid) 50% reduction jj

Injection of manure with sweeps

Application of beef manure (li

quid) 56% reduction jj

Injection of manure with knives Application of beef manure (li

quid) 71% reduction jj

Best Management Practices

N/A 

Manure Storage Covers Storage of livestock manure (solid and li

quid) N/A 

Manure Digesters (Biogas) Handling of livestock manure (solid and li

quid) N/A 

Animal Lot Increased Cleaning N/A Injection of manure into fields

Application of livestock manure (li

quid) N/A 

[continued]

B-14
Appendix B-6. Control Strategies for Ammonia

Control Measure Sources Covered

Estimated 

Efficiency (%) N

Nutrient Management Plans Housing, storage, handling, and application of 

livestock manure (solid and li

quid)

N/A 

Earthen storage Storage of manure (solid and li

quid) N/A 

Cla

y-lined im

poundment Storage of manure (solid and li

quid) N/A 

Geomembrane-lined im

poundment Storage of manure (solid and li

quid) N/A 

Geos

ynthetic cla

y-lined im

poundment Storage of manure (solid and li

quid) N/A 

Concrete-lined im

poundment Storage of manure (solid and li

quid) N/A 

Manure storage structure Storage of manure (solid and li

quid) N/A 

Cla

y-lined im

poundment Storage of manure (solid and li

quid) N/A 

Geomembrane-lined im

poundment Storage of manure (solid and li

quid) N/A 

Geos

ynthetic cla

y-lined im

poundment Storage of manure (solid and li

quid) N/A 

Concrete-lined im

poundment Storage of manure (solid and li

quid) N/A 

Nitrification inhibitor Handling of livestock manure (li

quid) N/A 

Minimize application on frozen or snow-covered ground Application of livestock manure (solid and liquid) N/A Apply manure on crops that can use all of its nutrients Application of livestock manure (solid and liquid) N/A Incorporate or inject manure within 72 hours using urease inhibitor

Application of livestock manure (solid and liquid) N/A 

Cover manure storage structures or use organic matter in 

bedding to form a crust cover

Storage of livestock manure (solid and liquid) N/A 

Divert urine awa

y from feces Handling of livestock manure (solid and li

quid) N/A 

Incor

porate manure

Application of dair

y manure 10% reduction jj

Incor

porate manure

Application of beef manure 10% reduction 

Incor

porate manure

Application of swine manure (solid) 15% reduction 

Incor

porate manure

Application of swine manure (li

quid) 15% reduction 

[continued]

B-15
Appendix B-6. Control Strategies for Ammonia

Control Measure Sources Covered

Estimated 

Efficiency (%) N

Incor

porate manure

Application of 

poultr

y manure 10% reduction 

Incor

porate manure

Application of shee

p manure (solid) 10% reduction 

Incor

porate manure

Application of horse manure (solid) 10% reduction 

Solid and li

quid se

paration s

yste

m Handling of li

quid and solid manure

N/A

Treat waste by mechanical, chemical, or biological means Treatment of livestock manure (solid and liquid) N/A Hopper to transfer manure Handling of li

quid and solid manure

N/A 

Rece

ption structure or tank to transfer manure Handling of li

quid and solid manure

N/A

w

Piston pumps to transfer manure to storage or treatment structure

Handling of liquid and solid manure N/A 

Channels to transfer manure (gravit

y transfer) Handling of li

quid and solid manure

N/A 

Transfer pipes to transfer manure to storage or treatment structure

Handling of liquid and solid manure N/A 

Pi

pelines (gravit

y transfer) Handling of li

quid and solid manure

N/A 

[continued]

B-16
Appendix B-7. References for Control Strategies

1. Chan et al. Emission Reduction Scenarios for Mobile Sources in the LADCO States in 2009 and 2012 . Memorandum to 

Mike Koerber, LADCO, December 5, 2006.

2. “Evaluation of the Effectiveness of Low NOx ECM Reprogramming to In Service Heavy-Duty Vehicles,” UC Riverside 

3. Evaluating Vehicle Emission Inspection and Maintenance Programs . NAS 2001. Executive Summary available online 

at www.mindfully.org/air/vehicle-emissions-inspections-NAS-26jul01.htm

4. Gardetto and Trimble. Evaluation of On Board Diagnostics for Use In Detecting Malfunctioning and High Emitting 

5. Estimates of Emission Reductions from Performing OBDII Tests on 1997 and Newer Light-Duty Diesel Vehicles. 

Prepared for TCEQ by de la Torre Klausmeier Consulting and ERG. August 31, 2005.

6. EPA Heavy-Duty In-Use Emissions Testing Program. Available: http://www.epa.gov/otaq/hd-hwy.htm#inuse

7. A Comprehensive Analysis of Biodiesel Impacts on Exhaust Emissions Draft Technical Report. EPA420-P-02-001 

8. Durbin et al. Evaluation of the Effects of Biodiesel Fuel on Emissions from Heavy-Duty Non-Road Vehicles . Prepared 

9. Fritz, SG. Evaluation of Biodiesel Fuel in an EMD GP38-2 Locomotive . Southwest Research Institute. Prepared for 

10. Port of Seattle (available http://www.portseattle.org/news/press/2005/12_23_2005_36.shtml), Port of Vancouver 

(available http://www.renewableenergyaccess.com/rea/news/story?id=44987)

11. Report of the Biofuels Task Force to the Prime Minister . Australian Biofuels Task Force. August 2005. Available: 

http://www.dpmc.gov.au/biofuels/report/report_full.pdf

12. EPA Renewable Fuels Standard. Available: http://www.epa.gov/otaq/renewablefuels/

13. DOE Alternative Fuels. Available: http://www.eere.energy.gov/afdc/altfuel/gas_benefits.html

14. LNG Short Line Locomotive Project in SCAQMD (PoLA, PoLB short haul; West Coast Collaborative Funding)

15. "Combined ARB and U.S. EPA standards for off-road compression ignition engines." CARB Website: Off-Road 

Equipment (In-Use) Control Measure Documents & Fact Sheets. Available: 

16. "Recommendations for Reducing Emissions from the Legacy Diesel Fleet." Report from the Clean Air Act Advisory 

17. Exhaust Emissions Controls for Diesel Locomotives -- Experiences in Europe.

18. Starcrest Consulting Group, LLC. Evaluation of Low Sulfur Marine Fuel Availability - Pacific Rim. July 2005. Prepared 

19. LADCO EGU White Paper. Available: 

http://www.ladco.org/reports/rpo/Regional%20Air%20Quality/White%20Papers%20March%202006/EGU_Ver4.pdf

20. LADCO ICI Boiler White Paper. Available: 

http://www.ladco.org/reports/rpo/Regional%20Air%20Quality/White%20Papers%20March%202006/ICI_Boilers_Ver4.pdf

21. "Use of Remote Sensors to Identify High Emitters." HB1302 Workgroup Meeting Douglas R. Lawson Denver, CO July 

31, 2006

22. "Multi-Pollutant Strategy Straw Proposal of the State Collaborative To further the Discussion and Narrow the Range of 

Control Level and Dates." Document provided by Mike Koerber on 12/19/2006.

23. "Michigan's Emissions Under CAIR." Available: http://www.epa.gov/cair/mi.html

24. "Minnesota's Emissions Under CAIR." Available: http://www.epa.gov/cair/mn.html

25. "Wisconsin's Emissions Under CAIR." Available: http://www.epa.gov/cair/wi.html

26. "Draft Regional Control Strategy Recommendations." Provided by Mike Koerber on 3/7/2007. Product of the LADCO 

Stationary and Mobile Source Control Strategy Workgroup.

27. "Stationary Reciprocating Internal Combustion Engines: Updated Information on NOx Emissions and Control 

Techniques." Edgerton, S.W., Lee-Greco, J., Walsh, S. September 1, 2000

28. AirControlNET database Version 4.1

29. "AirControlNet Version 4.1 Documentation Report." E.H. Pechan & Associates, Inc. September 2005

30. "Stanton Station Unit 1: Best Available Retrofit Technology Analysis." Great River Energy. August 17, 2006

31. Smith, Rich. 1996. "Poultry Manure Handling - A Practical Approach." Alberta Agriculture, Food and Rural 

Development. http://www1.agric.gov.ab.ca/$department/deptdocs.nsf/all/pou3606

32. Madison, Fred, K. Kelling, L. Massie, L.W. Good. "Guidelines for Applying Manure to Cropland and Pasture in 

Wisconsin." http://learningstore.uwex.edu/Guidelines-for-Applying-Manure-to-Pasture-and-Cropland-in-Wisconsin33. USDA Natural Resources Conservation Service, U. of WI-Madison, WI Dept. of Natural Resources, WI Dept. of 

Agriculture, Trade & Consumer Protection. "Manure Management Choices for Wisconsin Dairy & Beef Cattle Operations." 

34. University of Wisconsin-Madison. 1998. "Outwintering dairy cattle: manure management issues." Research Brief #28. 

http://www.cias.wisc.edu/archives/1998/02/01/outwintering_dairy_cattle_manure_management_issues/index.php

35. University of Wisconsin-Madison. 1999. "Composted manures offer yield and disease resistance benefits." Research 

Brief #45. 

B-17
Appendix B-7. References for Control Strategies

36. Schmitt, Michael, G. Rehum. 1998. "Fertilizing Cropland with Swine Manure." FO-05879-GO. University of Minnesota 

Extension Service http://www.extension.umn.edu/distribution/cropsystems/DC5879.html

37 Jacobson, Larry D., D.R. Schmidt. 1994. "Manure Management Practices for the Minnesota Pork Industry." FO-06456. 

University of Minnesota Extension Service http://www.extension.umn.edu/distribution/livestocksystems/DI6456.html

38. Schmitt, Michael, G. Rehum. 1998. "Fertilizing Cropland with Poultry Manure." FO-05881-GO. University of 

Minnesota Extension Service http://www.extension.umn.edu/distribution/cropsystems/DC5881.html

39. Schmitt, Michael, G. Rehum. 1998. "Fertilizing Cropland with Dairy Manure." FO-05880-GO. University of Minnesota 

Extension Service http://www.extension.umn.edu/distribution/cropsystems/DC5880.html

40. Schmitt, Michael, G. Rehum. 1998. "Fertilizing Cropland with Beef Manure." FO-05882-GO. University of Minnesota 

Extension Service http://www.extension.umn.edu/distribution/cropsystems/DC5882.html

41. Wisconsin Dept. of Agriculture, Trade and Consumer Protection. 2005. "Wisconsin Federal Grant Application Notice." 

http://www.datcp.state.wi.us/arm/agriculture/land-water/odor/pdf/ WI_CIG_application.pdf

42. Natural Resources Conservation Service. 2005. "Waste Storage Facility. Code 313, Conservation Practice Standard." 

electronic Field Office Technical Guide, Wisconsin. http://efotg.nrcs.usda.gov/efotg_locator.aspx?map=WI

43. Natural Resources Conservation Service. 2005. "Nutrient Management. Code 590, Conservation Practice Standard." 

electronic Field Office Technical Guide, Wisconsin. http://efotg.nrcs.usda.gov/efotg_locator.aspx?map=WI

44. Natural Resources Conservation Service. 2005. "Wisconsin Conservation Planning Technical Note WI-1; Companion 

Document to NRCS FOTG Standard 590, Nutrient Management." electronic Field Office Technical Guide, Wisconsin. 

45. Natural Resources Conservation Service. 2005. "Solid/Liquid Waste Separation Facility, Code 632." electronic Field 

Office Technical Guide, Wisconsin. http://efotg.nrcs.usda.gov/efotg_locator.aspx?map=WI

46. Natural Resources Conservation Service. 2005. "Waste Treatment, Code 629." electronic Field Office Technical Guide, 

Wisconsin. http://efotg.nrcs.usda.gov/efotg_locator.aspx?map=WI

47. Natural Resources Conservation Service. 2005. "Amendments for Treatment of Agricultural Waste, Code 591." 

electronic Field Office Technical Guide, Wisconsin. http://efotg.nrcs.usda.gov/efotg_locator.aspx?map=WI

48. Natural Resources Conservation Service. 2005. "Manure Transfer, Code 634." electronic Field Office Technical Guide, 

Wisconsin. http://efotg.nrcs.usda.gov/efotg_locator.aspx?map=WI

[continued]

B-18
Appendix B-8. Notes on Control Strategies

a. Implementation: use existing authorities like anti-tampering compliance authority, pursuing a mandatory program based 

on current draft OTC model rule, or working with engine manufacturers on a voluntary program. 

b. Southeastern Wisconsin already requires tailpipe and OBDII inspections on passenger vehicles. This recommendation 

would expand the program to all of WI, re-start and expand the program in MN, and start a program in MI. Requires 

promulgation of State laws. (Similar measures were also mentioned in ENVIRON's phase I mobile source strategy

c. MOBILE5 estimates a 9% total emission inventory reduction with a fully implemented enhanced IM program. However, 

a NAS report in 2001 found that this may be an overestimation. The ENVIRON Phase I mobile source control measures 

report estimates an 8% NOX reduction in 2007 if all states in the LADCO region fully implemented an IM and OBD 

d. Co-benefits of this strategy are significant. PM, HC, and CO are reduced by 48, 48, and 68% respectively. Cetane 

e. Co-benefits of this strategy are significant. PM, HC, and CO are reduced by 10, 21, and 11% respectively. 98% of 

vehicles in this study are pre-1998. Cetane additives may decrease NOX emissions.

f. Opacity reduced 2-6% when switching from regular diesel to B20

g. Opacity reduced 5-11% when switching from regular diesel to B30

h. This test did not demonstrate PM or HC reductions using B20 or CARB diesel.

i. Emission benefits are not readily available for most nonroad applications. However, biodiesel is being used for 

j. 1% NOX reduction for line-haul locomotives, 2% for switching.

k. Based on Port of Los Angeles Emissions Inventory. Percentage may differ for LADCO region.

l. Co-benefits include reductions in PM, CO, and greenhouse gases. Low blends of ethanol demonstrate a slight increase in 

VOC cold-start emissions when compared to regular gasoline.

m. ENVIRON report assumes 15% participation in 2009 and 30% participation of HDDV anti-idling measures by 2012. 

The report also assumes 25% and 50% of switching and linehaul locomotives respectively. 

n. Calculation of percentage NOX control efficiency would require knowledge of the percentage of time a truck would 

participate in anti-idling programs. It is assumed that 100% of NOX would be reduced during the anti-idling time.

o. Control efficiency was cited from the ENVIRON Phase II report.

p. Control efficiencies were calculated based on the g/bhp-hr engine standard of the upgraded engine vs. the old engine.

q. Also demonstrates 10-30% PM reduction

r. ENVIRON Phase II report analyzes emission reductions and cost-effectiveness of LNC combined with DPF, resulting in 

PM reduction co-benefits and combined costs results. 

s. ENVIRON Phase II report analyzes emission reductions and cost-effectiveness of EGR combined with DPF, resulting in 

PM, VOC, and CO reduction co-benefits and combined costs results. 

t. ENVIRON Phase II report analyzes emission reductions and cost-effectiveness of SCR combined with DOC, resulting in 

PM, VOC, and CO reduction co-benefits and combined costs results. 

u. ENVIRON Phase II report analyzes emission reductions and cost-effectiveness of SCR combined with DPF, resulting in 

PM, VOC, and CO reduction co-benefits and combined costs results. 

v. Candidate measure ID EGU1

w. Candidate measure ID EGU2

x. Candidate measure ID ICI1. Timing of Implementation : Assumes full reductions achieved in 2009. Implementation 

y. Candidate measure ID ICI2. Timing of Implementation : Assumes full reductions achieved in 2013 Implementation Area : 

z. Candidate measure ID ICI3. Timing of Implementation : Assumes full reductions achieved in 2009 Implementation Area : 

aa. Applies to CO, HC (and toxics), PM, and somewhat for NOx, probably for nontailpipe HCs. Fresno Study referenced in 

Doug Lawson's presentation cited a 53% reduction in NOX, 65% in HC, and 94% in CO.

bb. Baseline and on-the-way measures are listed here as additional information that was provided by the LADCO white 

papers. We will include discussion on these existing or upcoming measures for all source categories in our final report.

B-19
Appendix B-8. Notes on Control Strategies

cc. used only on lean burn, natural gas spark ignited engines

dd. natural gas- and diesel-fired

ee. source 27 states 95% efficiency for rich-burn spark ignited engines

ff. source 27 states 95% efficiency for rich-burn spark ignited engines

gg. source 27 states 90% efficiency for internal combustion sources

hh. AirControlNET provided information on control technologies from multiple pollution sources; the reduction in tons listed 

under "Efficiency Estimate (%)" is an average of all the sources for a particular technology

ii. high cost

jj. Efficiency calculations are based on estimates of atmospheric losses, assuming a consistent distribution of losses among 

ammonia and other gases (N2O and N2)

kk. Baseline is spreading manure without incorporation

ll. Costly, even with cost-sharing, average price is $1000/cow

mm. Moderate to high cost

nn. Baseline is open ground storage (leaving manure on ground with no method of collection or storage)

oo. Baseline is earthen ground storage (leaving manure on ground with no method of collection or storage)

pp. Baseline is broadcasting manure with no waiting time before incorporation

qq. no particular strategy is described as "best practice" but State offers technical specifications for structures to meet 

standard, e.g., storage volume, depth, how much stress can be placed on the structure depending on the material

ss. the inhibitor works on ammonium forms of nitrogen; it is recommended to use this technique in the late summer or fall; 

reference also recommends timings of manure application (specific soil temperatures)

tt. reference broke out nutrient availability among indoor pit, outdoor pit, and farrow-nursery indoor pit storage options; all 

uu. reference broke out nutrient availability among duck, chicken, turkey, and poultry manure; all had same nutrient 

vv. reference provides efficiency in capturing solids from waste stream

ww. reference provides technical specifications for dimensions and distances from water sources

xx. reference provides material components and technical specifications for transfer mechanism

[continued]

B-20
Appendix C

EGU Control Analysis Parameters and

Individual EGU and ICI Boiler

Facility Analyses 
Contents

C.1. Cost Equations and Control Efficiencies for EGU .............................. C-1

C.2. Individual Facility Analysis ................................................ C-1

C.3. Example of a CUECost Individual Facility Spreadsheet ......................... C-2

References ................................................................. C-3

Tables

Table C-1. IPM Cost Equation Parameters Used for EGU Control Strategy Analyses ....... C-4

Table C-2. Emission Control Efficiencies Used for EGU Control Strategy Analyses ....... C-5

Table C-3. Detroit Edison/St. Clair-Belle River Facility (Michigan) .................... C-6

Table C-4. Consumers Energy Company/JH Campbell Facility (Michigan) .............. C-9

Table C-5. Wisconsin Electric/Presque Isle Facility (Michigan) ....................... C-11

Table C-6. Wisconsin Power and Light/Clay Boswell Facility (Minnesota) .............. C-14

Table C-7. Minnesota Power and Light/Syl Laskin Facility (Minnesota) ................ C-15

Table C-8. Northshore Mining Company/Silver Bay Facility (Minnesota) ............... C-16

Table C-9. Virginia Public Utilities Commission Facility (Minnesota) ................. C-17

Table C-10. Dairyland Power Coop/Alma Facility (Wisconsin) ....................... C-19

Table C-11. Xcel Energy/Bay Front Facility (Wisconsin) ............................ C-21

Table C-12. Alliant Energy-Wisconsin Power/Edgewater Facility (Wisconsin) ........... C-23

Table C-13. Alliant Energy-Wisconsin Power/Nelson Dewey Facility (Wisconsin) ....... C-25

Table C-14. Boise Cascade Corporation (Minnesota) ............................... C-26

Table C-15. CUECost Example - Input Data for Analysis (JH Campbell, Michigan) ...... C-28

Table C-16. CUECost Example - Results Output of Analysis

 (JH Campbell facility, Michigan) .................................... C-31
a

The ICI Workgroup recommendation and the Candidate Measure ID ICI1 control strategies discussed in

section 5.2 are used in this facility analysis. The Workgroup recommendation results in a regional cap for SO2

emissions of 1.2 lb/mmBtu (a 77% rollback of emissions for either the 3-state or 9-state region). When conducting

the facility analysis of an ICI boiler (Boise Cascade Corporation/International Falls in Minnesota) we found only one

unit at the facility emitted SO2. The remaining units all burned natural gas and so had negligible SO2 emissions.

According to Boise's 2005 permit, the SO2 emissions from Unit 2 amount to .1 lb/mmBtu, well below the regional

emissions caps. Therefore, this facility would not be controlled under this rule for SO2

, and further cost analysis for

ICI1 was not necessary. Analyses were conducted for ICI1 NOX, and the Workgroup recommendation for both NOX

and SO2.

C-1

C.1 Cost Equations and Control Efficiencies for EGU

Costs for regional EGU control strategies were analyzed using cost equations developed

for the Integrated Planning Model (IPM).1 The IPM model is commonly used to estimate the

costs of large-scale pollution control programs. The cost equation parameters are shown in

Table C-1. Control efficiencies used in the EGU regional strategy analyses are shown in

Table C-2.

C.2 EGU and ICI Boiler Individual Facility Analyses

Eleven electric generating facilities were selected for more in-depth analyses. The

analyses of these facilities were designed to ensure that opportunities for cost-effective visibility

improvements were not overlooked. None of these facilities are required to completed BART

analyses nor are they expected to reduce emissions pursuant to CAIR. Each of these facilities

includes multiple boilers, totaling 35 individual boilers that were analyzed. For these plantspecific analyses we estimated costs using the IPM cost equations,3

 and also drew on a number of

additional data sources, including a Menu of Options for controlling PM2.5 and its precursors by

the National Association of Clean Air Agencies (NACAA, formerly STAPPA and ALAPCO)2

and the Coal Utility Environmental Cost (CUECost) worksheet.3 For ICIs smaller than 100

MW, an ICI boiler cost estimation methodology developed by EPA was used.4,5

Tables C-1 through C-11 present detailed estimates of capital and annualized costs for

each individual unit, emissions reductions, and cost effectiveness for each control technology. 

The control technologies were selected to achieve the either the EGU1 cap or both the EGU1 and

EGU2 caps. Table C-12 is the analysis for an ICI boiler at Boise Cascade Corporation.a In this

case, the control technologies meet both the ICI1 rule and the ICI Workgroup recommendation.

It must be noted that the reported results are estimates. In fact, control cost estimates can

vary by at a factor of 2 or more. There are a number of reasons for this range of cost estimates.

First, all of the costing approaches rely on default assumptions for flue gas conditions, and for

retrofit costs and other contingency costs. These assumptions may differ from model to model. 

In addition, the cost equations have been developed for different base years, and use different

inflation factors to project costs to subsequent years. The CueCost and IPM models also use
C-2

different scaling factors to calculate costs for various boiler sizes. The NACAA report only

provides cost effectiveness values for broad boiler size ranges. 

C.3 Example CUECOST Individual Facility Input Spreadsheet

CUECost is a set of interrelated Excel spreadsheets that focus on costs for coal-fired

power plants. In the CUECost spreadsheets, the user has the ability to change all the parameters

to suit the facility under analysis. A sensitivity analysis of CUECost conducted by EPA has

shown that the following variables have significant impacts on the cost results (greater than 5%):6

• Unit capacity

• Heat rate

• Coal sulfur content

• Coal heating value

• Capacity factor

• Disposal mode

Unit capacities and heat rates for individual EGUs were obtained from the NEEDS database, and

capacity factors for 2018 were calculated based on the IPM unit-specific fuel consumption

estimates. Fuel sulfur contents were obtained from operating permits, where possible, or

calculated from SO2 emission rates reported in the NEI database. We assumed that the disposal

mode for sludge and ash will be landfilling. It must be noted that the results are ball-park

figures; default values were used when plant-specific information required by CUECost was not

available in the operating permits.

Tables C-17 and C-18 show an example of an individual facility analysis with the

CUECost program. Table C-20 shows the inputs for the program, and Table C-21 presents the

results. This example is from the JH Campbell facility in Michigan, which has three units

(Boilers 1, 2 and 3). Plant-specific information was used in the highlighted rows (the same type

of information was available for all other facilities as well). CUECost allows the user to specify

the type of coal being used at the facility, either choosing from its coal library or, if the coal is not

found in the library, input the coal characteristics for more accurate results. We often exercised

the latter option in our analyses. In this example Boiler 3 uses a different coal than Boilers 1

and 2. In cases like this, two separate analyses were conducted (i.e., two separate spreadsheets

were used): one for the boilers using coal type A and a second for boilers using coal type B.
C-3

1. Documentation for EPA Base Case 2006 V3.0. Using the Integrated Planning Model –

Chapter 5: Emission Control Technologies. U.S. Environmental Protection Agency,

Washington, D.C. November 2006. www.epa.gov/AIRMARKET/progsregs/epa-ipm/

2. STAPPA and ALAPCO (now NACAA). 2006. “Controlling Fine Particulate Matter

Under the Clean Air Act: A Menu of Options.” 

3. Keeth, R., R. Blagg, C. Burklin, B. Kosmicki, D. Rhodes, T. Waddell. Coal Utility

Environmental Cost (CUECost) Workbook User's Manual, Version 1.0.

4. Khan, S. 2003. Methodology, Assumptions, and References - Preliminary NOx Controls

Cost Estimates for Industrial Boilers. EPA-HQ-OAR-2003-0053-170.

5. Khan, S. 2003. Methodology, Assumptions, and References - Preliminary SO2 Controls

Cost Estimates for Industrial Boilers. EPA-HQ-OAR-2003-0053-166.

6. Srivastava, R.K. 2000. “Controlling SO2 Emissions: A Review of Technologies.”

EPA/600/R-00/093. U.S. Environmental Protection Agency, Washington, D.C.

References for Appendix C
Control technology Fuel and boiler type

Base value 

($/kW)

Scale 

factor Expon-ent

Base value 

($/kW-yr) Scale factor Expon-ent

B

(c

<100 MW 511.1 100 0.62 20.75 100 0.47 

100-300 MW 251.2 300 0.62 12.01 300 0.39 

300-500 MW 190.0 500 0.55 9.83 500 0.35 

500-700 MW 155.1 700 0.60 8.74 700 0.37 >700 MW 131.0 1,000 0.47 7.64 1,000 0.37 <100 MW 312.3 100 0.50 14.20 100 0.47 100-300 MW 169.3 300 0.33 8.74 300 0.56 300-500 MW 143.1 500 0.31 6.55 500 0.54 500-700 MW 128.9 700 0.15 5.46 700 0.63 >700 MW 122.3 1,000 0.15 4.37 1,000 0.63 

SCR Coal 133.8 243 0.27 0.89 243 0.27 

Oil / gas 38.6 200 0.35 1.19 200 0.35 

SNCR Coal, pulverized, term 1** 22.9 200 0.58 0.34 200 0.58 

Coal, pulverized, term 2** 26.1 100 0.68 0.40 100 0.68 Coal, cyclone 13.2 300 0.58 0.19 300 0.58 Coal, fluidized bed 22.9 200 0.58 0.35 200 0.58 Oil / gas 13.0 200 0.58 0.20 200 0.58 

LNB without OFA Coal, wall-fired 23.1 300 0.36 0.35 300 0.36 LNB with OFA Coal, wall-fired 31.3 300 0.36 0.48 300 0.36 LNB with close-coupled OFA Coal, tangential 12.2 300 0.36 0.02 300 0.36 LNB with separated OFA Coal, tangential 17.0 300 0.36 0.25 300 0.36 LNB with close-coupled and separated OFA

Coal, tangential 19.4 300 0.36 0.30 300 0.36 <100 MW 511.1 100 0.62 20.75 100 0.47 100-300 MW 251.2 300 0.62 12.01 300 0.39 300-500 MW 190.0 500 0.55 9.83 500 0.35 500-700 MW 155.1 700 0.60 8.74 700 0.37 >700 MW 131.0 1,000 0.47 7.64 1,000 0.37 <100 MW 312.3 100 0.50 14.20 100 0.47 100-300 MW 169.3 300 0.33 8.74 300 0.56 300-500 MW 143.1 500 0.31 6.55 500 0.54 500-700 MW 128.9 700 0.15 5.46 700 0.63 >700 MW 122.3 1,000 0.15 4.37 1,000 0.63 

Source: Reference 1

NOX Controls

Lime spray dryer scrubberLimestone forced oxidation scrubber* Cost equations take the following form: Cost = (Base value) x (Scale Factor/MW)^(exponent)

where "Base value," "Scale factor," and "exponent" are terms defined in the table, and MW is the capacity of the boiler

**For SNCR applied to pulverized coal, terms 1 and 2 are added together.

Table C-1. IPM Cost Equation Parameters Used for EGU Control Strategy Analyses

SO2 Controls

Capital cost factors*

Fixed operating and maintenance 

scaling factors*

Var

Limestone forced oxidation scrubberLime spray dryer scrubber

C-4
Control technology Fuel and boiler type

Estiamated 

control 

efficiency (%)

SO2 control measures

Limestone forced oxidation scrubber Coal /oil 95

Lime spray dryer scrubber Coal /oil 90

NOX control measures

SCR Coal 90

Oil / gas 80

SNCR Coal, pulverized or cyclone 35

Coal, fluidized bed 50

Oil / gas 50

LNB without OFA Coal, wall-fired 35

LNB with OFA Coal, wall-fired 40

LNB with close-coupled OFA Coal, tangential 40

LNB with separated OFA Coal, tangential 45

LNB with close-coupled and separated OFA Coal, tangential 50

Table C-2. Emission Control Efficiencies Used for EGU Control Strategy 

Analyses

C-5
Table C-3. Estimated Cost and Cost Effectiveness for EGU1 and EGU2 Control Strategies for t

Detroit Edison/St. Clair-Belle River Facility (Michigan)

State Facility Unit Fuel

Capacity (MW)

Baseline Emissions (tons)

Control Technology

% Reduction Cost Model

Total Capital Investment [$M2005]

Total O&M Cost [$M2005]

Total Annualized Cost [$M2005]

Emission Reduction (tons)

Cost Effectiveness [$2005/ton]

Lowest Annualized Cost ($M2005)

Highest Annualized Cost ($M2005)

Lowest Emissions Reduced (tons)

HiEmRe(to

MI

St. Clair/ Belle River 1 Coal 153 5,491 LSD 90 CUECost 54,602 6,604 14,783 4,942 2,991 10,628 18,012 4,942 5,2

IPM 44,092 4,023 10,628 4,942 2,151STAPPA - - - - 150-4000

LSFO 95 CUECost 71,543 7,295 18,012 5,216 3,453

IPM 69,090 4,938 15,288 5,216 2,931STAPPA - - - - 200-5000

2 Coal 162 6,162 LSD 90 CUECost 59,169 7,156 16,020 5,546 2,888 11,009 19,257 4,942 5,2

IPM 45,379 4,211 11,009 5,546 1,985STAPPA - - - - 150-4000

LSFO 95 CUECost 76,687 7,769 19,257 5,854 3,289

IPM 70,608 5,155 15,732 5,854 2,687STAPPA - - - - 200-5000

3 Coal 171 6,132 LSD 90 CUECost 58,567 7,149 15,923 5,519 2,885 11,425 19,263 4,942 5,8

IPM 46,631 4,440 11,425 5,519 2,070STAPPA - - - - 150-4000

LSFO 95 CUECost 76,094 7,864 19,263 5,825 3,307

IPM 72,074 5,412 16,209 5,825 2,783STAPPA - - - - 200-5000

4 Coal 158 5,734 LSD 90 CUECost 56,209 6,840 15,260 5,160 2,957 10,774 18,434 4,942 5,4

IPM 44,811 4,061 10,774 5,160 2,088STAPPA - - - - 150-4000

LSFO 95 CUECost 73,110 7,482 18,434 5,447 3,384

IPM 69,940 4,992 15,469 5,447 2,840STAPPA - - - - 200-5000

6 Coal 321 11,765 LSD 90 CUECost 75,056 10,823 22,066 10,588 2,084 16,444 25,653 4,942 11

IPM 61,545 7,224 16,444 10,588 1,553STAPPA - - - - 150-4000

LSFO 95 CUECost 92,898 11,737 25,653 11,176 2,295

IPM 89,995 8,446 21,928 11,176 1,962STAPPA - - - - 200-5000

7 Coal 450 11,765 LSD 90 CUECost 90,888 15,164 28,779 10,588 2,718 21,036 32,737 4,942 11

IPM 77,195 9,472 21,036 10,588 1,987STAPPA - - - - 150-4000

LSFO 95 CUECost 111,146 16,088 32,737 11,176 2,929

IPM 104,903 11,187 26,902 11,176 2,407STAPPA - - - - 200-5000

Plant Total 1,415 47,048 77,147 133,356 42,344 44

State Facility Unit Fuel

Capacity (MW)

Baseline Emissions (tons)

Control Technology

% Reduction Cost Model

Total Capital Investment [$M2005]

Total O&M Cost [$M2005]

Total Annualized Cost [$M2005]

Emission Reduction (tons)

Cost Effectiveness [$2005/ton]

Lowest Annualized Cost ($M2005)

Highest Annualized Cost ($M2005)

Lowest Emissions Reduced (tons)

HiEmRe(to

MI

St. Clair/ Belle River 1 Coal 153 1,071 SCR 90 CUECost 15,493 1,520 3,602 963 3,739 599 6,764 375 96

IPM 24,436 1,143 4,428 963 4,596STAPPA - - - - 1000-2000

Costs of SO2 Controls for EGUsCosts of NOx Controls for EGUs

C-6
Table C-3. Estimated Cost and Cost Effectiveness for EGU1 and EGU2 Control Strategies for t

Detroit Edison/St. Clair-Belle River Facility (Michigan)

State Facility Unit Fuel

Capacity (MW)

Baseline Emissions (tons)

Control Technology

% Reduction Cost Model

Total Capital Investment [$M2005]

Total O&M Cost [$M2005]

Total Annualized Cost [$M2005]

Emission Reduction (tons)

Cost Effectiveness [$2005/ton]

Lowest Annualized Cost ($M2005)

Highest Annualized Cost ($M2005)

Lowest Emissions Reduced (tons)

HiEmRe(to

SNCR 35 CUECost 2,219 301 599 375 1,600

IPM 3,727 1,420 1,921 375 5,126STAPPA - - - - 800-1500

LNB 35 CUECost 5,375 120 843 375 2,250

IPM 4,741 155 792 375 2,114STAPPA - - - - 200-1000

NGR 55 CUECost 5,006 6,091 6,764 589 11,488

IPM - - - 589 -STAPPA - - - - 500-2000

2 Coal 162 1,693 SCR 90 CUECost 17,433 1,736 4,079 1,524 2,677 744 7,595 593 1,5

IPM 25,477 1,207 4,631 1,524 3,039STAPPA - - - - 1000-2000

SNCR 35 CUECost 2,479 411 744 593 1,255

IPM 3,809 1,508 2,020 593 3,409STAPPA - - - - 800-1500

LNB 35 CUECost 5,579 125 875 593 1,476

IPM - - - 593 -STAPPA - - - - 200-1000

NGR 55 CUECost 5,339 6,878 7,595 931 8,156

IPM - - - 931 -STAPPA - - - - 500-2000

3 Coal 171 1,195 SCR 90 CUECost 16,866 1,651 3,918 1,076 3,641 638 7,505 418 1,0

IPM 26,503 1,291 4,853 1,076 4,510STAPPA - - - - 1000-2000

SNCR 35 CUECost 2,376 319 638 418 1,525

IPM 3,888 1,627 2,149 418 5,137STAPPA - - - - 800-1500

LNB 35 CUECost 5,778 129 906 418 2,166

IPM - - - 418 -STAPPA - - - - 200-1000

NGR 55 CUECost 5,485 6,767 7,505 657 11,414

IPM - - - 657 -STAPPA - - - - 500-2000

4 Coal 158 1,118 SCR 90 CUECost 16,244 1,616 3,799 1,006 3,776 609 7,079 391 1,0

IPM 25,017 1,145 4,507 1,006 4,480STAPPA - - - - 1000-2000

SNCR 35 CUECost 2,276 303 609 391 1,556

IPM 3,773 1,422 1,929 391 4,931STAPPA - - - - 800-1500

LNB 35 CUECost 5,489 123 861 391 2,200

IPM 4,840 157 807 391 2,063STAPPA - - - - 200-1000

NGR 55 CUECost 5,083 6,396 7,079 615 11,514

IPM - - - 615 -STAPPA - - - - 500-2000

C-7
Table C-3. Estimated Cost and Cost Effectiveness for EGU1 and EGU2 Control Strategies for t

Detroit Edison/St. Clair-Belle River Facility (Michigan)

State Facility Unit Fuel

Capacity (MW)

Baseline Emissions (tons)

Control Technology

% Reduction Cost Model

Total Capital Investment [$M2005]

Total O&M Cost [$M2005]

Total Annualized Cost [$M2005]

Emission Reduction (tons)

Cost Effectiveness [$2005/ton]

Lowest Annualized Cost ($M2005)

Highest Annualized Cost ($M2005)

Lowest Emissions Reduced (tons)

HiEmRe(to

6 Coal 321 1,766 SCR 90 CUECost 25,234 2,886 6,278 1,589 3,950 846 13,028 618 1,5

IPM 41,972 2,180 7,821 1,589 4,921STAPPA - - - - 1000-2000

SNCR 35 CUECost 3,070 433 846 618 1,369

IPM 4,939 2,942 3,606 618 5,834STAPPA - - - - 800-1500

LNB 35 CUECost 8,701 195 1,364 618 2,207

IPM - - - 618 -STAPPA - - - - 200-1000

NGR 55 CUECost 7,844 11,974 13,028 971 13,414

IPM - - - 971 -STAPPA - - - - 500-2000

7 Coal 450 1,766 SCR 90 CUECost 33,526 4,143 8,648 1,589 5,442 1,214 10,190 618 1,5

IPM 53,710 2,972 10,190 1,589 6,412STAPPA - - - - 1000-2000

SNCR 35 CUECost 3,891 691 1,214 618 1,964

IPM 5,619 4,177 4,932 618 7,980STAPPA - - - - 800-1500

Plant Total 1,415 8,609 4,649 51,639 3,013 7,7

C-8
Table C-4. Consumers Energy Company/JH Campbell Facility (Michigan)

State Facility Unit Fuel

Capacity (MW)

Baseline Emissions (tons)

Control Technology

% Reduction Cost Model

Total Capital Investment [$M2005]

Total O&M Cost [$M2005]

Total Annualized Cost [$M2005]

Emission Reduction (tons)

Cost Effectiveness [$2005/ton]

Lowest Annualized Cost ($M2005)

Highest Annualized Cost ($M2005)

Lowest Emissions Reduced (tons)

HigEmRed(ton

MI JH Campbell 1 Coal 260 10,767 LSD 90 CUECost 78,193 11,709 23,423 9,690 2,417 14,483 24,314 9,690 10,2

IPM 57,580 5,858 14,483 9,690 1,495STAPPA - - - - 150-4000

LSFO 95 CUECost 93,492 10,309 24,314 10,229 2,377

IPM 84,520 7,077 19,738 10,229 1,930STAPPA - - - - 200-5000

2 Coal 355 12,986 LSD 90 CUECost 83,538 13,935 26,449 11,688 2,263 17,567 27,430 11,688 12,3

IPM 65,844 7,704 17,567 11,688 1,503STAPPA - - - - 150-4000

LSFO 95 CUECost 99,523 12,521 27,430 12,337 2,223

IPM 94,201 9,060 23,171 12,337 1,878STAPPA - - - - 200-5000

3 Coal 820 30,020 LSD 90 CUECost 112,653 24,860 41,735 27,018 1,545 32,371 47,039 27,018 28,5

IPM 119,585 14,457 32,371 27,018 1,198STAPPA - - - - 150-4000

LSFO 95 CUECost 156,806 23,550 47,039 28,519 1,649

IPM 136,680 17,580 38,055 28,519 1,334STAPPA - - - - 200-5000

Plant Total 1435 53773 64,421 98,783 48,396 51,0

State Facility Unit Fuel

Capacity (MW)

Baseline Emissions (tons)

Control Technology

% Reduction Cost Model

Total Capital Investment [$M2005]

Total O&M Cost [$M2005]

Total Annualized Cost [$M2005]

Emission Reduction (tons)

Cost Effectiveness [$2005/ton]

Lowest Annualized Cost ($M2005)

Highest Annualized Cost ($M2005)

Lowest Emissions Reduced (tons)

HigEmRed(ton

MI JH Campbell 1 Coal 260 3,153 SCR 78 CUECost 29,285 3,146 7,082 2,459 2,880 1,116 12,797 1,104 2,45

IPM 35,987 1,719 6,556 2,459 2,666STAPPA - - - - 1000-2000

SNCR 35 CUECost 3,316 671 1,116 1,104 1,012

IPM 4,559 2,250 2,862 1,104 2,594STAPPA - - - - 800-1500

LNB 35 CUECost 7,589 170 1,190 1,104 1,078

IPM - - - 1,104 -STAPPA - - - - 200-1000

NGR 55 CUECost 6,885 11,872 12,797 1,734 7,379

IPM - - - 1,734 -STAPPA - - - - 500-2000

Costs of SO2 Controls for EGUsCosts of NOx Controls for EGUs

C-9
Table C-4. Consumers Energy Company/JH Campbell Facility (Michigan)

State Facility Unit Fuel

Capacity (MW)

Baseline Emissions (tons)

Control Technology

% Reduction Cost Model

Total Capital Investment [$M2005]

Total O&M Cost [$M2005]

Total Annualized Cost [$M2005]

Emission Reduction (tons)

Cost Effectiveness [$2005/ton]

Lowest Annualized Cost ($M2005)

Highest Annualized Cost ($M2005)

Lowest Emissions Reduced (tons)

HigEmRed(ton

2 Coal 355 7,359 SCR 88 CUECost 33,388 4,005 8,492 6,476 1,311 1,457 15,574 2,576 6,47

IPM 45,173 2,336 8,407 6,476 1,298STAPPA - - - - 1000-2000

SNCR 35 CUECost 3,946 1,424 1,954 2,576 759

IPM 5,133 3,182 3,872 2,576 1,503STAPPA - - - - 800-1500

LNB 35 CUECost 9,292 208 1,457 2,576 566

IPM - - - 2,576 -STAPPA - - - - 200-1000

NGR 55 CUECost 8,375 14,448 15,574 4,047 3,848

IPM - - - 4,047 -STAPPA - - - - 500-2000

3 Coal 820 11,799 SCR 70 CUECost 64,401 8,825 17,481 8,259 2,117 2,511 17,481 4,130 8,25

IPM 90,557 4,830 17,000 8,259 2,058STAPPA - - - - 1000-2000

SNCR 35 CUECost 6,647 2,231 3,124 4,130 757

IPM 7,069 6,937 7,887 4,130 1,910STAPPA - - - - 800-1500

LNB 35 CUECost 16,012 359 2,511 4,130 608

IPM - - - 4,130 -STAPPA - - - - 200-1000

NGR 55 CUECost 17,069 6,921 9,215 6,489 1,420

IPM - - - 6,489 -STAPPA - - - - 500-2000

Plant Total 1435 22311 5,084 45,851 7,809 17,1

C-10
Table C-5. Wisconsin Electric/Presque Isle Facility (Michigan)

State Facility Unit Fuel

Capacity (MW)

Baseline Emissions (tons)

Control Technology

% Reduction Cost Model

Total Capital Investment [$M2005]

Total O&M Cost [$M2005]

Total Annualized Cost [$M2005]

Emission Reduction (tons)

Cost Effectiveness [$2005/ton]

Lowest Annualized Cost ($M2005)

Highest Annualized Cost ($M2005)

Lowest Emissions Reduced (tons)

HigEmRed(ton

MI

WI Electric/Presque Isle 5 Coal 88 3,431 LSD 90 CUECost 45,698 4,761 11,607 3,088 3,759 6,536 14,697 3,088 3,2

IPM 27,815 2,369 6,536 3,088 2,117STAPPA - - - - 150-4000

LSFO 95 CUECost 62,139 5,389 14,697 3,259 4,509

IPM 46,657 2,935 9,924 3,259 3,045STAPPA - - - - 200-5000

6 Coal 88 3,416 LSD 90 CUECost 45,635 4,750 11,586 3,075 3,768 6,536 14,680 3,075 3,2

IPM 27,815 2,369 6,536 3,075 2,126STAPPA - - - - 150-4000

LSFO 95 CUECost 62,076 5,381 14,680 3,245 4,523

IPM 46,657 2,935 9,924 3,245 3,058STAPPA - - - - 200-5000

7 Coal 88 2,046 LSD 90 CUECost 47,226 5,026 12,100 1,842 6,570 6,536 15,113 1,842 1,9

IPM 27,815 2,369 6,536 1,842 3,549STAPPA - - - - 150-4000

LSFO 95 CUECost 63,665 5,576 15,113 1,944 7,773

IPM 46,657 2,935 9,924 1,944 5,104STAPPA - - - - 200-5000

8 Coal 88 1,965 LSD 90 CUECost 46,584 4,914 11,893 1,768 6,726 6,536 14,938 1,768 1,8

IPM 27,815 2,369 6,536 1,768 3,697STAPPA - - - - 150-4000

LSFO 95 CUECost 63,027 5,497 14,938 1,866 8,004

IPM 46,657 2,935 9,924 1,866 5,317STAPPA - - - - 200-5000

9 Coal 88 1,967 LSD 90 CUECost 46,605 4,918 11,899 1,770 6,721 6,536 14,944 1,770 1,8

IPM 27,815 2,369 6,536 1,770 3,692STAPPA - - - - 150-4000

LSFO 95 CUECost 63,047 5,499 14,944 1,869 7,997

IPM 46,657 2,935 9,924 1,869 5,310STAPPA - - - - 200-5000

Plant Total 440 12,825 32,679 74,371 11,543 12,

State Facility Unit Fuel

Capacity (MW)

Baseline Emissions (tons)

Control Technology

% Reduction Cost Model

Total Capital Investment [$M2005]

Total O&M Cost [$M2005]

Total Annualized Cost [$M2005]

Emission Reduction (tons)

Cost Effectiveness [$2005/ton]

Lowest Annualized Cost ($M2005)

Highest Annualized Cost ($M2005)

Lowest Emissions Reduced (tons)

HigEmRed(ton

MI

WI Electric/Presque Isle 5 Coal 88 1,012 SCR 90 CUECost 12,663 988 2,690 910 2,954 427 4,066 354 910 

IPM 16,319 685 2,878 910 3,161STAPPA - - - - 1000-2000

SNCR 35 CUECost 1,916 288 546 354 1,542

IPM 3,023 799 1,205 354 3,404STAPPA - - - - 800-1500

Costs of SO2 Controls for EGUsCosts of NOx Controls for EGUs

C-11
Table C-5. Wisconsin Electric/Presque Isle Facility (Michigan)

State Facility Unit Fuel

Capacity (MW)

Baseline Emissions (tons)

Control Technology

% Reduction Cost Model

Total Capital Investment [$M2005]

Total O&M Cost [$M2005]

Total Annualized Cost [$M2005]

Emission Reduction (tons)

Cost Effectiveness [$2005/ton]

Lowest Annualized Cost ($M2005)

Highest Annualized Cost ($M2005)

Lowest Emissions Reduced (tons)

HigEmRed(ton

LNB 35 CUECost 2,720 61 427 354 1,205

IPM - - - 354 -STAPPA - - - - 200-1000

NGR 55 CUECost 3,962 3,534 4,066 556 7,308

IPM - - - 556 -STAPPA - - - - 500-2000

6 Coal 88 1,049 SCR 90 CUECost 12,630 984 2,681 944 2,839 427 4,051 367 944 

IPM 16,319 685 2,878 944 3,047STAPPA - - - - 1000-2000

SNCR 35 CUECost 1,913 288 545 367 1,483

IPM 3,023 799 1,205 367 3,282STAPPA - - - - 800-1500

LNB 35 CUECost 2,720 61 427 367 1,161

IPM - - - 367 -STAPPA - - - - 200-1000

NGR 55 CUECost 3,962 3,519 4,051 577 7,020

IPM - - - 577 -STAPPA - - - - 500-2000

7 Coal 88 1,218 SCR 90 CUECost 13,467 1,082 2,892 1,096 2,640 427 4,430 426 1,0

IPM 16,319 685 2,878 1,096 2,626STAPPA - - - - 1000-2000

SNCR 35 CUECost 1,982 308 574 426 1,348

IPM 3,023 799 1,205 426 2,828STAPPA - - - - 800-1500

LNB 35 CUECost 2,720 61 427 426 1,001

IPM - - - 426 -STAPPA - - - - 200-1000

NGR 55 CUECost 3,962 3,897 4,430 670 6,615

IPM - - - 670 -STAPPA - - - - 500-2000

8 Coal 88 1,063 SCR 90 CUECost 13,130 1,042 2,807 957 2,934 427 4,276 372 957 

IPM 16,319 108 2,302 957 2,406STAPPA - - - - 1000-2000

SNCR 35 CUECost 1,954 300 562 372 1,512

IPM 3,023 799 1,205 372 3,240STAPPA - - - - 800-1500

LNB 35 CUECost 2,720 61 427 372 1,146

IPM - - - 372 -STAPPA - - - - 200-1000

NGR 55 CUECost 3,962 3,744 4,276 585 7,314

IPM - - - 585 -STAPPA - - - - 500-2000

C-12
Table C-5. Wisconsin Electric/Presque Isle Facility (Michigan)

State Facility Unit Fuel

Capacity (MW)

Baseline Emissions (tons)

Control Technology

% Reduction Cost Model

Total Capital Investment [$M2005]

Total O&M Cost [$M2005]

Total Annualized Cost [$M2005]

Emission Reduction (tons)

Cost Effectiveness [$2005/ton]

Lowest Annualized Cost ($M2005)

Highest Annualized Cost ($M2005)

Lowest Emissions Reduced (tons)

HigEmRed(ton

9 Coal 88 1,120 SCR 90 CUECost 13,141 1,044 2,690 1,008 2,668 427 4,066 392 1,0

IPM 16,319 685 2,878 1,008 2,854STAPPA - - - - 1000-2000

SNCR 35 CUECost 1,955 300 546 392 1,392

IPM 3,023 799 1,205 392 3,074STAPPA - - - - 800-1500

LNB 35 CUECost 2,720 61 427 392 1,088

IPM - - - 392 -STAPPA - - - - 200-1000

NGR 55 CUECost 3,962 3,749 4,066 616 6,084

IPM - - - 616 -STAPPA - - - - 500-2000

Plant Total 440 5,462 2,133 20,890 1,912 4,9

C-13
Table C-6. Minnesota Power/Clay Boswell Facility (Minnesota)

State Facility Unit Fuel

Capacity 

(MW)

Baseline 

Emissions 

(tons)

Control 

Technology % Reduction Cost Model

Total Capital 

Investment 

[$M2005]

Total O&M Cost 

[$M2005]

Total 

Annualized Cost 

[$M2005]

Emission 

Reduction 

(tons)

Cost Effectiveness 

[$2005/ton]

Lowest 

Annualized Cost 

($M2005)

Highest 

Annualized 

Cost ($M2005)

Lowest 

Emissions 

Reduced (tons)

Highest 

Emissions 

Reduced (tons)

Cost Effectiveness 

($2005/ton)

MN Clay Boswell 1 Coal 69 2,587 LSD 90 CUECost 45,601 5,271 12,102 2,328 5,198 5,660 14,108 2,328 2,458 150-5741

IPM 24,610 1,974 5,660 2,328 2,431

STAPPA - - - - 150-4000

LSFO 95 CUECost 59,232 5,235 14,108 2,458 5,741

IPM 42,536 2,469 8,841 2,458 3,598

STAPPA - - - - 200-5000

2 Coal 69 2,572 LSD 90 CUECost 46,112 5,266 12,174 2,315 5,259 5,625 14,169 2,315 2,443 150-5799

IPM 24,610 1,938 5,625 2,315 2,430

STAPPA - - - - 150-4000

LSFO 95 CUECost 59,739 5,220 14,169 2,443 5,799

IPM 42,536 2,434 8,806 2,443 3,604

STAPPA - - - - 200-5000

Plant Total 138 5159 11,285 28,276 4,643 4,901 2431-5770

State Facility Unit Fuel

Capacity 

(MW)

Baseline 

Emissions 

(tons)

Control 

Technology % Reduction Cost Model

Total Capital 

Investment 

[$M2005]

Total O&M Cost 

[$M2005]

Total 

Annualized Cost 

[$M2005]

Emission 

Reduction 

(tons)

Cost Effectiveness 

[$2005/ton]

Lowest 

Annualized Cost 

($M2005)

Highest 

Annualized 

Cost ($M2005)

Lowest 

Emissions 

Reduced (tons)

Highest 

Emissions 

Reduced (tons)

Cost Effectiveness 

($2005/ton)

MN Clay Boswell 1 Coal 69 693 SCR 90 CUECost 10,693 761 2,198 624 3,524 472 3,157 243 624 500-8281

IPM 13,664 550 2,387 624 3,825

STAPPA - - - - 1000-2000

SNCR 35 CUECost 1,754 237 472 243 1,947

IPM 2,758 627 997 243 4,111

STAPPA - - - - 800-1500

NGR 55 CUECost 3,635 2,669 3,157 381 8,281

IPM - - - 381 -

STAPPA - - - - 500-2000

2 Coal 69 689 SCR 90 CUECost 10,937 781 2,251 620 3,628 474 3,142 241 620 500-8289

IPM 13,664 531 2,367 620 3,817

STAPPA - - - - 1000-2000

SNCR 35 CUECost 1,773 236 474 241 1,965

IPM 2,758 602 973 241 4,032

STAPPA - - - - 800-1500

NGR 55 CUECost 3,635 2,654 3,142 379 8,289

IPM - - - 379 -

STAPPA - - - - 500-2000

4 Coal 426 4,859 SCR 90 CUECost 36,447 3,805 8,703 4,373 1,990 1,408 23,558 1,701 4,373 500-8815

IPM 51,611 3,525 10,461 4,373 2,392

STAPPA - - - - 1000-2000

SNCR 35 CUECost 3,919 882 1,408 1,701 828

IPM 5,503 5,033 5,773 1,701 3,394

STAPPA - - - - 800-1500

NGR 55 CUECost 9,854 22,234 23,558 2,673 8,815

IPM - - - 2,673 -

STAPPA - - - - 500-2000

Plant Total 564 6242 2,355 29,857 2,185 5,617 1078-5315

Costs of SO2 Controls for EGUs

Costs of NOx Controls for EGUs

C-14
Table C-7. Minnesota Power/Syl Laskin Facility (Minnesota)*

State Facility Unit Fuel

Capacity 

(MW)

Baseline 

Emissions 

(tons)

Control 

Technology % Reduction Cost Model

Total Capital 

Investment 

[$M2005]

Total 

O&M Cost 

[$M2005]

Total 

Annualized 

Cost [$M2005]

Emission 

Reduction 

(tons)

Cost 

Effectiveness 

[$2005/ton]

Lowest 

Annualized 

Cost 

($M2005)

Highest 

Annualized 

Cost 

($M2005)

Lowest 

Emissions 

Reduced 

(tons)

Highest 

Emissions 

Reduced 

(tons)

Cost 

Effectiveness 

($2005/ton)

MN Syl Laskin 1 Coal 55 951 LSD 90 CUECost 44,526 4,856 11,526 856 13,460 4,955 11,526 856 904 150-13460

IPM 21,945 1,668 4,955 856 5,786

STAPPA - - - - 150-4000

LSFO 95 CUECost 37,652 4,253 9,894 904 10,945

IPM 39,005 2,106 7,949 904 8,794

STAPPA - - - - 200-5000

2 Coal 55 950 LSD 90 CUECost 58,190 4,856 13,573 855 15,873 4,698 13,573 855 903 150-15873

IPM 21,945 1,662 4,949 855 5,788

STAPPA - - - - 150-4000

LSFO 95 CUECost 58,192 4,852 13,569 903 15,033

IPM 39,005 2,100 7,943 903 8,800

STAPPA - - - - 200-5000

Plant Total 110 1902 9,653 25,099 1,711 1,807 5640-13894

* This facility is installing NOx controls so NOx control costs were not evaluated

Costs of SO2 Controls for EGUs

C-15
Table C-8. Northshore Mining Company/Silver Bay Facility (Minnesota)

State Facility Unit Fuel

Capacity (MW)

Baseline Emissions (tons)

Control Technology

% Reduction Cost Model

Total Capital Investment [$M2005]

Total O&M Cost [$M2005]

Total Annualized Cost [$M2005]

Emission Reduction (tons)

Cost Effectiveness [$2005/ton]

Lowest Annualized Cost ($M2005)

Highest Annualized Cost ($M2005)

Lowest Emissions Reduced (tons)

HigEmRed(ton

MN

Northshore/Silver Bay 1 Coal 85 851 LSD 90 CUECost 43,277,712 3,894 10,377 766 13,549 3,465 12,918 766 808 

IPM 17,737 808 3,465 766 4,524STAPPA - - - - 150-4000

LSFO 95 CUECost 58,235 4,195 12,918 808 15,979

IPM 33,215 1,156 6,132 808 7,585STAPPA - - - - 200-5000

Plant Total 85 851 3,465 12,918 766 808 

State Facility Unit Fuel

Capacity (MW)

Baseline Emissions (tons)

Control Technology

% Reduction Cost Model

Total Capital Investment [$M2005]

Total O&M Cost [$M2005]

Total Annualized Cost [$M2005]

Emission Reduction (tons)

Cost Effectiveness [$2005/ton]

Lowest Annualized Cost ($M2005)

Highest Annualized Cost ($M2005)

Lowest Emissions Reduced (tons)

HigEmRed(ton

MN

Northshore/Silver Bay 1 Coal 85 1122 SCR 90 CUECost 11,870 849 2,627 1,010 2,602 322 2,627 16 40 

IPM 8,498 56 1,199 1,010 1,187STAPPA - - - - 1000-2000

SNCR 35 CUECost 1,758 205 468 393 1,192

IPM 2,160 32 322 393 821

STAPPA - - - - 800-1500

LNB 35 CUECost 3,668 82 632 393 1,609

IPM 2,546 39 381 393 971

STAPPA - - - - 200-1000

NGR 55 CUECost 3,912 844 1,430 617 2,317

IPM - - - 617 -

STAPPA - - - - 500-2000

Plant Total 85 1122 322 2,627 16 40 

Costs of SO2 Controls for EGUsCosts of NOx Controls for EGUs

C-16
Table C-9. Virginia Public Utilities Commission Facility (Minnesota)

State Facility Unit Fuel

Capacity (MW)

Baseline Emissions (tons)

Control Technology

% Reduction Cost Model

Total Capital Investment [$M2005]

Total O&M Cost [$M2005]

Total Annualized Cost [$M2005]

Emission Reduction (tons)

Cost Effectiveness [$2005/ton]

Lowest Annualized Cost ($M2005)

Highest Annualized Cost ($M2005)

Lowest Emissions Reduced (tons)

HigheEmissReduc(tons)

MN Virginia PUC 7 Coal 10 584 LSD 90 CUECost 30,787 1,616 6,228 525 11,859 6,228 8,933 525 554 

IPM - - - 525 -STAPPA - - - - 150-4000

LSFO 95 CUECost 44,821 2,219 8,933 554 16,116

IPM - - - 554 -STAPPA - - - - 200-5000

9 Coal 10 584 LSD 90 CUECost 30,787 1,616 6,228 525 11,859 6,228 8,933 525 554 

IPM - - - 525 -STAPPA - - - - 150-4000

LSFO 95 CUECost 44,821 2,219 8,933 554 16,116

IPM - - - 554 -STAPPA - - - - 200-5000

10 Coal 10 12,606 LSD 90 CUECost 30,787 1,616 6,228 11,346 549 6,228 8,933 11,346 11,976 

IPM - - - 11,346 -STAPPA - - - - 150-4000

LSFO 95 CUECost 44,821 2,219 8,933 11,976 -

IPM - - - 11,976 -STAPPA - - - - 200-5000

Plant Total 30 13,773 18,684 26,800 12,396 13,085 

State Facility Unit Fuel

Capacity (MW)

Baseline Emissions (tons)

Control Technology

% Reduction Cost Model

Total Capital Investment [$M2005]

Total O&M Cost [$M2005]

Total Annualized Cost [$M2005]

Emission Reduction (tons)

Cost Effectiveness [$2005/ton]

Lowest Annualized Cost ($M2005)

Highest Annualized Cost ($M2005)

Lowest Emissions Reduced (tons)

HigheEmissReduc(tons)

MN Virginia PUC 7 Coal 10 125 SCR 90 CUECost 4,188 180 743 113 6,589 143 743 44 113 

IPM 3,254 68 505 113 4,481STAPPA - - - - 1000-2000

SNCR 35 CUECost 1,259 115 284 44 6,477

IPM 1,322 67 245 44 5,584STAPPA - - - - 800-1500

LNB 35 CUECost 913 20 143 44 3,264

IPM - - - 44 -STAPPA - - - 200-1000

NGR 55 CUECost 2,270 316 621 69 9,011

IPM - - - 69 -STAPPA - - - - 500-2000

9 Coal 10 125 SCR 90 CUECost 4,188 180 743 113 6,589 143 743 44 113 

IPM 3,254 68 505 113 4,481STAPPA - - - - 1000-2000

SNCR 35 CUECost 1,259 115 284 44 6,477

IPM 1,322 67 245 44 5,584STAPPA - - - - 800-1500

LNB 35 CUECost 913 20 143 44 3,264

IPM - - - 44 -STAPPA - - - 200-1000

NGR 55 CUECost 2,270 316 621 69 9,011

IPM - - - 69 -STAPPA - - - - 500-2000

Costs of SO2 Controls for EGUsCosts of NOx Controls for EGUs

C-17
Table C-9. Virginia Public Utilities Commission Facility (Minnesota)

State Facility Unit Fuel

Capacity (MW)

Baseline Emissions (tons)

Control Technology

% Reduction Cost Model

Total Capital Investment [$M2005]

Total O&M Cost [$M2005]

Total Annualized Cost [$M2005]

Emission Reduction (tons)

Cost Effectiveness [$2005/ton]

Lowest Annualized Cost ($M2005)

Highest Annualized Cost ($M2005)

Lowest Emissions Reduced (tons)

HigheEmissReduc(tons)

10 Coal 10 0 SCR 90 CUECost 4,188 180 743 0 - 108 743 0 0 

IPM - - - 0 -

STAPPA - - - - -

SNCR 35 CUECost 1,259 115 284 0 -

IPM 720 11 108 0 -

STAPPA - - - - -

LNB 35 CUECost 913 20 143 0 -

IPM - - - 0 -

STAPPA - - - - -

NGR 55 CUECost 2,270 316 621 0 -

IPM - - - 0 -

STAPPA - - - - -

Plant Total 30 251 394 2,229 88 226 

C-18
Table C-10. Dairyland Power Coop/Alma Facility (Wisconsin)

State Facility Unit Fuel

Capacity (MW)

Baseline Emissions (tons)

Control Technology

% Reduction Cost Model

Total Capital Investment [$M2005]

Total O&M Cost [$M2005]

Total Annualized Cost [$M2005]

Emission Reduction (tons)

Cost Effectiveness [$2005/ton]

Lowest Annualized Cost ($M2005)

Highest Annualized Cost ($M2005)

Lowest Emissions Reduced (tons)

Highest EmissionReduced (tons)

WI Dairyland1 Coal 18 1,384 LSD 90 CUECost 33,226 2,297 7,274 1,245 5,841 2,748 9,953 1,245 1,315 

IPM 12,606 859 2,748 1,245 2,206STAPPA - - - - 150-4000

LSFO 95 CUECost 47,057 2,904 9,953 1,315 7,571

IPM 25,663 1,101 4,945 1,315 3,762STAPPA - - - - 200-5000

2 Coal 18 1,165 LSD 90 CUECost 33,226 2,213 7,190 1,048 6,858 2,701 9,874 1,048 1,107 

IPM 12,606 813 2,701 1,048 2,576STAPPA - - - - 150-4000

LSFO 95 CUECost 47,057 2,825 9,874 1,107 8,922

IPM 25,663 1,054 4,899 1,107 4,426STAPPA - - - - 200-5000

3 Coal 22 1,396 LSD 90 CUECost 34,312 2,416 7,556 1,256 6,016 2,986 10,284 1,256 1,326 

IPM 13,805 918 2,986 1,256 2,378STAPPA - - - - 150-4000

LSFO 95 CUECost 48,384 3,036 10,284 1,326 7,757

IPM 27,487 1,184 5,302 1,326 3,999STAPPA - - - - 200-5000

4 Coal 57 2,415 LSD 90 CUECost 42,672 4,086 10,478 2,174 4,820 5,090 13,325 2,174 2,295 

IPM 22,357 1,741 5,090 2,174 2,341STAPPA - - - - 150-4000

LSFO 95 CUECost 57,570 4,701 13,325 2,295 5,807

IPM 39,561 2,188 8,114 2,295 3,536STAPPA - - - - 200-5000

5 Coal 77 3,514 LSD 90 CUECost 43,802 4,382 10,944 3,163 3,460 6,175 14,097 3,163 3,338 

IPM 26,064 2,271 6,175 3,163 1,953STAPPA - - - - 150-4000

LSFO 95 CUECost 60,464 5,039 14,097 3,338 4,223

IPM 44,421 2,798 9,453 3,338 2,832STAPPA - - - - 200-5000

Plant Total 192 9,874 19,701 57,533 8,886 9,380 

State Facility Unit Fuel

Capacity (MW)

Baseline Emissions (tons)

Control Technology % ReductionCost Model

Total Capital Investment [$M2005]

Total O&M Cost [$M2005]

Total Annualized Cost [$M2005]

Emission Reduction (tons)

Cost Effectiveness [$2005/ton]

Lowest Annualized Cost ($M2005)

Highest Annualized Cost ($M2005)

Lowest Emissions Reduced (tons)

Highest EmissionReduced (tons)

WI Dairyland1 Coal 18 316 SCR 90 CUECost 5,047 244 922 285 3,238 152 1,336 111 285 

IPM 5,178 221 917 285 3,223STAPPA - - - - 1000-2000

SNCR 35 CUECost 1,301 146 321 111 2,900

IPM 1,675 231 456 111 4,119STAPPA - - - - 800-1500

LNB 35 CUECost 970 22 152 111 1,373

IPM 1,214 31 194 111 1,753STAPPA - - - - 200-1000

NGR 55 CUECost 2,548 994 1,336 174 7,682

IPM - - - 174 -

STAPPA - - - - 500-2000

Costs of SO2 Controls for EGUsCosts of NOx Controls for EGUs

C-19
Table C-10. Dairyland Power Coop/Alma Facility (Wisconsin)

State Facility Unit Fuel

Capacity (MW)

Baseline Emissions (tons)

Control Technology

% Reduction Cost Model

Total Capital Investment [$M2005]

Total O&M Cost [$M2005]

Total Annualized Cost [$M2005]

Emission Reduction (tons)

Cost Effectiveness [$2005/ton]

Lowest Annualized Cost ($M2005)

Highest Annualized Cost ($M2005)

Lowest Emissions Reduced (tons)

Highest EmissionReduced (tons)

2 Coal 18 266 SCR 90 CUECost 5,047 242 920 240 3,840 152 1,226 93 240 

IPM 5,178 192 888 240 3,705STAPPA - - - - 1000-2000

SNCR 35 CUECost 1,300 139 314 93 3,369

IPM 1,675 198 423 93 4,544STAPPA - - - - 800-1500

LNB 35 CUECost 970 22 152 93 1,631

IPM 1,214 29 192 93 2,061

STAPPA - - - - 200-1000

NGR 55 CUECost 2,548 883 1,226 146 8,370

IPM - - - 146 -STAPPA - - - - 500-2000

3 Coal 22 319 SCR 90 CUECost 5,662 290 1,051 287 3,662 173 1,411 112 287 

IPM 5,908 224 1,018 287 3,547STAPPA - - - - 1000-2000

SNCR 35 CUECost 1,349 148 330 112 2,953

IPM 1,792 234 475 112 4,257STAPPA - - - - 800-1500

LNB 35 CUECost 1,105 25 173 112 1,552

IPM 1,363 33 216 112 1,939STAPPA - - - - 200-1000

NGR 55 CUECost 2,661 1,053 1,411 175 8,043

IPM - - - 175 -STAPPA - - - - 500-2000

4 Coal 57 773 SCR 90 CUECost 10,041 697 2,046 696 2,942 322 2,973 271 696 

IPM 11,888 479 2,076 696 2,985STAPPA - - - - 1000-2000

SNCR 35 CUECost 1,700 227 456 271 1,684

IPM 2,567 537 882 271 3,259STAPPA - - - - 800-1500

LNB 35 CUECost 2,051 46 322 271 1,189

IPM - - - 271 -STAPPA - - - - 200-1000

NGR 55 CUECost 3,418 2,513 2,973 425 6,993

IPM - - - 425 -

STAPPA - - - - 500-2000

5 Coal 77 1,124 SCR 90 CUECost 11,907 922 2,522 1,012 2,492 391 4,119 394 1,012 

IPM 14,851 676 2,672 1,012 2,640STAPPA - - - - 1000-2000

SNCR 35 CUECost 1,856 288 538 394 1,366

IPM 2,880 787 1,174 394 2,984STAPPA - - - - 800-1500

LNB 35 CUECost 2,494 56 391 394 994

IPM - - - 394 -STAPPA - - - 200-1000

NGR 55 CUECost 3,775 3,611 4,119 618 6,660

IPM - - - 618 -

STAPPA - - - - 500-2000

Plant Total 192 2,799 1,190 11,065 980 2,519 

C-20
Table C-11. Xcel Energy/Bay Front Facility (Wisconsin)

State Facility Unit Fuel

Capacity (MW)

Baseline Emissions (tons)

Control Technology

% Reduction Cost Model

Total Capital Investment [$M2005]

Total O&M Cost [$M2005]

Total Annualized Cost [$M2005]

Emission Reduction (tons)

Cost Effectiveness [$2005/ton]

Lowest Annualized Cost ($M2005)

Highest Annualized Cost ($M2005)

Lowest Emissions Reduced (tons)

WI Xcel Energ1 Coal 22 1,890 LSD 90 CUECost 37,322 2,701 8,291 1,701 4,876 2,953 11,074 1,701 

IPM 13,843 879 2,953 1,701 1,736

STAPPA - - - - 150-4000

LSFO 95 CUECost 51,934 3,294 11,074 1,795 6,169

IPM 27,544 1,146 5,272 1,795 2,937

STAPPA - - - - 200-5000

2 Coal 22 1,890 LSD 90 CUECost 36,222 2,666 8,092 1,701 4,758 2,992 10,865 1,701 

IPM 13,843 919 2,992 1,701 1,760

STAPPA - - - - 150-4000

LSFO 95 CUECost 50,684 3,272 10,865 1,795 6,053

IPM 27,544 1,186 5,312 1,795 2,959

STAPPA - - - - 200-5000

5 Coal 30 1,478 LSD 90 CUECost 36,662 2,553 8,045 1,330 6,047 3,457 10,888 1,330 

IPM 16,182 1,033 3,457 1,330 2,598

STAPPA - - - - 150-4000

LSFO 95 CUECost 51,173 3,222 10,888 1,404 7,753

IPM 30,991 1,348 5,991 1,404 4,266

STAPPA - - - - 200-5000

Plant Total 74 5,257 9,402 32,826 4,731 

State Facility Unit Fuel

Capacity (MW)

Baseline Emissions (tons)

Control Technology

% Reduction Cost Model

Total Capital Investment [$M2005]

Total O&M Cost [$M2005]

Total Annualized Cost [$M2005]

Emission Reduction (tons)

Cost Effectiveness [$2005/ton]

Lowest Annualized Cost ($M2005)

Highest Annualized Cost ($M2005)

Lowest Emissions Reduced (tons)

WI Xcel Energ1 Coal 22 509 SCR 90 CUECost 7,479 443 1,448 458 3,163 173 1,777 178 

IPM 5,932 199 996 458 2,175STAPPA - - - - 1000-2000

SNCR 35 CUECost 1,518 192 396 178 2,223

IPM 1,796 206 447 178 2,510STAPPA - - - - 800-1500

LNB 35 CUECost 1,105 25 173 178 973

IPM - - - 178 -STAPPA - - - - 200-1000

NGR 55 CUECost 2,661 1,419 1,777 280 6,350

IPM - - - 280 -STAPPA - - - - 500-2000

2 Coal 22 447 SCR 90 CUECost 6,757 384 1,292 402 3,213 173 1,777 156 

IPM 5,932 223 1,021 402 2,537STAPPA - - - - 1000-2000

SNCR 35 CUECost 1,437 168 361 156 2,310

IPM 1,796 233 475 156 3,036

STAPPA - - - - 800-1500

LNB 35 CUECost 1,105 25 173 156 1,107

IPM - - - 156 -STAPPA - - - - 200-1000

Costs of SO2 Controls for EGUsCosts of NOx Controls for EGUs

C-21
Table C-11. Xcel Energy/Bay Front Facility (Wisconsin)

State Facility Unit Fuel

Capacity (MW)

Baseline Emissions (tons)

Control Technology

% Reduction Cost Model

Total Capital Investment [$M2005]

Total O&M Cost [$M2005]

Total Annualized Cost [$M2005]

Emission Reduction (tons)

Cost Effectiveness [$2005/ton]

Lowest Annualized Cost ($M2005)

Highest Annualized Cost ($M2005)

Lowest Emissions Reduced (tons)

NGR 55 CUECost 2,661 1,419 1,777 246 7,227

IPM - - - 246 500-2000

STAPPA - - - - 1,285

5 Coal 30 517 SCR 90 CUECost 7,216 411 1,381 466 2,966 212 1,505 181 

IPM 7,439 229 1,229 466 2,640STAPPA - - - - 1000-2000

SNCR 35 CUECost 1,515 188 392 181 2,165

IPM 1,582 419 631 181 3,486STAPPA - - - - 800-1500

LNB 35 CUECost 1,352 30 212 181 1,170

IPM - - - 181 -

STAPPA - - - 181 200-1000

NGR 55 CUECost 2,862 1,120 1,505 285 5,287

IPM - - - 285 -

STAPPA - - - - 500-2000

Plant Total 74 1,473 558 5,058 516 

C-22
Table C-12. Alliant Energy-Wisconsin Power/Edgewater Facility (Wisconsin)

State Facility Unit Fuel

Capacity (MW)

Baseline Emissions (tons)

Control Technology

% Reduction Cost Model

Total Capital Investment [$M2005]

Total O&M Cost [$M2005]

Total Annualized Cost [$M2005]

Emission Reduction (tons)

Cost Effectiveness [$2005/ton]

Lowest Annualized Cost ($M2005)

Highest Annualized Cost ($M2005)

Lowest Emissions Reduced (tons)

Highest Emissions Reduced (tons)

Cost Effecti($2005

WI Alliant Ener3 Coal 75 1,864 LSD 90 CUECost 47,351 5,328 12,421 1,677 7,406 5,955 14,711 1,677 1,770 150-83

IPM 25,747 2,098 5,955 1,677 3,550STAPPA - - - - 150-4000

LSFO 95 CUECost 60,864 5,593 14,711 1,770 8,310

IPM 44,012 2,618 9,211 1,770 5,203STAPPA - - - - 200-5000

4 Coal 334 8,277 LSD 90 CUECost 86,380 17,366 30,306 7,449 4,068 17,153 31,414 7,449 7,863 150-40

IPM 63,174 7,690 17,153 7,449 2,303STAPPA - - - - 150-4000

LSFO 95 CUECost 98,542 16,653 31,414 7,863 3,995

IPM 91,600 8,963 22,684 7,863 2,885STAPPA - - - - 200-5000

5 Coal 422 10,672 LSD 90 CUECost 87,931 13,842 27,014 9,605 2,813 19,892 30,888 9,605 10,138 150-30

IPM 73,892 8,823 19,892 9,605 2,071STAPPA - - - - 150-4000

LSFO 95 CUECost 107,638 14,764 30,888 10,138 3,047

IPM 101,846 10,432 25,689 10,138 2,534STAPPA - - - - 200-5000

Plant Total 831 20,812 43,000 77,013 18,731 19,771 2296-3

State Facility Unit Fuel

Capacity (MW)

Baseline Emissions (tons)

Control Technology

% Reduction Cost Model

Total Capital Investment [$M2005]

Total O&M Cost [$M2005]

Total Annualized Cost [$M2005]

Emission Reduction (tons)

Cost Effectiveness [$2005/ton]

Lowest Annualized Cost ($M2005)

Highest Annualized Cost ($M2005)

Lowest Emissions Reduced (tons)

Highest Emissions Reduced (tons)

Cost Effecti($2005

WI Alliant Ener3 Coal 75 865 SCR 90 CUECost 11,459 844 2,384 779 3,061 497 3,501 303 779 200-73

IPM 14,589 590 2,550 779 3,275STAPPA - - - - 1000-2000

SNCR 35 CUECost 1,815 253 497 303 1,641

IPM 2,337 1,233 1,547 303 5,109STAPPA - - - - 800-1500

LNB 35 CUECost 3,382 76 530 303 1,751

IPM - - - 303 -STAPPA - - - - 200-1000

NGR 55 CUECost 3,743 2,998 3,501 476 7,355

IPM - - - 476 -STAPPA - - - - 500-2000

4 Coal 334 3,285 SCR 90 CUECost 28,738 3,183 7,045 2,957 2,383 1,232 14,090 1,150 2,957 200-77

IPM 43,182 2,370 8,174 2,957 2,764STAPPA - - - - 1000-2000

SNCR 35 CUECost 3,322 785 1,232 1,150 1,071

IPM 4,382 6,012 6,601 1,150 5,741STAPPA - - - - 800-1500

Costs of SO2 Controls for EGUsCosts of NOx Controls for EGUs

C-23
Table C-12. Alliant Energy-Wisconsin Power/Edgewater Facility (Wisconsin)

State Facility Unit Fuel

Capacity (MW)

Baseline Emissions (tons)

Control Technology

% Reduction Cost Model

Total Capital Investment [$M2005]

Total O&M Cost [$M2005]

Total Annualized Cost [$M2005]

Emission Reduction (tons)

Cost Effectiveness [$2005/ton]

Lowest Annualized Cost ($M2005)

Highest Annualized Cost ($M2005)

Lowest Emissions Reduced (tons)

Highest Emissions Reduced (tons)

Cost Effecti($2005

LNB 35 CUECost 8,929 200 1,400 1,150 1,218

IPM - - - 1,150 -STAPPA - - - - 200-1000

NGR 55 CUECost 8,058 13,007 14,090 1,807 7,797

IPM - - - 1,807 -STAPPA - - - - 500-2000

5 Coal 422 1,971 SCR 90 CUECost 33,963 3,698 8,263 1,774 4,659 863 16,789 690 1,774 200-15

IPM 51,214 2,727 9,610 1,774 5,419STAPPA - - - - 1000-2000

SNCR 35 CUECost 3,533 388 863 690 1,251

IPM 5,481 3,792 4,529 690 6,566STAPPA - - - - 800-1500

LNB 35 CUECost 7,536 169 1,182 690 1,713

IPM - - - 690 -STAPPA - - - - 200-1000

NGR 55 CUECost 9,791 15,474 16,789 1,084 15,491

IPM - - - 1,084 -STAPPA - - - - 500-2000

Plant Total 831 6,121 2,592 34,380 2,142 5,509 1210-6

C-24
Table C-13. Alliant Energy-Wisconsin Power/Nelson Dewey Facility (Wisconsin)

State Facility Unit Fuel

Capacity (MW)

Baseline Emissions (tons)

Control Technology

% Reduction Cost Model

Total Capital Investment [$M2005]

Total O&M Cost [$M2005]

Total Annualized Cost [$M2005]

Emission Reduction (tons)

Cost Effectiveness [$2005/ton]

Lowest Annualized Cost ($M2005)

Highest Annualized Cost ($M2005)

Lowest Emissions Reduced (tons)

HEmR(to

WI Alliant Energy/N1 Coal 108 4,206 LSD 90 CUECost 54,250 8,018 16,145 3,786 4,265 8,642 17,324 3,786 3,

IPM 36,950 3,107 8,642 3,786 2,283STAPPA - - - - 150-4000

LSFO 95 CUECost 66,535 7,357 17,324 3,996 4,335

IPM 60,457 3,864 12,921 3,996 3,233STAPPA - - - - 200-5000

2 Coal 111 4,127 LSD 90 CUECost 54,432 7,949 16,103 3,714 4,336 8,738 17,320 3,714 3,

IPM 37,434 3,131 8,738 3,714 2,353STAPPA - - - - 150-4000

LSFO 95 CUECost 66,701 7,328 17,320 3,920 4,418

IPM 61,054 3,898 13,044 3,920 3,327STAPPA - - - - 200-5000

Plant Total 219 8,333 17,381 17,320 7,500 7,

State Facility Unit Fuel

Capacity (MW)

Baseline Emissions (tons)

Control Technology

% Reduction Cost Model

Total Capital Investment [$M2005]

Total O&M Cost [$M2005]

Total Annualized Cost [$M2005]

Emission Reduction (tons)

Cost Effectiveness [$2005/ton]

Lowest Annualized Cost ($M2005)

Highest Annualized Cost ($M2005)

Lowest Emissions Reduced (tons)

HEmR(to

WI Alliant Energy/N1 Coal 108 1,262 SCR 90 CUECost 14,058 1,159 3,049 1,136 2,684 487 4,904 442 1,

IPM 18,912 849 3,391 1,136 2,986STAPPA - - - - 1000-2000

SNCR 35 CUECost 2,033 326 599 442 1,357

IPM 2,716 1,871 2,236 442 5,063STAPPA - - - - 800-1500

LNB 35 CUECost 3,108 70 487 442 1,103

IPM - - - 442 -STAPPA - - - - 200-1000

NGR 55 CUECost 4,294 4,327 4,904 694 7,066

IPM - - - 694 -STAPPA - - - - 500-2000

2 Coal 111 1,238 SCR 90 CUECost 14,135 1,161 3,061 1,114 2,747 496 4,830 433 1,

IPM 19,272 850 3,440 1,114 3,087STAPPA - - - - 1000-2000

SNCR 35 CUECost 2,039 322 596 433 1,375

IPM 2,746 1,871 2,240 433 5,171STAPPA - - - - 800-1500

LNB 35 CUECost 3,163 71 496 433 1,145

IPM - - - 433 -STAPPA - - - - 200-1000

NGR 55 CUECost 4,343 4,246 4,830 681 7,093

IPM - - - 681 -STAPPA - - - - 500-2000

Plant Total 219 2,500 983 9,734 875 2,

Costs of SO2 Controls for EGUsCosts of NOx Controls for EGUs

C-25
Table C-14. Boise Cascade Corporation (Minnesota)

State Facility Unit Fuel

Capacity (MW)

Baseline Emissions (tons)

Control Technology

% Reduction Cost Model

Total Capital Investment [$M2005]

Total O&M Cost [$M2005]

Total Annualized Cost [$M2005]

Emission Reduction (tons)

 CostEffectiveness [$2005/ton]

Lowest Annualized Cost ($M2005)

Highest Annualized Cost ($M2005)

LoweEmisRedu(tons

MI Boise Cascade Corp. 2 Gas 38 48 LSD 90 CUECost 51,688 3,169 10,912 43 254,398 3,966 10,912 43 

IPM 18,130 1,373 4,089 43 95,333Khan (2003)* 17,294 1,376 3,966 43 92,472STAPPA - - - - 1,011

LSFO 95 CUECost 32,346 2,199 7,044 45 155,586

IPM 33,769 1,730 6,789 45 149,938Khan (2003)* 17,294 1,376 3,966 45 87,605STAPPA - - - - 1,011

Plant Total 38 48 3,966 10,912 43 

State Facility Unit Fuel

Capacity (MW)

Baseline Emissions (tons)

Control Technology

% Reduction Cost Model

Total Capital Investment [$M2005]

Total O&M Cost [$M2005]

Total Annualized Cost [$M2005]

Emission Reduction (tons)

 CostEffectiveness [$2005/ton]

Lowest Annualized Cost ($M2005)

Highest Annualized Cost ($M2005)

LoweEmisRedu(tons

MI Boise Cascade Corp. 1 Gas 38 104 SCR 80 CUECost 7,076 398 1,349 84 16,146 120 2,769 37 

IPM 2,768 129 501 84 5,990

Khan (2003)* 2,485 238 572 84 6,847STAPPA - - - - 1,354

SNCR 50 CUECost 1,366 116 299 52 5,733

IPM 1,353 219 401 52 7,678Khan (2003)* 1,307 299 475 52 9,094STAPPA - - - - 2,193

LNB 35 CUECost 2,174 49 341 37 9,322

IPM 1,023 2 139 37 3,805Khan (2003)* 792 61 167 37 4,569STAPPA - - - 424

NGR 61 CUECost 3,041 2,360 2,769 64 43,450

IPM - - - 64 -Khan (2003)* 446 61 120 64 1,891STAPPA - - - - -

Costs of SO2 Controls for ICIsCosts of NOx Controls for ICIs

C-26
Table C-14. Boise Cascade Corporation (Minnesota)

State Facility Unit Fuel

Capacity (MW)

Baseline Emissions (tons)

Control Technology

% Reduction Cost Model

Total Capital Investment [$M2005]

Total O&M Cost [$M2005]

Total Annualized Cost [$M2005]

Emission Reduction (tons)

 CostEffectiveness [$2005/ton]

Lowest Annualized Cost ($M2005)

Highest Annualized Cost ($M2005)

LoweEmisRedu(tons

2 Gas 38 331 SCR 90 CUECost 7,331 421 1,406 265 5,307 169 1,406 116 

IPM 2,749 127 497 265 1,875Khan (2003)* 2,511 241 579 265 2,185STAPPA - - - - 1,354

SNCR 35 CUECost 1,448 159 354 166 2,137

IPM 1,347 217 398 166 2,401Khan (2003)* 1,321 304 482 166 2,908STAPPA - - - - 2,193

LNB 35 CUECost 2,159 48 339 37 9,258

IPM 2 1,016 1,017 37 27,803Khan (2003)* 801 61 169 37 4,623STAPPA - - - 424

3 Gas 35 25 SCR 90 CUECost 6,669 361 1,257 20 62,895 117 1,652 9 

IPM 2,624 97 450 20 22,500Khan (2003)* 2,413 230 554 20 27,716STAPPA - - - - 2,330

SNCR 35 CUECost 1,322 101 279 12 22,303

IPM 1,307 96 271 12 21,728Khan (2003)* 1,269 287 458 12 36,626STAPPA - - - - 3,116

LNB 35 CUECost 2,061 46 323 9 36,942

IPM 1,550 28 236 9 27,018Khan (2003)* 769 58 162 9 18,501STAPPA 797

NGR 61 CUECost 2,975 1,252 1,652 15 108,392

IPM - - - 15 -Khan (2003)* 433 58 117 15 7,648STAPPA - - - - -

Plant Total 76 436 406 5,827 161 

* "Total O&M Costs" for Khan (2003) also includes annual costs (e.g., annual catalyst replacement, fuel costs). For all other models "Total O&M Costs" do not contain any annual costs.

C-27
APC Technology Choices

Suggested Default

Description Units Range Values Boiler 1 Boiler 2 Boiler 3 Boiler 3 Boiler 3

FGD Process Integer 1 or 2 1 1 2 1 21

 (1 = LSFO, 2 = LSD)

Particulate Control Integer 1 or 2 1 1 1 1 11

 (1 = Fabric Filter, 2 = ESP)

NOx Control Integer 1 - 4 1 1 2 1 24

 (1 = SCR, 2 = SNCR, 3 = LNBs, 4 = NGR)

INPUTS

Default

Description Units Range Values Boiler 1 Boiler 2 Boiler 3 Boiler 3 Boiler 3

General Plant Technical Inputs

Location - State Abbrev. All States PA MI MI MI MI MI

MW Equivalent of Flue Gas to Control System MW 100-2000 500 260 355 820 820 820

Net Plant Heat Rate (w/o APC) Btu/kWhr 10,500 13,269 11,243 11,814 11,814 11,814

Plant Capacity Factor % 40-90% 65% 77% 81% 77% 77% 77%

Percent Excess Air in Boiler % 120% 120% 120% 120% 120% 120%

Air Heater Inleakage % 12% 12% 12% 12% 12% 12%

Air Heater Outlet Gas Temperature °F 300 300 300 300 300 300

Inlet Air Temperature °F 80 80 80 80 80 80

Ambient Absolute Pressure In. of Hg 29.4 29.4 29.4 29.4 29.4 29.4

Pressure After Air Heater In. of H2O -12 -12 -12 -12 -12 -12

Moisture in Air lb/lb dry air 0.013 0.013 0.013 0.013 0.013 0.013

Ash Split:

 Fly Ash % 80% 80% 80% 80% 80% 80%

 Bottom Ash % 20% 20% 20% 20% 20% 20%

Seismic Zone Integer 1-5 1 1 1 1 11

Retrofit Factor Integer 1.0-3.0 1.3 1.3 1.3 1.3 1.3 1.3

 (1.0 = new, 1.3 = medium, 1.6 = difficult)

Select Coal Integer 1-8 1 8 8 8 88

Is Selected Coal a Powder River Basin Coal? Yes / No See Column K Yes No No No No No

Coals Available in Library

Coal 1, Wyoming PRB: 8,227 Btu, 0.37% S, 5.32% ash

Coal 2, Armstrong, PA: 13,100 Btu, 2.6% S, 9.1% ash

Coal 3, Jefferson, OH: 11,922 Btu, 3.43% S, 13% ash

Coal 4, Logan, WV: 12,058 Btu, 0.89% S, 16.6% ash

Coal 5, No. 6 Illinois: 10,100 Btu, 4% S, 16% ash

Coal 6, Rosebud, MT: 8,789 Btu, 0.56% S, 8.15% ash

Coal 7, Lignite, ND: 7,500 Btu, 0.94% S, 5.9% ash

Coal 8, "User Specified": 12,062 Btu, 1% S, 16.6% ash

Economic Inputs

Cost Basis -Year Dollars Year 1998 2005 2005 2005 2005 2005

Sevice Life (levelization period) Years 30 15 15 15 15 15

Inflation Rate % 3.00% 3.99% 3.99% 3.99% 3.99% 3.99%

After Tax Discount Rate (current $'s) % 9.20% 9.20% 9.20% 9.20% 9.20% 9.20%

AFDC Rate (current $'s) % 10.80% 10.80% 10.80% 10.80% 10.80% 10.80%

First-year Carrying Charge (current $'s) % 22.30% 14.98% 14.98% 14.98% 14.98% 14.98%

Levelized Carrying Charge (current $'s) % 16.90% 16.90% 16.90% 16.90% 16.90% 16.90%

First-year Carrying Charge (constant $'s) % 15.70% 15.70% 15.70% 15.70% 15.70% 15.70%

Levelized Carrying Charge (constant $'s) % 11.70% 11.70% 11.70% 11.70% 11.70% 11.70%

Sales Tax % 6% 6% 6% 6% 6% 6%

Escalation Rates:

 Consumables (O&M) % 3% 3% 3% 3% 3% 3%

 Capital Costs:

 Is Chem. Eng. Cost Index available? Yes / No Yes Yes Yes Yes Yes Yes

 If "Yes" input cost basis CE Plant Index. Integer 388 468.3 468.3 468.3 468.3 468.3

 If "No" input escalation rate. % 3% 3% 3% 3% 3% 3%

Construction Labor Rate $/hr $35 $32 $32 $32 $32 $32

Prime Contractor's Markup % 3% 3% 3% 3% 3% 3%

Operating Labor Rate $/hr $30 $31 $31 $31 $31 $31

Power Cost Mills/kWh 25 68.3 68.3 68.3 68.3 68.3

Steam Cost $/1000 lbs 3.5 7.44 7.44 7.44 7.44 7.44

Limestone Forced Oxidation (LSFO) Inputs

SO2 Removal Required % 90-98% 95% 95% 95% 95% 95% 95%

L/G Ratio gal / 1000 acf 95-160 125 125 125 125 125 125

Design Scrubber with Dibasic Acid Addition? Integer 1 or 2 2 2 2 2 22

 (1 = yes, 2 = no)

Adiabatic Saturation Temperature °F 100-170 127 127 127 127 127 127

Table C-15. CUECost Example - Input Data for Analysis (JH Campbell, Michigan)

C-28
Table C-15. CUECost Example - Input Data for Analysis (JH Campbell, Michigan)

Reagent Feed Ratio Factor 1.0-2.0 1.05 1.05 1.05 1.05 1.05 1.05

 (Mole CaCO3 / Mole SO2 removed)

Scrubber Slurry Solids Concentration Wt. % 15% 15% 15% 15% 15% 15%

Stacking, Landfill, Wallboard Integer 1,2,3 1 1 1 1 11

 (1 = stacking, 2 = landfill, 3 = wallboard)

Number of Absorbers Integer 1-6 1 1 1 1 11

 (Max. Capacity = 700 MW per absorber)

Absorber Material Integer 1 or 2 1 1 1 1 11

 (1 = alloy, 2 = RLCS)

Absorber Pressure Drop in. H2O 6 6 6 6 66

Reheat Required ? Integer 1 or 2 1 1 1 1 11

 (1 = yes, 2 = no)

Amount of Reheat °F 0-50 25 25 25 25 25 25

Reagent Bulk Storage Days 60 60 60 60 60 60

Reagent Cost (delivered) $/ton $15 $15 $15 $15 $15 $15

Landfill Disposal Cost $/ton $30 $30 $30 $30 $30 $30

Stacking Disposal Cost $/ton $6 $6 $6 $6 $6 $6

Credit for Gypsum Byproduct $/ton $2 $2 $2 $2 $2 $2

Maintenance Factors by Area (% of Installed Cost)

 Reagent Feed % 5% 5% 5% 5% 5% 5%

 SO2 Removal % 5% 5% 5% 5% 5% 5%

 Flue Gas Handling % 5% 5% 5% 5% 5% 5%

 Waste / Byproduct % 5% 5% 5% 5% 5% 5%

 Support Equipment % 5% 5% 5% 5% 5% 5%

Contingency by Area (% of Installed Cost)

 Reagent Feed % 20% 20% 20% 20% 20% 20%

 SO2 Removal % 20% 20% 20% 20% 20% 20%

 Flue Gas Handling % 20% 20% 20% 20% 20% 20%

 Waste / Byproduct % 20% 20% 20% 20% 20% 20%

 Support Equipment % 20% 20% 20% 20% 20% 20%

General Facilities by Area (% of Installed Cost)

 Reagent Feed % 10% 10% 10% 10% 10% 10%

 SO2 Removal % 10% 10% 10% 10% 10% 10%

 Flue Gas Handling % 10% 10% 10% 10% 10% 10%

 Waste / Byproduct % 10% 10% 10% 10% 10% 10%

 Support Equipment % 10% 10% 10% 10% 10% 10%

Engineering Fees by Area (% of Installed Cost)

 Reagent Feed % 10% 10% 10% 10% 10% 10%

 SO2 Removal % 10% 10% 10% 10% 10% 10%

 Flue Gas Handling % 10% 10% 10% 10% 10% 10%

 Waste / Byproduct % 10% 10% 10% 10% 10% 10%

 Support Equipment % 10% 10% 10% 10% 10% 10%

Lime Spray Dryer (LSD) Inputs

SO2 Removal Required % 90-95% 90% 90% 90% 90% 90% 90%

Adiabatic Saturation Temperature °F 100-170 127 127 127 127 127 127

Flue Gas Approach to Saturation °F 10.-50 20 20 20 20 20 20

Spray Dryer Outlet Temperature °F 110-220 147 147 147 147 147 147

Reagent Feed Ratio Factor Calc. Based on %S 0.90 1.04 1.04 1.04 1.04 1.04

 (Mole CaO / Mole Inlet SO2)

Recycle Rate Factor Calculated 30 7.5 7.5 7.5 7.5 7.5

 (lb recycle / lb lime feed)

Recycle Slurry Solids Concentration Wt. % 10-50 35% 35% 35% 35% 35% 35%

Number of Absorbers Integer 1-7 2 2 2 2 22

 (Max. Capacity = 300 MW per spray dryer)

Absorber Material Integer 1 or 2 1 1 1 1 11

 (1 = alloy, 2 = RLCS)

Spray Dryer Pressure Drop in. H2O 5 5 5 5 55

Reagent Bulk Storage Days 60 60 60 60 60 60

Reagent Cost (delivered) $/ton $65 $65 $65 $65 $65 $65

Dry Waste Disposal Cost $/ton $30 $30 $30 $30 $30 $30

Maintenance Factors by Area (% of Installed Cost)

 Reagent Feed % 5% 5% 5% 5% 5% 5%

 SO2 Removal % 5% 5% 5% 5% 5% 5%

 Flue Gas Handling % 5% 5% 5% 5% 5% 5%

 Waste / Byproduct % 5% 5% 5% 5% 5% 5%

 Support Equipment % 5% 5% 5% 5% 5% 5%

Contingency by Area (% of Installed Cost)

 Reagent Feed % 20% 20% 20% 20% 20% 20%

 SO2 Removal % 20% 20% 20% 20% 20% 20%

 Flue Gas Handling % 20% 20% 20% 20% 20% 20%

 Waste / Byproduct % 20% 20% 20% 20% 20% 20%

 Support Equipment % 20% 20% 20% 20% 20% 20%

General Facilities by Area (% of Installed Cost)

 Reagent Feed % 10% 10% 10% 10% 10% 10%

 SO2 Removal % 10% 10% 10% 10% 10% 10%

 Flue Gas Handling % 10% 10% 10% 10% 10% 10%

C-29
Table C-15. CUECost Example - Input Data for Analysis (JH Campbell, Michigan)

 Waste / Byproduct % 10% 10% 10% 10% 10% 10%

 Support Equipment % 10% 10% 10% 10% 10% 10%

Engineering Fees by Area (% of Installed Cost)

 Reagent Feed % 10% 10% 10% 10% 10% 10%

 SO2 Removal % 10% 10% 10% 10% 10% 10%

 Flue Gas Handling % 10% 10% 10% 10% 10% 10%

 Waste / Byproduct % 10% 10% 10% 10% 10% 10%

 Support Equipment % 10% 10% 10% 10% 10% 10%

NOx Control Inputs

Selective Catalytic Reduction (SCR) Inputs

NH3/NOX Stoichiometric Ratio NH3/NOX 0.7-1.0 0.9 D D D DD

NOX Reduction Efficiency Fraction 0.60-0.90 0.70 0.9 0.9 0.9 0.9 0.9

Inlet NOx lbs/MMBtu 0.9 0.27 0.5225 0.3624 0.3624 0.3624

Space Velocity (Calculated if zero) 1/hr 0 D D D DD

Overall Catalyst Life years 2-5 3 D D D DD

Ammonia Cost $/ton 206 D D D DD

Catalyst Cost $/ft3 356 D D D DD

Solid Waste Disposal Cost $/ton 11.48 D D D DD

Maintenance (% of installed cost) % 1.5% D D D DD

Contingency (% of installed cost) % 20% D D D DD

General Facilities (% of installed cost) % 5% D D D DD

Engineering Fees (% of installed cost) % 10% D D D DD

Number of Reactors integer 2 D D D DD

Number of Air Preheaters integer 1 D D D DD

Selective NonCatalytic Reduction (SNCR) Inputs

Reagent integer 1:Urea 2:Ammonia 1 D D D DD

Number of Injector Levels integer 3 D D D DD

Number of Injectors integer 18 D D D DD

Number of Lance Levels integer 0 D D D DD

Number of Lances integer 0 D D D DD

Steam or Air Injection for Ammonia integer 1: Steam, 2: Air 1 D D D DD

NOX Reduction Efficiency fraction 0.30-0.70 0.50 0.35 0.35 0.35 0.35 0.35

Inlet NOx lbs/MMBtu 0.9 0.27 0.5225 0.3624 0.3624 0.3624

NH3/NOX Stoichiometric Ratio NH3/NOX 0.8-2.0 1.2 D D D DD

Urea/NOX Stoichiometric Ratio Urea/NOX 0.8-2.0 1.2 D D D DD

Urea Cost $/ton 225 D D D DD

Ammonia Cost $/ton 206 D D D DD

Water Cost $/1,000 gal 0.4 D D D DD

Maintenance (% of installed cost) % 1.5% D D D DD

Contingency (% of installed cost) % 20% D D D DD

General Facilities (% of installed cost) % 5% D D D DD

Engineering Fees (% of installed cost) % 10% D D D DD

Low NOX Burner Technology Inputs

NOX Reduction Efficiency fraction 0.15-0.60 0.35 D D D DD

Boiler Type T:T-fired, W:Wall T D D D DD

Retrofit Difficulty

L:Low, A:Average, 

H:High A D D D DD

Maintenance Labor (% of installed cost) % 0.8% D D D DD

Maintenance Materials (% of installed cost) % 1.2% D D D DD

Natural Gas Reburning Inputs

NOX Reduction Efficiency fraction 0.55-0.65 0.61 D D D DD

Gas Reburn Fraction fraction 0.08 - 0.20 0.15 D D D DD

Waste Disposal Cost $/ton 11.48 D D D DD

Natural Gas Cost $/MMBtu 2.31 5 5 5 55

Maintenance (% of installed cost) % 1.5% D D D DD

Contingency (% of installed cost) % 20% D D D DD

General Facilities (% of installed cost) % 2% D D D DD

Engineering Fees (% of installed cost) % 10% D D D DD

C-30
Table C-16. CUECost Example - Results Output of Analysis

(JH Campbell facility, Michigan)

SUMMARY OF COSTS

Description Units Boiler 1 Boiler 2

APC Technologies

NOx Control SCR SNCR

Particulate Control PJFF PJFF

SO2 Control LSFO LSD

NOx Control Costs SCR SNCR

Total Capital Requirement (TCR) $ $29,284,539 $3,945,946

$/kW $112.6 $11.1

First Year Costs

 Fixed O&M $ $407,517 $117,261

$/kW-Yr 1.57 0.33

Mills/kWH 0.23 0.05

$/ton NOx removed $109 $66

 Variable O&M $ $2,738,948 $1,306,727

$/kW-Yr 10.53 3.68

Mills/kWH 1.56 0.52

$/ton NOx removed $733 $739

 Fixed Charges $ $4,386,824 $591,103

$/kW-Yr 16.87 1.67

Mills/kWH 2.50 0.23

$/ton NOx removed $1,174 $334

 TOTAL $ $7,533,289 $2,015,091

$/kW-Yr 28.97 5.68

Mills/kWH 4.30 0.80

$/ton NOx removed $2,016 $1,140

Levelized Current Dollars

 Fixed O&M $/kW-Yr 1.91 0.40

Mills/kWH 0.28 0.06

$/ton NOx removed $133 $81

 Variable O&M $/kW-Yr 12.83 4.48

Mills/kWH 1.90 0.63

$/ton NOx removed $893 $900

 Fixed Charges $/kW-Yr 19.03 1.88

Mills/kWH 2.82 0.26

$/ton NOx removed $1,325 $377

 TOTAL $/kW-Yr 33.77 6.76

Mills/kWH 5.01 0.95

$/ton NOx removed $2,350 $1,358

Levelized Constant Dollars

 Fixed O&M $/kW-Yr 1.57 0.33

Mills/kWH 0.23 0.05

$/ton NOx removed $109 $66

 Variable O&M $/kW-Yr 10.53 3.68

Mills/kWH 1.56 0.52

$/ton NOx removed $733 $739

 Fixed Charges $/kW-Yr 13.18 1.30

Mills/kWH 1.86 0.17

$/ton NOx removed $875 $249

 TOTAL $/kW-Yr 25.28 5.31

Mills/kWH 3.66 0.74

$/ton NOx removed $1,717 $1,054

SO2 Control Costs LSFO LSD

Total Capital Requirement (TCR) $ $93,491,840 $83,537,509

$/kW $360 $235

First Year Costs

 Fixed O&M $ $5,268,554 $4,777,549

$/kW-Yr 20.26 13.46

Mills/kWH 3.00 1.90

$/ton SO2 removed $287.8 $226.3

 Variable O&M $ $5,040,781 $9,157,340

$/kW-Yr 19.39 25.80

Mills/kWH 2.87 3.64

$/ton SO2 removed $275.3 $433.8

 Fixed Charges $ $14,005,078 $12,513,919

$/kW-Yr 53.87 35.25

Mills/kWH 7.99 4.97

$/ton SO2 removed $764.9 $592.8

 TOTAL $ $24,314,412 $26,448,808

$/kW-Yr 93.52 74.50

Mills/kWH 13.86 10.50

$/ton SO2 removed $1,328 $1,253

Levelized Current Dollars

 Fixed O&M $/kW-Yr 24.67 16.39

Mills/kWH 3.66 2.31

$/ton SO2 removed $350.4 $275.6

 Variable O&M $/kW-Yr 23.61 31.41

C-31
Table C-16. CUECost Example - Results Output of Analysis

(JH Campbell facility, Michigan)

Mills/kWH 3.50 4.43

$/ton SO2 removed $335.2 $528.2

 Fixed Charges $/kW-Yr 60.77 39.77

Mills/kWH 9.01 5.60

$/ton SO2 removed $863.0 $668.8

 TOTAL $/kW-Yr 109.05 87.56

Mills/kWH 16.17 12.34

$/ton SO2 removed $1,548.6 $1,472.6

Levelized Constant Dollars

 Fixed O&M $/kW-Yr 20.26 13.46

Mills/kWH 3.00 1.90

$/ton SO2 removed $287.8 $226.3

 Variable O&M $/kW-Yr 19.39 25.80

Mills/kWH 2.87 3.64

$/ton SO2 removed $275.3 $433.8

 Fixed Charges $/kW-Yr 42.07 27.53

Mills/kWH 5.95 3.70

$/ton SO2 removed $570.0 $441.8

 TOTAL $/kW-Yr 81.72 66.79

Mills/kWH 11.83 9.23

$/ton SO2 removed $1,133.1 $1,101.9

Due to the detailed nature of CUECost, the resulting cost effectiveness figures will not 

match exactly to what is reported in Section 5.1.6. However, the differences are 

insignificant and well within the +/- 30% range.

C-32
Contents

Table A-1. Summary of Current and Projected Emissions in the for States in the Study

 Region .......................................................... A-1

Table A-2. Estimated Cost of Control for Facilities Subject to BART .................. A-2

Table A-3. Projected Emission Reductions from EGUs as a Result of CAIR and Other

 Existing Regulations ............................................... A-3
EGU

ICI 

boilers

Reciprocating 

engines Turbines

Other 

point

Area 

sources

Onroad 

mobile 

sources

Nonroad 

mobile 

sources

Marine, 

aircraft, 

railroad Total

Michigan 1,103 55 107 71 19 1 1,355

Minnesota 318 23 36 33 19 8 437

Wisconsin 602 149 14 9 13 13 800

3-State Subtotal 2,023 227 156 113 51 21 2,592

Illinois 1,310 161 213 11 31 0 1,725

Indiana 2,499 148 144 158 17 0 2,966

Iowa 412 88 50 2 12 8 571

Missouri 835 28 227 117 12 12 1,231

North Dakota 376 21 22 142 0 3 564

South Dakota 35 1 3 50 0 1 90

9-State Total 7,489 676 813 594 123 44 9,739

Michigan 448 45 44 11 116 49 926 205 114 1,959

Minnesota 271 26 18 6 117 126 455 208 100 1,327

Wisconsin 294 65 8 2 24 32 481 145 79 1,129

3-State Subtotal 1,013 136 71 19 256 208 1,862 557 294 4,416

Illinois 712 101 112 14 129 62 890 324 277 2,622

Indiana 830 105 25 2 106 63 703 178 123 2,133

Iowa 254 45 26 2 39 7 304 174 89 941

Missouri 458 12 21 3 63 64 602 199 133 1,555

North Dakota 196 14 9 1 7 45 75 2 46 395

South Dakota 44 1 0 1 14 14 92 2 8 176

9-State Total 3,507 413 264 42 616 462 4,529 1,437 969 12,239

Michigan 1,093 51 134 68 0 1 1,347

Minnesota 236 22 48 34 4 2 346

Wisconsin 426 142 15 10 0 9 601

3-State Subtotal 1,755 215 196 112 4 11 2,294

Illinois 661 155 94 13 0 0 923

Indiana 1,033 138 152 153 3 0 1,479

Iowa 404 83 74 3 1 2 567

Missouri 770 26 395 120 3 7 1,321

North Dakota 298 20 32 137 4 0 491

South Dakota 33 2 4 51 3 0 94

9-State Total 4,952 641 948 588 19 20 7,168

Michigan 273 43 41 11 133 54 385 94 110 1,145

Minnesota 115 25 18 6 134 136 205 175 54 867

Wisconsin 126 64 7 2 21 35 118 69 57 500

3-State Subtotal 514 132 66 20 287 225 708 338 222 2,512

Illinois 199 96 111 16 121 73 176 154 186 1,131

Indiana 262 100 23 2 101 69 105 141 84 887

Iowa 140 44 25 2 50 9 67 141 47 525

Missouri 213 12 20 3 75 74 119 161 99 777

North Dakota 196 14 8 1 12 50 34 204 24 545

South Dakota 40 1 0 1 22 15 42 148 5 273

9-State Total 1,564 400 254 45 669 515 1,250 1,288 666 6,650

SO2 in 2018

NOX in 2018

Table A-1. Summary of Current and Projected Emissions in the for States in the Study 

Region

Estimated missions (tons/day)

SO2 in 2002

NOX in 2002

A-1
State Source name County SO2 NOX SO2 NOX SO2 NOX SO2 NOX

Minnesota Ipsat Inland (Mittal) St. Louis 155 3,254 a a a a a a

EVTAC-Fairlane (United 

Taconite)

St. Louis 3,222 1,771 a a a a a a

National Steel (USS Keetac) St. Louis 704 6,049 34 a a a a a

Hibbing Taconite St. Louis 593 6,203 0 13 a a a a

USS Minntac St. Louis 1,946 14,924 0 10 a 612 a 705

Northshore Mining^ Lake 2,291 3,649 0 40 a 640 a 1,439

North Dakota Great River Energy – Coal Creek McLean 34,578 11,114 78 30 7,870 420 531 248

Basin Electric Power – Leland 

Olds

Mercer 88,462 16,136 93 44 49,000 9,300 963 1,770

Great River Energy – Stanton Mercer 8,592 2,139 90 26 9,330 1,275 300 504

Minnkota Power – MR Young Oliver b b 84 62 b 18,877 b 1,248

^ The facility proposed additional control as BART only for the power boiler at the facility, not the indurating furnaces. The power boiler is a CAIR unit

Table A-2. Estimated Cost of Control for Facilities Subject to BART*

Cost effectiveness ($/ton)

a The facility proposed that existing controls and operations were BART and therefore cost estimates are not included

b Information not available in facility's BART analysis

* Other State's BART analyses are not listed as they had not yet been completed at the time of this report

Baseline emissions 

(tons/year)

Estimated 

reductions (%)

Total annualized cost 

($1000/year)

A-2
2002 2012 2018 2026 2012 2018 2026

SO2 emissions

Michigan 403 398 399 185 1 1 54

Minnesota 116 86 86 73 26 26 37

Wisconsin 220 153 155 137 31 29 38

3-state total 739 636 641 395 14 13 47

Illinois 478 239 241 214 50 50 55

Indiana 912 462 377 336 49 59 63

Iowa 150 144 147 146 4 2 3

Missouri 305 281 281 224 8 8 27

North Dakota 137 108 109 91 21 21 34

South Dakota 13 12 12 12 5 5 3

Region total 2,734 1,883 1,808 1,418 31 34 48

NOX emissions

Michigan 164 91 100 93 45 39 43

Minnesota 99 41 42 43 58 58 57

Wisconsin 107 44 46 47 59 57 56

3-state total 370 176 188 182 52 49 51

Illinois 260 73 73 68 72 72 74

Indiana 303 141 95 93 54 68 69

Iowa 93 49 51 51 47 45 45

Missouri 167 81 78 75 52 53 55

North Dakota 72 72 72 72 0 0 0

South Dakota 16 15 15 15 9 9 8

Region total 1,280 606 571 556 53 55 57

Table A-3. Projected Emission Reductions from EGUs as a Result of CAIR and 

Other Existing Regulations

Baseline and projected emissions from EGU 

(1000 tons/year) Emission reductions from 2002 (%)

A-3
Appendix B

Potential SO2 and NOX Regional Control

Strategies and Unit-level Control

Technologies
Contents

Table B-1. Control Strategies for Mobile Sources ................................... B-1

Table B-2. Control Strategies for EGUs .......................................... B-5

Table B-3. Control Strategies for ICI Boilers ...................................... B-8

Table B-4. Control Strategies for Reciprocating Engines ............................ B-10

Table B-5. Control Strategies for Turbines ....................................... B-11

Table B-6. Control Strategies for Ammonia ...................................... B-12

Table B-7. References for Control Strategies ..................................... B-17

Table B-8. Notes on Control Strategies .......................................... B-19
Appendix B-1. Control Strategies for Mobile Sources

Technology Processes Covered

Estimated NOX Control 

Efficiency 

 1993 to 1998 MHDDV 24% reduction in tailpipe 

emissions

 1993 to 1998 HHDDV 24% reduction in tailpipe 

emissions

1995 and older enhanced IM tailpipe test

8-9% annual inventory reduction

1996 and newer OBDII equipped 

gasoline vehicles

0.1 gram/mile reduction for post-repair vehicles

1997 and newer OBDII equipped lightduty diesel vehicles 0.6% reduction in tailpipe emissions 

2007 and newer heavy-duty diesel trucks (on the books)

Smoking vehicles (identification, repair, and/or replace)

up to 53% decrease in NOX emissions for all vehicles 

participating in the program

Use 7.0 RVP fuel in urban areas; e.g., Detroit area LDGV Fuel Switching: Biodiesel B100 HDDV +10% pre-1998, +30% 98-04 

increase in tailpipe emissions

Fuel Switching: Biodiesel B20 HDDV +2% pre-1998, +4% 98-04 

increase in tailpipe emissions

Low NOX Calibration/Reflashing. Adopt regulations similar to the CARB Low NOx Software Upgrade program with a set phase in schedule that would require all low NOx rebuild engines to have low NOx rebuild kit installed by 2009.Emissions Inspections Program. Implement a State emissions inspection program for passenger vehicles and heavy duty diesel trucks.Alternative Fuels. Increase use of alternative fuels including biodiesel-petroleum diesel blends, ethanol-gasoline blends, and liquid or compressed (*Recommendation may be restricted to fuels already available in the Petroleum Administration for Defense District.)

B-1
Appendix B-1. Control Strategies for Mobile Sources

Technology Processes Covered

Estimated NOX Control 

Efficiency 

Fuel Switching: Biodiesel B20 Bulldozer, Motor Grader unknown 

Fuel Switching: Biodiesel B30 Bulldozer, Motor Grader unknown Fuel Switching: Biodiesel B20 Locomotive (line haul or switching) +5-6% increase in tailpipe 

emissions

Fuel Switching: Biodiesel B20 Marine Port applications unknown 

Locomotive (line haul or switching) 1-2% reduction in tailpipe 

emissions

Harbor craft 15% inventory reduction 

Large deep draft marine vessels 15% inventory reduction Harbor craft (ferries, tugs) 15% inventory reduction Large deep draft marine vessels 15% inventory reduction 

Increase use of E10 LDGV +5% increase in tailpipe 

emissions

Fuel Switching: Convert public fleets to Flex Fuel Vehicles fueled with E85. LDGV tailpipe control efficiency 

unavailable

Fuel Switching: LNG or CNG LDGV 60% reduction in tailpipe 

emissions

Fuel Switching: LNG Locomotive (line haul or switching) tailpipe control efficiency 

unavailable

Fuel Switching: LNG or CNG MDGV, HDGV 50% reduction in tailpipe 

emissions

1993 to 1998 MHDDV unknown 

Switching locomotives 50% reduction in tailpipe 

emissions

Line-haul locomotives 75% reduction in tailpipe 

emissions

[continued]

Use lower sulfur fuel: CARB Diesel*Use lower sulfur fuel: Highway or ULSD*Anti-Idling. Reduce idling emissions from heavy-duty diesel trucks and locomotives using truck stop electrification and locomotive anti-idling technology.

B-2
Appendix B-1. Control Strategies for Mobile Sources

Technology Processes Covered

Estimated NOX Control 

Efficiency 

Upgrade to 1990 Engine MY 1989 and earlier HDDV 43% reduction 

MY 1989 and earlier HDDV 63% reduction MY 1990 HDDV 33% reduction MY 1991-1997 HDDV 20% reduction MY 1989 and earlier HDDV 78% reduction MY 1990 HDDV 66% reduction MY 1991-1997 HDDV 52% reduction MY 1998-2001 HDDV 95% reduction MY 2002-2006 HDDV 92% reduction 

Upgrade construction and agricultural equipment to Tier 2, 3, or 4 Excavators, Rubber Tire Loaders, 

Crawler Tractors/Dozers, Tractors/Loaders/Backhoes, OffHighway Trucks, Agricultural Tractors, Combines

Dependent on model year and horsepower. See Reference 11 for engine standard schematic.

Fleet turnover to 2007 and newer engines (On the books) HDDV unknown

[continued]

Fleet Modernization (all percentages are reductions in tailpipe emissions). Replace equipment or rebuild engines to meet new engine standards.Upgrade to 2002/4 EngineUpgrade to 2007 EngineUpgrade to 2001/2 Engine

B-3
Appendix B-1. Control Strategies for Mobile Sources

Technology Processes Covered

Estimated NOX Control 

Efficiency 

MY pre-1989 through 2006 HDDV up to 80% reduction 

Excavators, Rubber Tire Loaders, Crawler Tractors/Dozers, Tractors/Loaders/Backhoes, OffHighway Trucks

up to 80% reduction 

Locomotive (line haul or switching) 90% reduction Agricultural Tractors, Combines up to 80% reduction 

Lean NOX Catalyst (LNC) combined with Diesel Particulate Filter (DPF) MY pre-1989 through 2006 HDDV 15-25% reduction 

Excavators, Rubber Tire Loaders, Crawler Tractors/Dozers, Tractors/Loaders/Backhoes, OffHighway Trucks

15-25% reduction 

Agricultural Tractors, Combines 15-25% reduction 

Excavators, Rubber Tire Loaders, Crawler Tractors/Dozers, Tractors/Loaders/Backhoes, OffHighway Trucks

up to 50% reduction 

Agricultural Tractors, Combines up to 50% reduction Excavators, Rubber Tire Loaders, Crawler Tractors/Dozers, Tractors/Loaders/Backhoes, OffHighway Trucks

up to 80% reduction 

Agricultural Tractors, Combines up to 80% reduction Excavators, Rubber Tire Loaders, Crawler Tractors/Dozers, Tractors/Loaders/Backhoes, OffHighway Trucks

up to 80% reduction 

Agricultural Tractors, Combines up to 80% reduction 

[continued]

SCR combined with DPFSelective Catalytic Reduction (SCR)LNCExhaust Gas Recirculation (EGR) combined with DPFDiesel Oxidation Catalyst combined with SCRRetrofit Technology (all percentages are reductions in tailpipe emissions). Install aftertreatment NOX controls on on-road heavy-duty diesel vehiconstruction, cargo-handling, and marine equipment.

B-4
Appendix B-2. Control Strategies for EGUs

Technology Processes Covered Efficiency of Control No

Baseline and On-the-books regional programsBaseline 2002: (MRPO average SO2 is 1.16 lbs/mmBtu, NOx is 0.43 lbs/mmBtu): NSPS; PSD/NSR; State RACT Rules; Title IV SO2 Program 

EGUs MRPO average SO2 is 1.16 

lbs/mmBtu, NOx is 0.43 lbs/mmBtu

bb 

2009 On-the-Books measures: CAIR EGUs EPA CAIR levels are estimated at 

0.13 lbs/mmBtu NOX and 0.26 lbs/mmBtu SO2 in 2015.

bb 

2009 On-the-Books measures: CAIR -- Michigan Impacts EGUs EPA estimates a 10% reduction in 

SO2 and a 29% reduction in NOX from 2003 levels.

bb 

2009 On-the-Books measures: CAIR -- Minnesota Impacts EGUs EPA estimates a 36% reduction in 

SO2 and a 59% reduction in NOX from 2003 levels.

bb 

2009 On-the-Books measures: CAIR -- Wisconsin Impacts EGUs EPA estimates a 32% reduction in 

SO2 and a 61% reduction in NOX from 2003 levels.

bb 

Additional regional programs

Adopt Emission Caps Based on “Retrofit SO2 BACT Level” of 0.15 lbs/mmBtu by 2013 (with Interim Cap Based on 0.36 lbs/mmBtu in 2009)

EGUs Additional 0.11 lbs/mmBtu reduction 

in SO2 from original CAIR emissions cap

v 

Adopt Emission Caps Based on “Retrofit NOx BACT Level” of 0.10 lbs/mmBtu by 2013 (with Interim Cap Based on 0.15 lbs/mmBtu in 2009)

EGUs Additional 0.03 lbs/mmBtu reduction 

in NOX from original CAIR emissions cap

Adopt Emission Caps Based on “SO2 BACT Level for New Plants” of 0.10 lbs/mmBtu by 2013 (with Interim Cap Based on 0.24 lbs/mmBtu in 2009)

EGUs Additional 0.16 lbs/mmBtu reduction 

in SO2 from original CAIR emissions cap

w 

Adopt Emission Caps Based on “NOx BACT Level for New Plants” of 0.07 lbs/mmBtu by 2013 (with Interim Cap Based on 0.12 lbs/mmBtu in 2009)

EGUs Additional 0.06 lbs/mmBtu reduction 

in NOX from original CAIR emissions cap

Replace old boilers to boost efficiency by 50-60% EGUs Not Available Implement Consumer Education programs to promote energy efficiency and reduce demand.

Not Available 

B-5
Appendix B-2. Control Strategies for EGUs

Technology Processes Covered Efficiency of Control No

Fuel Options

Use fuel oil with a sulfur content of 0.05% or less for all boiler sizes (<50 - >250 MmBtu/hr)

#1 and #2 fuel oil 

Use fuel oil with a sulfur content of 0.5% or less #4 and #6 fuel oil Use coal with low sulfur content Coal for units between 50-100 

mmBtu/hr

2.0 lb/MmBtu or 30% SO2 reduction 

Use coal with low sulfur content Coal for units between 100-250 

mmBtu/hr

1.2 lb/MmBtu or 85% SO2 reduction 

Use coal with low sulfur content

Coal for units >250 MmBtu/hr

0.25 lb/MmBtu or 85% SO2 reduction 

Retrofit Technologies for individual emission units

Burner Modifications Most units 10 to 30% NOx reduction Fuel Reburn Most units. Furnace height (residence 

time) may restrict some applications 

20 to 30% NOx reduction for FuelLean Gas Reburning (no OFA), and 30 to 60% reduction for conventional reburning. 

Hydrocarbon-enhanced SNCR Most units. Can use more NH3 with 

less slip. 

 40 to 60% NOx reduction 

Low-NOx Burners Most boilers already have LNB. 30 to 50% NOx reduction 

Overfire Air Most units. Furnace height may restrict 

some applications 

 20 to 40% NOx reduction 

Oxygen-enhanced combustion modification Best applied with new OFA system 

designed to achieve stoichiometric airfuel ratio < 0.8. 

 30-50% beyond OFA 

Rich Reagent Injection Most units. Modeling required to 

determine injection locations. 

 20 to 30% additional NOx reduction 

beyond OFA. 

Selective Catalytic Reduction (SCR) Most units. Space availability may 

constrain some options. High sulfur fuels more challenging

 70 to 90+% NOx reduction 

Selective Non-catalytic Reduction (SNCR) Most units. Residence time and 

temperature characteristics are important

 25 to 50% NOx reduction, depending on the furnace temperature and time for reaction. 

[continued]

B-6
Appendix B-2. Control Strategies for EGUs

Technology Processes Covered Efficiency of Control No

Physical Coal Cleaning Available for all units 10-40% SO2 reduction 

Chemical Coal Cleaning Available for all units 50-85% SO2 reduction 

Switch to Low Sulfur Coal Available for all units 50-80% SO2 reduction Limestone forced oxidation system (LSFO) Generally used for >100 MW units 

units firing high-sulfur (>2 percent) 

bituminous coals. 

 52 – 98% reduction in SO2, with median reduction of 90%; EPA used 95% in CAIR analysis 

Magnesium enhanced lime system (MEL) Generally used for 100-550 MW units 

units firing low-sulfur (<2 percent) 

bituminous, sub-bituminous, and lignite coals. 

 52 – 98% reduction in SO2, with median reduction of 90%; EPA used 96% for CAIR analysis 

Lime spray dryer system (LSD) Can be used for both low-and highsulfur coals, depending on the 

economics of each application. 

 70 - 96% reduction in SO2, with median reduction of 90%; EPA used 90% for CAIR analysis 

Dry or wet FGD Coal-burning units >250 mmBtu/hr 90% SO2 reduction 

Combustion Tuning All units 50-100 mmBtu/hr 5-35% NOX reduction 

[continued]

B-7
Appendix B-3. Control Strategies for ICI Boilers

Technology Processes Covered

Efficiency of Control (% at 

the unit) Note

Baseline and On-the-books re

gional 

pro

grams

Baseline 2002: NSPS; PSD/NSR; State RACT Rules ICI Boilers

N

A

bb 

2009 On-the-Books (OTB) measures: Enforcement settlements and Alcoa announced scrubbers 

ICI Boilers 18% SO2 reduction from 

2002 levels

bb 

2009 OTB measures: NOx SIP Call for large boilers, enforcement settlements 

ICI Boilers 3% NOX reduction from 

2002 levels

bb 

Additional regional 

programs

OTB measures plus 40% SO2 Reduction and 60% Reduction (similar to NOx SIP Call) to All Medium and Large ICI Boilers

ICI Boilers 29% SO2 reduction and 

19% NOX reduction from 2002 levels 

x 

OTB Measures plus Likely Controls to ICI Boilers subject to the proposed BART requirements Emission Reductions. 

ICI Boilers 8% NOX reduction and 

40% SO2 reduction from 2002 levels

y 

OTB Measures plus 90% SO2 Reduction and 80% NOX reduction (similar to BART) to All Medium and Large ICI Boilers Emission Reductions. 

ICI Boilers 66% SO2 reduction and 

31% NOX reduction from 2002 levels

z 

Fuel O

ptions

Use fuel oil with a sulfur content of 0.05% or less for all boiler sizes (<50 - >250 MmBtu/hr)

#1 and #2 fuel oil 

Use fuel oil with a sulfur content of 0.5% or less #4 and #6 fuel oil Use coal with low sulfur content Coal for units between 50-100 

mmBtu/hr

2.0 lb/MmBtu or 30% SO2 reduction

Use coal with low sulfur content Coal for units between 100-250 

mmBtu/hr

1.2 lb/MmBtu or 85% SO2 reduction

Use coal with low sulfur content

Coal for units >250 MmBtu/hr

0.25 lb/MmBtu or 85% SO2 reduction

B-8
Appendix B-3. Control Strategies for ICI Boilers

Technology Processes Covered

Efficiency of Control (% at 

the unit) Note

Retrofit Technolo

gies for individual emission units

LNB (Low NOX Burner) Coal Sub-bituminous fueled boiler 51% NOX reduction 

Coal Sub-bituminous fueled boiler 65% NOX reduction Coal Bituminous fueled boiler 51% NOX reduction Gas fueled boiler 60% NOX reduction Oil fueled boiler 30% NOX reduction 

LNB + OFA + FGR (Flue Gas Recirculation) Gas fueled boiler 80% NOX reduction 

LNB + OFA + FGR (0.5 lbs/mmBtu inlet NOx) Oil fueled boiler 50% NOX reduction 

Coal fueled boiler 80% NOX reduction 

Gas fueled boiler 80% NOX reduction 

Oil fueled boiler 80% NOX reduction 

Coal fueled boiler 40% NOX reduction 

Oil fueled boiler 40% NOX reduction 

Wood/Non-fossil solid fuel not available Gas fueled boiler 40% NOX reduction Coal High Sulfur fueled boiler 40% SO2 reduction Coal Low Sulfur fueled boiler 40% SO2 reduction 

SDA Coal fueled boiler 90% SO2 reduction 

Coal High Sulfur fueled boiler 90% SO2 reduction Coal Low Sulfur fueled boiler 90% SO2 reduction Oil fueled boiler 90% SO2 reduction 

Water Injection Gas fueled boiler 75% NOX reduction 

[continued]

LNB + OFA (Over-fire air)In-duct Dry Sorbent Injection (IDSI) Wet FGD SNCR SCR 

B-9
Control Measure Sources Covered

Estimated Efficiency 

(%) Notes Reference

Low-Emission Combustion Internal Combustion 80-90% reduction 27

Prestratified Charge Internal Combustion 75-90% reduction 27High Energy/Plasma Ignition Systems Internal Combustion 80% reduction cc 27SCONOx Technology Internal Combustion 95% reduction dd 27

NOxTech System Internal Combustion 90-95% reduction 27

High-pressure Fuel Injection Internal Combustion 80% reduction 27Air Fuel w/Ignition Retard Internal Combustion - Gas 53 tons/30% reduction hh 28, 29

Air Fuel w/Ignition Retard IC Engines - Gas 53 tons/30% reduction hh 28, 29Air Fuel Ratio Adjustment Internal Combustion - Gas 36 tons/20% reduction hh 28, 29Air Fuel Ratio Adjustment IC Engines - Gas 38 tons/20% reduction hh 28, 29Ignition Retard IC Engine - Oil 6 tons/25% reduction hh 28, 29Ignition Retard IC Engines - Gas, Diesel, LPG 9 tons/25% reduction hh 28, 29L-E (Low Speed) IC Engine - Gas 148 tons/87% reduction hh 28, 29L-E (Medium Speed) IC Engine - Gas 98 tons/87% reduction hh 28, 29

NSCR IC Engine - Oil 19 tons/90% reduction ee, hh 27, 28, 29NSCR IC Engine - Gas, Diesel, LPG 26 tons/90% reduction ff, hh 27, 28, 29

SCR IC Engine - Gas 150 tons/90% reduction gg, hh 27, 28, 29SCR IC Engine - Gas, Diesel, LPG 23 tons/80% reduction hh 27, 28, 29SCR IC Engine - Oil 17 tons/80% reduction hh 27, 28, 29

Appendix B-4. Control Strategies for Reciprocating Engines

B-10
Control Measure Sources Covered

Estimated Efficiency 

(%) Notes Reference

External Flue Gas Recirculation Turbine N/A ii 30

Overfire Air Turbine N/A 30

Low NOx Burners Turbine 25-50% reduction 30Selective Catalytic Reduction (High Dust) Turbine 70-90% control efficiency ii 30Selective Catalytic Reduction (Low Dust) Turbine 80-90% control efficiency 30Selective Non-Catalytic Reduction Turbine 25-50% control efficiency 30Low Temperature Oxidation (Tri-NOx) Turbine 99% control efficiency 30Low Temperature Oxidation (LoTox) Turbine 80-95% control efficiency 30

Non Selective Catalytic Reduction Turbine N/A ii 30

Novel Multi-Pollutant Controls (ElectroCatalytic Oxidation) Turbine N/A 30

Novel Multi-Pollutant Controls (Pahlman Process)

Turbine N/A ii 30

SCONOx Technology Gas Turbines 95% reduction 27

Dry Low NOx Combuster Combustion Turbines - Natural Gas 102 tons/50% reduction hh 28, 29

Dry Low NOx Combuster Combustion Turbines - Natural Gas 102 tons/84% reduction hh 28, 29SCR w/Low NOx Burner Combustion Turbines - Natural Gas 143 tons/94% reduction hh 28, 29SCR w/Steam Injection Combustion Turbines - Natural Gas 145 tons/95% reduction hh 28, 29SCR w/Water Injection Combustion Turbines - Natural Gas 145 tons/95% reduction hh 28, 29SCR w/Water Injection Combustion Turbines - Oil 31 tons/90% reduction hh 28, 29SCR w/Water Injection Combustion Turbines - Jet Fuel 13 tons/90% reduction hh 28, 29Steam Injection Combustion Turbines - Natural Gas 119 tons/80% reduction hh 28, 29Water Injection Combustion Turbines - Natural Gas 112 tons/76% reduction hh 28, 29Water Injection Combustion Turbines - Oil 23 tons/68% reduction hh 28, 29Water Injection Combustion Turbines - Jet Fuel 10 tons/68% reduction hh 28, 29Dry Low NOx Combuster Combustion Turbines - Natural Gas 102 tons/50% reduction hh 28, 29Dry Low NOx Combuster Combustion Turbines - Natural Gas 102 tons/84% reduction hh 28, 29

Appendix B-5. Control Strategies for Turbines

B-11
Appendix B-6. Control Strategies for Ammonia

Control Measure Sources Covered

Estimated 

Efficiency (%) N

Floor housing s

ystem with stockpiling of manure Storage and handling of 

poultr

y manure (solid) N/A 

Cage housing s

ystem with conve

yor belts Storage and handling of 

poultr

y manure (solid) N/A 

Cage housing s

ystem with dee

p

pits Storage and handling of 

poultr

y manure (solid) N/A 

Lagoons/concrete tanks for storage of poultry manure Storage of poultry manure (storage) N/A Spread manure and incor

porate within 3 da

ys Application of 

poultr

y manure (solid) 36 - 80% reduction jj

Spread manure and incor

porate within 3 da

ys Application of dair

y manure (solid and li

quid) 70% reduction jj

Spread manure and incor

porate within 3 da

ys Application of beef manure (solid and li

quid) 36-70% reduction jj

Spread manure and incor

porate within 3 da

ys Application of swine manure (solid and li

quid) 36-70% reduction jj

Inject manure using tank wagon and incorporate with knives or disks

Application of dairy and beef manure (liquid) N/A 

Above-ground manure storage tanks Storage of dair

y and beef manure (solid and li

quid) N/A 

Walled enclosures to store manure Storage of dair

y and beef manure (solid and li

quid) N/A

m

Outwinter cattle by rotating through pastures to "store" manure in frozen form until it can be used in the spring

Housing cattle (winter) N/A 

Outwinter cattle by keeping them outside in one paddock (sacrifice paddock) to store manure in one location

Housing cattle (winter) N/A 

Com

post manure before applying Treatment of livestock manure (solid and li

quid) N/A 

Daily scraping and hauling of manure for collection and storage

Storage and handling of swine manure (solid) 42-63% reduction jj

Leaving manure to mix with bedding to form manure pac

k

for collection and storage

Storage and handling of swine manure (solid) 33-50% reduction jj

Storing manure in lined 

pit Storage and handling of swine manure (li

quid) jj

Storing manure in above-ground storage facilit

y Storage and handling of swine manure (li

quid) 25-50% reduction jj

Broadcasting manure w/incorporation into soil within 12 hours

Application of swine manure (solid) 80% reduction jj

B-12
Appendix B-6. Control Strategies for Ammonia

Control Measure Sources Covered

Estimated 

Efficiency (%) N

Broadcasting manure w/incorporation into soil within 4 da

ys

Application of swine manure (solid) 40% reduction jj

Injection of manure with sweeps

Application of swine manure (li

quid) 87% reduction jj

Injection of manure with knives Application of swine manure (li

quid) 62% reduction jj

Collection 

ponds to store manure Storage and handling of swine manure (li

quid) N/A 

Deep pits to store manure and minimize gas concentrations

Storage and handling of swine manure (solid) N/A 

Stockpile manure on concrete or cla

y

pad Storage and handling of swine manure (solid) N/A 

System than se

parates li

quid and solid manure Storage and handling of swine manure (solid) N/A 

Com

posting manure Treatment of swine manure (li

quid and solid) N/A 

Anaerobic lagoons and digesters to store and "treat" manure

Treatment of swine manure (liquid and solid) N/A 

Oxidation ditches and aerated lagoons to store and "treat" manure

Treatment of swine manure (liquid and solid) N/A 

Daily scraping and hauling of manure for collection and storage

Storage and handling of poultry manure (solid) 42-63% reduction jj

Leaving manure to mix with bedding to form manure pac

k

for collection and storage

Storage and handling of poultry manure (solid) 33-50% reduction jj

Broadcasting manure w/incorporation into soil within 12 hours

Application of poultry manure (solid) 83% reduction jj

Broadcasting manure w/incorporation into soil within 4 da

ys

Application of poultry manure (solid) 33% reduction jj

[continued]

B-13
Appendix B-6. Control Strategies for Ammonia

Control Measure Sources Covered

Estimated 

Efficiency (%) N

Daily scraping and hauling of manure for collection and storage

Storage and handling of dairy manure (solid) 42-62% reduction jj

Leaving manure to mix with bedding to form manure pac

k

for collection and storage

Storage and handling of dairy manure (solid) 30-50% reduction jj

Storing manure in lined 

pit Storage and handling of dair

y manure (li

quid) 25% reduction jj

Storing manure in above-ground storage facilit

y Storage and handling of dair

y manure (li

quid) 25-50% reduction jj

Broadcasting manure w/incorporation into soil within 12 hours

Application of dairy manure (solid) 75% reduction jj

Broadcasting manure w/incorporation into soil within 4 da

ys

Application of dairy manure (solid) 50% reduction jj

Injection of manure with sweeps

Application of dair

y manure (li

quid) 86% reduction jj

Injection of manure with knives Application of dair

y manure (li

quid) 71% reduction jj

Daily scraping and hauling of manure for collection and storage

Storage and handling of beef manure (solid) 42-63% reduction jj

Leaving manure to mix with bedding to form manure pac

k

for collection and storage

Storage and handling of beef manure (solid) 33-50% reduction jj

Storing manure in lined 

pit Storage and handling of beef manure (li

quid) 25% reduction jj

Storing manure in above-ground storage facilit

y Storage and handling of beef manure (li

quid) 25-50% reduction jj

Broadcasting manure w/incorporation into soil within 12 hours

Application of beef manure (solid) 87% reduction jj

Broadcasting manure w/incorporation into soil within 4 da

ys

Application of beef manure (solid) 50% reduction jj

Injection of manure with sweeps

Application of beef manure (li

quid) 56% reduction jj

Injection of manure with knives Application of beef manure (li

quid) 71% reduction jj

Best Management Practices

N/A 

Manure Storage Covers Storage of livestock manure (solid and li

quid) N/A 

Manure Digesters (Biogas) Handling of livestock manure (solid and li

quid) N/A 

Animal Lot Increased Cleaning N/A Injection of manure into fields

Application of livestock manure (li

quid) N/A 

[continued]

B-14
Appendix B-6. Control Strategies for Ammonia

Control Measure Sources Covered

Estimated 

Efficiency (%) N

Nutrient Management Plans Housing, storage, handling, and application of 

livestock manure (solid and li

quid)

N/A 

Earthen storage Storage of manure (solid and li

quid) N/A 

Cla

y-lined im

poundment Storage of manure (solid and li

quid) N/A 

Geomembrane-lined im

poundment Storage of manure (solid and li

quid) N/A 

Geos

ynthetic cla

y-lined im

poundment Storage of manure (solid and li

quid) N/A 

Concrete-lined im

poundment Storage of manure (solid and li

quid) N/A 

Manure storage structure Storage of manure (solid and li

quid) N/A 

Cla

y-lined im

poundment Storage of manure (solid and li

quid) N/A 

Geomembrane-lined im

poundment Storage of manure (solid and li

quid) N/A 

Geos

ynthetic cla

y-lined im

poundment Storage of manure (solid and li

quid) N/A 

Concrete-lined im

poundment Storage of manure (solid and li

quid) N/A 

Nitrification inhibitor Handling of livestock manure (li

quid) N/A 

Minimize application on frozen or snow-covered ground Application of livestock manure (solid and liquid) N/A Apply manure on crops that can use all of its nutrients Application of livestock manure (solid and liquid) N/A Incorporate or inject manure within 72 hours using urease inhibitor

Application of livestock manure (solid and liquid) N/A 

Cover manure storage structures or use organic matter in 

bedding to form a crust cover

Storage of livestock manure (solid and liquid) N/A 

Divert urine awa

y from feces Handling of livestock manure (solid and li

quid) N/A 

Incor

porate manure

Application of dair

y manure 10% reduction jj

Incor

porate manure

Application of beef manure 10% reduction 

Incor

porate manure

Application of swine manure (solid) 15% reduction 

Incor

porate manure

Application of swine manure (li

quid) 15% reduction 

[continued]

B-15
Appendix B-6. Control Strategies for Ammonia

Control Measure Sources Covered

Estimated 

Efficiency (%) N

Incor

porate manure

Application of 

poultr

y manure 10% reduction 

Incor

porate manure

Application of shee

p manure (solid) 10% reduction 

Incor

porate manure

Application of horse manure (solid) 10% reduction 

Solid and li

quid se

paration s

yste

m Handling of li

quid and solid manure

N/A

Treat waste by mechanical, chemical, or biological means Treatment of livestock manure (solid and liquid) N/A Hopper to transfer manure Handling of li

quid and solid manure

N/A 

Rece

ption structure or tank to transfer manure Handling of li

quid and solid manure

N/A

w

Piston pumps to transfer manure to storage or treatment structure

Handling of liquid and solid manure N/A 

Channels to transfer manure (gravit

y transfer) Handling of li

quid and solid manure

N/A 

Transfer pipes to transfer manure to storage or treatment structure

Handling of liquid and solid manure N/A 

Pi

pelines (gravit

y transfer) Handling of li

quid and solid manure

N/A 

[continued]

B-16
Appendix B-7. References for Control Strategies

1. Chan et al. Emission Reduction Scenarios for Mobile Sources in the LADCO States in 2009 and 2012 . Memorandum to 

Mike Koerber, LADCO, December 5, 2006.

2. “Evaluation of the Effectiveness of Low NOx ECM Reprogramming to In Service Heavy-Duty Vehicles,” UC Riverside 

3. Evaluating Vehicle Emission Inspection and Maintenance Programs . NAS 2001. Executive Summary available online 

at www.mindfully.org/air/vehicle-emissions-inspections-NAS-26jul01.htm

4. Gardetto and Trimble. Evaluation of On Board Diagnostics for Use In Detecting Malfunctioning and High Emitting 

5. Estimates of Emission Reductions from Performing OBDII Tests on 1997 and Newer Light-Duty Diesel Vehicles. 

Prepared for TCEQ by de la Torre Klausmeier Consulting and ERG. August 31, 2005.

6. EPA Heavy-Duty In-Use Emissions Testing Program. Available: http://www.epa.gov/otaq/hd-hwy.htm#inuse

7. A Comprehensive Analysis of Biodiesel Impacts on Exhaust Emissions Draft Technical Report. EPA420-P-02-001 

8. Durbin et al. Evaluation of the Effects of Biodiesel Fuel on Emissions from Heavy-Duty Non-Road Vehicles . Prepared 

9. Fritz, SG. Evaluation of Biodiesel Fuel in an EMD GP38-2 Locomotive . Southwest Research Institute. Prepared for 

10. Port of Seattle (available http://www.portseattle.org/news/press/2005/12_23_2005_36.shtml), Port of Vancouver 

(available http://www.renewableenergyaccess.com/rea/news/story?id=44987)

11. Report of the Biofuels Task Force to the Prime Minister . Australian Biofuels Task Force. August 2005. Available: 

http://www.dpmc.gov.au/biofuels/report/report_full.pdf

12. EPA Renewable Fuels Standard. Available: http://www.epa.gov/otaq/renewablefuels/

13. DOE Alternative Fuels. Available: http://www.eere.energy.gov/afdc/altfuel/gas_benefits.html

14. LNG Short Line Locomotive Project in SCAQMD (PoLA, PoLB short haul; West Coast Collaborative Funding)

15. "Combined ARB and U.S. EPA standards for off-road compression ignition engines." CARB Website: Off-Road 

Equipment (In-Use) Control Measure Documents & Fact Sheets. Available: 

16. "Recommendations for Reducing Emissions from the Legacy Diesel Fleet." Report from the Clean Air Act Advisory 

17. Exhaust Emissions Controls for Diesel Locomotives -- Experiences in Europe.

18. Starcrest Consulting Group, LLC. Evaluation of Low Sulfur Marine Fuel Availability - Pacific Rim. July 2005. Prepared 

19. LADCO EGU White Paper. Available: 

http://www.ladco.org/reports/rpo/Regional%20Air%20Quality/White%20Papers%20March%202006/EGU_Ver4.pdf

20. LADCO ICI Boiler White Paper. Available: 

http://www.ladco.org/reports/rpo/Regional%20Air%20Quality/White%20Papers%20March%202006/ICI_Boilers_Ver4.pdf

21. "Use of Remote Sensors to Identify High Emitters." HB1302 Workgroup Meeting Douglas R. Lawson Denver, CO July 

31, 2006

22. "Multi-Pollutant Strategy Straw Proposal of the State Collaborative To further the Discussion and Narrow the Range of 

Control Level and Dates." Document provided by Mike Koerber on 12/19/2006.

23. "Michigan's Emissions Under CAIR." Available: http://www.epa.gov/cair/mi.html

24. "Minnesota's Emissions Under CAIR." Available: http://www.epa.gov/cair/mn.html

25. "Wisconsin's Emissions Under CAIR." Available: http://www.epa.gov/cair/wi.html

26. "Draft Regional Control Strategy Recommendations." Provided by Mike Koerber on 3/7/2007. Product of the LADCO 

Stationary and Mobile Source Control Strategy Workgroup.

27. "Stationary Reciprocating Internal Combustion Engines: Updated Information on NOx Emissions and Control 

Techniques." Edgerton, S.W., Lee-Greco, J., Walsh, S. September 1, 2000

28. AirControlNET database Version 4.1

29. "AirControlNet Version 4.1 Documentation Report." E.H. Pechan & Associates, Inc. September 2005

30. "Stanton Station Unit 1: Best Available Retrofit Technology Analysis." Great River Energy. August 17, 2006

31. Smith, Rich. 1996. "Poultry Manure Handling - A Practical Approach." Alberta Agriculture, Food and Rural 

Development. http://www1.agric.gov.ab.ca/$department/deptdocs.nsf/all/pou3606

32. Madison, Fred, K. Kelling, L. Massie, L.W. Good. "Guidelines for Applying Manure to Cropland and Pasture in 

Wisconsin." http://learningstore.uwex.edu/Guidelines-for-Applying-Manure-to-Pasture-and-Cropland-in-Wisconsin33. USDA Natural Resources Conservation Service, U. of WI-Madison, WI Dept. of Natural Resources, WI Dept. of 

Agriculture, Trade & Consumer Protection. "Manure Management Choices for Wisconsin Dairy & Beef Cattle Operations." 

34. University of Wisconsin-Madison. 1998. "Outwintering dairy cattle: manure management issues." Research Brief #28. 

http://www.cias.wisc.edu/archives/1998/02/01/outwintering_dairy_cattle_manure_management_issues/index.php

35. University of Wisconsin-Madison. 1999. "Composted manures offer yield and disease resistance benefits." Research 

Brief #45. 

B-17
Appendix B-7. References for Control Strategies

36. Schmitt, Michael, G. Rehum. 1998. "Fertilizing Cropland with Swine Manure." FO-05879-GO. University of Minnesota 

Extension Service http://www.extension.umn.edu/distribution/cropsystems/DC5879.html

37 Jacobson, Larry D., D.R. Schmidt. 1994. "Manure Management Practices for the Minnesota Pork Industry." FO-06456. 

University of Minnesota Extension Service http://www.extension.umn.edu/distribution/livestocksystems/DI6456.html

38. Schmitt, Michael, G. Rehum. 1998. "Fertilizing Cropland with Poultry Manure." FO-05881-GO. University of 

Minnesota Extension Service http://www.extension.umn.edu/distribution/cropsystems/DC5881.html

39. Schmitt, Michael, G. Rehum. 1998. "Fertilizing Cropland with Dairy Manure." FO-05880-GO. University of Minnesota 

Extension Service http://www.extension.umn.edu/distribution/cropsystems/DC5880.html

40. Schmitt, Michael, G. Rehum. 1998. "Fertilizing Cropland with Beef Manure." FO-05882-GO. University of Minnesota 

Extension Service http://www.extension.umn.edu/distribution/cropsystems/DC5882.html

41. Wisconsin Dept. of Agriculture, Trade and Consumer Protection. 2005. "Wisconsin Federal Grant Application Notice." 

http://www.datcp.state.wi.us/arm/agriculture/land-water/odor/pdf/ WI_CIG_application.pdf

42. Natural Resources Conservation Service. 2005. "Waste Storage Facility. Code 313, Conservation Practice Standard." 

electronic Field Office Technical Guide, Wisconsin. http://efotg.nrcs.usda.gov/efotg_locator.aspx?map=WI

43. Natural Resources Conservation Service. 2005. "Nutrient Management. Code 590, Conservation Practice Standard." 

electronic Field Office Technical Guide, Wisconsin. http://efotg.nrcs.usda.gov/efotg_locator.aspx?map=WI

44. Natural Resources Conservation Service. 2005. "Wisconsin Conservation Planning Technical Note WI-1; Companion 

Document to NRCS FOTG Standard 590, Nutrient Management." electronic Field Office Technical Guide, Wisconsin. 

45. Natural Resources Conservation Service. 2005. "Solid/Liquid Waste Separation Facility, Code 632." electronic Field 

Office Technical Guide, Wisconsin. http://efotg.nrcs.usda.gov/efotg_locator.aspx?map=WI

46. Natural Resources Conservation Service. 2005. "Waste Treatment, Code 629." electronic Field Office Technical Guide, 

Wisconsin. http://efotg.nrcs.usda.gov/efotg_locator.aspx?map=WI

47. Natural Resources Conservation Service. 2005. "Amendments for Treatment of Agricultural Waste, Code 591." 

electronic Field Office Technical Guide, Wisconsin. http://efotg.nrcs.usda.gov/efotg_locator.aspx?map=WI

48. Natural Resources Conservation Service. 2005. "Manure Transfer, Code 634." electronic Field Office Technical Guide, 

Wisconsin. http://efotg.nrcs.usda.gov/efotg_locator.aspx?map=WI

[continued]

B-18
Appendix B-8. Notes on Control Strategies

a. Implementation: use existing authorities like anti-tampering compliance authority, pursuing a mandatory program based 

on current draft OTC model rule, or working with engine manufacturers on a voluntary program. 

b. Southeastern Wisconsin already requires tailpipe and OBDII inspections on passenger vehicles. This recommendation 

would expand the program to all of WI, re-start and expand the program in MN, and start a program in MI. Requires 

promulgation of State laws. (Similar measures were also mentioned in ENVIRON's phase I mobile source strategy

c. MOBILE5 estimates a 9% total emission inventory reduction with a fully implemented enhanced IM program. However, 

a NAS report in 2001 found that this may be an overestimation. The ENVIRON Phase I mobile source control measures 

report estimates an 8% NOX reduction in 2007 if all states in the LADCO region fully implemented an IM and OBD 

d. Co-benefits of this strategy are significant. PM, HC, and CO are reduced by 48, 48, and 68% respectively. Cetane 

e. Co-benefits of this strategy are significant. PM, HC, and CO are reduced by 10, 21, and 11% respectively. 98% of 

vehicles in this study are pre-1998. Cetane additives may decrease NOX emissions.

f. Opacity reduced 2-6% when switching from regular diesel to B20

g. Opacity reduced 5-11% when switching from regular diesel to B30

h. This test did not demonstrate PM or HC reductions using B20 or CARB diesel.

i. Emission benefits are not readily available for most nonroad applications. However, biodiesel is being used for 

j. 1% NOX reduction for line-haul locomotives, 2% for switching.

k. Based on Port of Los Angeles Emissions Inventory. Percentage may differ for LADCO region.

l. Co-benefits include reductions in PM, CO, and greenhouse gases. Low blends of ethanol demonstrate a slight increase in 

VOC cold-start emissions when compared to regular gasoline.

m. ENVIRON report assumes 15% participation in 2009 and 30% participation of HDDV anti-idling measures by 2012. 

The report also assumes 25% and 50% of switching and linehaul locomotives respectively. 

n. Calculation of percentage NOX control efficiency would require knowledge of the percentage of time a truck would 

participate in anti-idling programs. It is assumed that 100% of NOX would be reduced during the anti-idling time.

o. Control efficiency was cited from the ENVIRON Phase II report.

p. Control efficiencies were calculated based on the g/bhp-hr engine standard of the upgraded engine vs. the old engine.

q. Also demonstrates 10-30% PM reduction

r. ENVIRON Phase II report analyzes emission reductions and cost-effectiveness of LNC combined with DPF, resulting in 

PM reduction co-benefits and combined costs results. 

s. ENVIRON Phase II report analyzes emission reductions and cost-effectiveness of EGR combined with DPF, resulting in 

PM, VOC, and CO reduction co-benefits and combined costs results. 

t. ENVIRON Phase II report analyzes emission reductions and cost-effectiveness of SCR combined with DOC, resulting in 

PM, VOC, and CO reduction co-benefits and combined costs results. 

u. ENVIRON Phase II report analyzes emission reductions and cost-effectiveness of SCR combined with DPF, resulting in 

PM, VOC, and CO reduction co-benefits and combined costs results. 

v. Candidate measure ID EGU1

w. Candidate measure ID EGU2

x. Candidate measure ID ICI1. Timing of Implementation : Assumes full reductions achieved in 2009. Implementation 

y. Candidate measure ID ICI2. Timing of Implementation : Assumes full reductions achieved in 2013 Implementation Area : 

z. Candidate measure ID ICI3. Timing of Implementation : Assumes full reductions achieved in 2009 Implementation Area : 

aa. Applies to CO, HC (and toxics), PM, and somewhat for NOx, probably for nontailpipe HCs. Fresno Study referenced in 

Doug Lawson's presentation cited a 53% reduction in NOX, 65% in HC, and 94% in CO.

bb. Baseline and on-the-way measures are listed here as additional information that was provided by the LADCO white 

papers. We will include discussion on these existing or upcoming measures for all source categories in our final report.

B-19
Appendix B-8. Notes on Control Strategies

cc. used only on lean burn, natural gas spark ignited engines

dd. natural gas- and diesel-fired

ee. source 27 states 95% efficiency for rich-burn spark ignited engines

ff. source 27 states 95% efficiency for rich-burn spark ignited engines

gg. source 27 states 90% efficiency for internal combustion sources

hh. AirControlNET provided information on control technologies from multiple pollution sources; the reduction in tons listed 

under "Efficiency Estimate (%)" is an average of all the sources for a particular technology

ii. high cost

jj. Efficiency calculations are based on estimates of atmospheric losses, assuming a consistent distribution of losses among 

ammonia and other gases (N2O and N2)

kk. Baseline is spreading manure without incorporation

ll. Costly, even with cost-sharing, average price is $1000/cow

mm. Moderate to high cost

nn. Baseline is open ground storage (leaving manure on ground with no method of collection or storage)

oo. Baseline is earthen ground storage (leaving manure on ground with no method of collection or storage)

pp. Baseline is broadcasting manure with no waiting time before incorporation

qq. no particular strategy is described as "best practice" but State offers technical specifications for structures to meet 

standard, e.g., storage volume, depth, how much stress can be placed on the structure depending on the material

ss. the inhibitor works on ammonium forms of nitrogen; it is recommended to use this technique in the late summer or fall; 

reference also recommends timings of manure application (specific soil temperatures)

tt. reference broke out nutrient availability among indoor pit, outdoor pit, and farrow-nursery indoor pit storage options; all 

uu. reference broke out nutrient availability among duck, chicken, turkey, and poultry manure; all had same nutrient 

vv. reference provides efficiency in capturing solids from waste stream

ww. reference provides technical specifications for dimensions and distances from water sources

xx. reference provides material components and technical specifications for transfer mechanism

[continued]

B-20
Appendix C

EGU Control Analysis Parameters and

Individual EGU and ICI Boiler

Facility Analyses 
Contents

C.1. Cost Equations and Control Efficiencies for EGU .............................. C-1

C.2. Individual Facility Analysis ................................................ C-1

C.3. Example of a CUECost Individual Facility Spreadsheet ......................... C-2

References ................................................................. C-3

Tables

Table C-1. IPM Cost Equation Parameters Used for EGU Control Strategy Analyses ....... C-4

Table C-2. Emission Control Efficiencies Used for EGU Control Strategy Analyses ....... C-5

Table C-3. Detroit Edison/St. Clair-Belle River Facility (Michigan) .................... C-6

Table C-4. Consumers Energy Company/JH Campbell Facility (Michigan) .............. C-9

Table C-5. Wisconsin Electric/Presque Isle Facility (Michigan) ....................... C-11

Table C-6. Wisconsin Power and Light/Clay Boswell Facility (Minnesota) .............. C-14

Table C-7. Minnesota Power and Light/Syl Laskin Facility (Minnesota) ................ C-15

Table C-8. Northshore Mining Company/Silver Bay Facility (Minnesota) ............... C-16

Table C-9. Virginia Public Utilities Commission Facility (Minnesota) ................. C-17

Table C-10. Dairyland Power Coop/Alma Facility (Wisconsin) ....................... C-19

Table C-11. Xcel Energy/Bay Front Facility (Wisconsin) ............................ C-21

Table C-12. Alliant Energy-Wisconsin Power/Edgewater Facility (Wisconsin) ........... C-23

Table C-13. Alliant Energy-Wisconsin Power/Nelson Dewey Facility (Wisconsin) ....... C-25

Table C-14. Boise Cascade Corporation (Minnesota) ............................... C-26

Table C-15. CUECost Example - Input Data for Analysis (JH Campbell, Michigan) ...... C-28

Table C-16. CUECost Example - Results Output of Analysis

 (JH Campbell facility, Michigan) .................................... C-31
a

The ICI Workgroup recommendation and the Candidate Measure ID ICI1 control strategies discussed in

section 5.2 are used in this facility analysis. The Workgroup recommendation results in a regional cap for SO2

emissions of 1.2 lb/mmBtu (a 77% rollback of emissions for either the 3-state or 9-state region). When conducting

the facility analysis of an ICI boiler (Boise Cascade Corporation/International Falls in Minnesota) we found only one

unit at the facility emitted SO2. The remaining units all burned natural gas and so had negligible SO2 emissions.

According to Boise's 2005 permit, the SO2 emissions from Unit 2 amount to .1 lb/mmBtu, well below the regional

emissions caps. Therefore, this facility would not be controlled under this rule for SO2

, and further cost analysis for

ICI1 was not necessary. Analyses were conducted for ICI1 NOX, and the Workgroup recommendation for both NOX

and SO2.

C-1

C.1 Cost Equations and Control Efficiencies for EGU

Costs for regional EGU control strategies were analyzed using cost equations developed

for the Integrated Planning Model (IPM).1 The IPM model is commonly used to estimate the

costs of large-scale pollution control programs. The cost equation parameters are shown in

Table C-1. Control efficiencies used in the EGU regional strategy analyses are shown in

Table C-2.

C.2 EGU and ICI Boiler Individual Facility Analyses

Eleven electric generating facilities were selected for more in-depth analyses. The

analyses of these facilities were designed to ensure that opportunities for cost-effective visibility

improvements were not overlooked. None of these facilities are required to completed BART

analyses nor are they expected to reduce emissions pursuant to CAIR. Each of these facilities

includes multiple boilers, totaling 35 individual boilers that were analyzed. For these plantspecific analyses we estimated costs using the IPM cost equations,3

 and also drew on a number of

additional data sources, including a Menu of Options for controlling PM2.5 and its precursors by

the National Association of Clean Air Agencies (NACAA, formerly STAPPA and ALAPCO)2

and the Coal Utility Environmental Cost (CUECost) worksheet.3 For ICIs smaller than 100

MW, an ICI boiler cost estimation methodology developed by EPA was used.4,5

Tables C-1 through C-11 present detailed estimates of capital and annualized costs for

each individual unit, emissions reductions, and cost effectiveness for each control technology. 

The control technologies were selected to achieve the either the EGU1 cap or both the EGU1 and

EGU2 caps. Table C-12 is the analysis for an ICI boiler at Boise Cascade Corporation.a In this

case, the control technologies meet both the ICI1 rule and the ICI Workgroup recommendation.

It must be noted that the reported results are estimates. In fact, control cost estimates can

vary by at a factor of 2 or more. There are a number of reasons for this range of cost estimates.

First, all of the costing approaches rely on default assumptions for flue gas conditions, and for

retrofit costs and other contingency costs. These assumptions may differ from model to model. 

In addition, the cost equations have been developed for different base years, and use different

inflation factors to project costs to subsequent years. The CueCost and IPM models also use
C-2

different scaling factors to calculate costs for various boiler sizes. The NACAA report only

provides cost effectiveness values for broad boiler size ranges. 

C.3 Example CUECOST Individual Facility Input Spreadsheet

CUECost is a set of interrelated Excel spreadsheets that focus on costs for coal-fired

power plants. In the CUECost spreadsheets, the user has the ability to change all the parameters

to suit the facility under analysis. A sensitivity analysis of CUECost conducted by EPA has

shown that the following variables have significant impacts on the cost results (greater than 5%):6

• Unit capacity

• Heat rate

• Coal sulfur content

• Coal heating value

• Capacity factor

• Disposal mode

Unit capacities and heat rates for individual EGUs were obtained from the NEEDS database, and

capacity factors for 2018 were calculated based on the IPM unit-specific fuel consumption

estimates. Fuel sulfur contents were obtained from operating permits, where possible, or

calculated from SO2 emission rates reported in the NEI database. We assumed that the disposal

mode for sludge and ash will be landfilling. It must be noted that the results are ball-park

figures; default values were used when plant-specific information required by CUECost was not

available in the operating permits.

Tables C-17 and C-18 show an example of an individual facility analysis with the

CUECost program. Table C-20 shows the inputs for the program, and Table C-21 presents the

results. This example is from the JH Campbell facility in Michigan, which has three units

(Boilers 1, 2 and 3). Plant-specific information was used in the highlighted rows (the same type

of information was available for all other facilities as well). CUECost allows the user to specify

the type of coal being used at the facility, either choosing from its coal library or, if the coal is not

found in the library, input the coal characteristics for more accurate results. We often exercised

the latter option in our analyses. In this example Boiler 3 uses a different coal than Boilers 1

and 2. In cases like this, two separate analyses were conducted (i.e., two separate spreadsheets

were used): one for the boilers using coal type A and a second for boilers using coal type B.
C-3

1. Documentation for EPA Base Case 2006 V3.0. Using the Integrated Planning Model –

Chapter 5: Emission Control Technologies. U.S. Environmental Protection Agency,

Washington, D.C. November 2006. www.epa.gov/AIRMARKET/progsregs/epa-ipm/

2. STAPPA and ALAPCO (now NACAA). 2006. “Controlling Fine Particulate Matter

Under the Clean Air Act: A Menu of Options.” 

3. Keeth, R., R. Blagg, C. Burklin, B. Kosmicki, D. Rhodes, T. Waddell. Coal Utility

Environmental Cost (CUECost) Workbook User's Manual, Version 1.0.

4. Khan, S. 2003. Methodology, Assumptions, and References - Preliminary NOx Controls

Cost Estimates for Industrial Boilers. EPA-HQ-OAR-2003-0053-170.

5. Khan, S. 2003. Methodology, Assumptions, and References - Preliminary SO2 Controls

Cost Estimates for Industrial Boilers. EPA-HQ-OAR-2003-0053-166.

6. Srivastava, R.K. 2000. “Controlling SO2 Emissions: A Review of Technologies.”

EPA/600/R-00/093. U.S. Environmental Protection Agency, Washington, D.C.

References for Appendix C
Control technology Fuel and boiler type

Base value 

($/kW)

Scale 

factor Expon-ent

Base value 

($/kW-yr) Scale factor Expon-ent

B

(c

<100 MW 511.1 100 0.62 20.75 100 0.47 

100-300 MW 251.2 300 0.62 12.01 300 0.39 

300-500 MW 190.0 500 0.55 9.83 500 0.35 

500-700 MW 155.1 700 0.60 8.74 700 0.37 >700 MW 131.0 1,000 0.47 7.64 1,000 0.37 <100 MW 312.3 100 0.50 14.20 100 0.47 100-300 MW 169.3 300 0.33 8.74 300 0.56 300-500 MW 143.1 500 0.31 6.55 500 0.54 500-700 MW 128.9 700 0.15 5.46 700 0.63 >700 MW 122.3 1,000 0.15 4.37 1,000 0.63 

SCR Coal 133.8 243 0.27 0.89 243 0.27 

Oil / gas 38.6 200 0.35 1.19 200 0.35 

SNCR Coal, pulverized, term 1** 22.9 200 0.58 0.34 200 0.58 

Coal, pulverized, term 2** 26.1 100 0.68 0.40 100 0.68 Coal, cyclone 13.2 300 0.58 0.19 300 0.58 Coal, fluidized bed 22.9 200 0.58 0.35 200 0.58 Oil / gas 13.0 200 0.58 0.20 200 0.58 

LNB without OFA Coal, wall-fired 23.1 300 0.36 0.35 300 0.36 LNB with OFA Coal, wall-fired 31.3 300 0.36 0.48 300 0.36 LNB with close-coupled OFA Coal, tangential 12.2 300 0.36 0.02 300 0.36 LNB with separated OFA Coal, tangential 17.0 300 0.36 0.25 300 0.36 LNB with close-coupled and separated OFA

Coal, tangential 19.4 300 0.36 0.30 300 0.36 <100 MW 511.1 100 0.62 20.75 100 0.47 100-300 MW 251.2 300 0.62 12.01 300 0.39 300-500 MW 190.0 500 0.55 9.83 500 0.35 500-700 MW 155.1 700 0.60 8.74 700 0.37 >700 MW 131.0 1,000 0.47 7.64 1,000 0.37 <100 MW 312.3 100 0.50 14.20 100 0.47 100-300 MW 169.3 300 0.33 8.74 300 0.56 300-500 MW 143.1 500 0.31 6.55 500 0.54 500-700 MW 128.9 700 0.15 5.46 700 0.63 >700 MW 122.3 1,000 0.15 4.37 1,000 0.63 

Source: Reference 1

NOX Controls

Lime spray dryer scrubberLimestone forced oxidation scrubber* Cost equations take the following form: Cost = (Base value) x (Scale Factor/MW)^(exponent)

where "Base value," "Scale factor," and "exponent" are terms defined in the table, and MW is the capacity of the boiler

**For SNCR applied to pulverized coal, terms 1 and 2 are added together.

Table C-1. IPM Cost Equation Parameters Used for EGU Control Strategy Analyses

SO2 Controls

Capital cost factors*

Fixed operating and maintenance 

scaling factors*

Var

Limestone forced oxidation scrubberLime spray dryer scrubber

C-4
Control technology Fuel and boiler type

Estiamated 

control 

efficiency (%)

SO2 control measures

Limestone forced oxidation scrubber Coal /oil 95

Lime spray dryer scrubber Coal /oil 90

NOX control measures

SCR Coal 90

Oil / gas 80

SNCR Coal, pulverized or cyclone 35

Coal, fluidized bed 50

Oil / gas 50

LNB without OFA Coal, wall-fired 35

LNB with OFA Coal, wall-fired 40

LNB with close-coupled OFA Coal, tangential 40

LNB with separated OFA Coal, tangential 45

LNB with close-coupled and separated OFA Coal, tangential 50

Table C-2. Emission Control Efficiencies Used for EGU Control Strategy 

Analyses

C-5
Table C-3. Estimated Cost and Cost Effectiveness for EGU1 and EGU2 Control Strategies for t

Detroit Edison/St. Clair-Belle River Facility (Michigan)

State Facility Unit Fuel

Capacity (MW)

Baseline Emissions (tons)

Control Technology

% Reduction Cost Model

Total Capital Investment [$M2005]

Total O&M Cost [$M2005]

Total Annualized Cost [$M2005]

Emission Reduction (tons)

Cost Effectiveness [$2005/ton]

Lowest Annualized Cost ($M2005)

Highest Annualized Cost ($M2005)

Lowest Emissions Reduced (tons)

HiEmRe(to

MI

St. Clair/ Belle River 1 Coal 153 5,491 LSD 90 CUECost 54,602 6,604 14,783 4,942 2,991 10,628 18,012 4,942 5,2

IPM 44,092 4,023 10,628 4,942 2,151STAPPA - - - - 150-4000

LSFO 95 CUECost 71,543 7,295 18,012 5,216 3,453

IPM 69,090 4,938 15,288 5,216 2,931STAPPA - - - - 200-5000

2 Coal 162 6,162 LSD 90 CUECost 59,169 7,156 16,020 5,546 2,888 11,009 19,257 4,942 5,2

IPM 45,379 4,211 11,009 5,546 1,985STAPPA - - - - 150-4000

LSFO 95 CUECost 76,687 7,769 19,257 5,854 3,289

IPM 70,608 5,155 15,732 5,854 2,687STAPPA - - - - 200-5000

3 Coal 171 6,132 LSD 90 CUECost 58,567 7,149 15,923 5,519 2,885 11,425 19,263 4,942 5,8

IPM 46,631 4,440 11,425 5,519 2,070STAPPA - - - - 150-4000

LSFO 95 CUECost 76,094 7,864 19,263 5,825 3,307

IPM 72,074 5,412 16,209 5,825 2,783STAPPA - - - - 200-5000

4 Coal 158 5,734 LSD 90 CUECost 56,209 6,840 15,260 5,160 2,957 10,774 18,434 4,942 5,4

IPM 44,811 4,061 10,774 5,160 2,088STAPPA - - - - 150-4000

LSFO 95 CUECost 73,110 7,482 18,434 5,447 3,384

IPM 69,940 4,992 15,469 5,447 2,840STAPPA - - - - 200-5000

6 Coal 321 11,765 LSD 90 CUECost 75,056 10,823 22,066 10,588 2,084 16,444 25,653 4,942 11

IPM 61,545 7,224 16,444 10,588 1,553STAPPA - - - - 150-4000

LSFO 95 CUECost 92,898 11,737 25,653 11,176 2,295

IPM 89,995 8,446 21,928 11,176 1,962STAPPA - - - - 200-5000

7 Coal 450 11,765 LSD 90 CUECost 90,888 15,164 28,779 10,588 2,718 21,036 32,737 4,942 11

IPM 77,195 9,472 21,036 10,588 1,987STAPPA - - - - 150-4000

LSFO 95 CUECost 111,146 16,088 32,737 11,176 2,929

IPM 104,903 11,187 26,902 11,176 2,407STAPPA - - - - 200-5000

Plant Total 1,415 47,048 77,147 133,356 42,344 44

State Facility Unit Fuel

Capacity (MW)

Baseline Emissions (tons)

Control Technology

% Reduction Cost Model

Total Capital Investment [$M2005]

Total O&M Cost [$M2005]

Total Annualized Cost [$M2005]

Emission Reduction (tons)

Cost Effectiveness [$2005/ton]

Lowest Annualized Cost ($M2005)

Highest Annualized Cost ($M2005)

Lowest Emissions Reduced (tons)

HiEmRe(to

MI

St. Clair/ Belle River 1 Coal 153 1,071 SCR 90 CUECost 15,493 1,520 3,602 963 3,739 599 6,764 375 96

IPM 24,436 1,143 4,428 963 4,596STAPPA - - - - 1000-2000

Costs of SO2 Controls for EGUsCosts of NOx Controls for EGUs

C-6
Table C-3. Estimated Cost and Cost Effectiveness for EGU1 and EGU2 Control Strategies for t

Detroit Edison/St. Clair-Belle River Facility (Michigan)

State Facility Unit Fuel

Capacity (MW)

Baseline Emissions (tons)

Control Technology

% Reduction Cost Model

Total Capital Investment [$M2005]

Total O&M Cost [$M2005]

Total Annualized Cost [$M2005]

Emission Reduction (tons)

Cost Effectiveness [$2005/ton]

Lowest Annualized Cost ($M2005)

Highest Annualized Cost ($M2005)

Lowest Emissions Reduced (tons)

HiEmRe(to

SNCR 35 CUECost 2,219 301 599 375 1,600

IPM 3,727 1,420 1,921 375 5,126STAPPA - - - - 800-1500

LNB 35 CUECost 5,375 120 843 375 2,250

IPM 4,741 155 792 375 2,114STAPPA - - - - 200-1000

NGR 55 CUECost 5,006 6,091 6,764 589 11,488

IPM - - - 589 -STAPPA - - - - 500-2000

2 Coal 162 1,693 SCR 90 CUECost 17,433 1,736 4,079 1,524 2,677 744 7,595 593 1,5

IPM 25,477 1,207 4,631 1,524 3,039STAPPA - - - - 1000-2000

SNCR 35 CUECost 2,479 411 744 593 1,255

IPM 3,809 1,508 2,020 593 3,409STAPPA - - - - 800-1500

LNB 35 CUECost 5,579 125 875 593 1,476

IPM - - - 593 -STAPPA - - - - 200-1000

NGR 55 CUECost 5,339 6,878 7,595 931 8,156

IPM - - - 931 -STAPPA - - - - 500-2000

3 Coal 171 1,195 SCR 90 CUECost 16,866 1,651 3,918 1,076 3,641 638 7,505 418 1,0

IPM 26,503 1,291 4,853 1,076 4,510STAPPA - - - - 1000-2000

SNCR 35 CUECost 2,376 319 638 418 1,525

IPM 3,888 1,627 2,149 418 5,137STAPPA - - - - 800-1500

LNB 35 CUECost 5,778 129 906 418 2,166

IPM - - - 418 -STAPPA - - - - 200-1000

NGR 55 CUECost 5,485 6,767 7,505 657 11,414

IPM - - - 657 -STAPPA - - - - 500-2000

4 Coal 158 1,118 SCR 90 CUECost 16,244 1,616 3,799 1,006 3,776 609 7,079 391 1,0

IPM 25,017 1,145 4,507 1,006 4,480STAPPA - - - - 1000-2000

SNCR 35 CUECost 2,276 303 609 391 1,556

IPM 3,773 1,422 1,929 391 4,931STAPPA - - - - 800-1500

LNB 35 CUECost 5,489 123 861 391 2,200

IPM 4,840 157 807 391 2,063STAPPA - - - - 200-1000

NGR 55 CUECost 5,083 6,396 7,079 615 11,514

IPM - - - 615 -STAPPA - - - - 500-2000

C-7
Table C-3. Estimated Cost and Cost Effectiveness for EGU1 and EGU2 Control Strategies for t

Detroit Edison/St. Clair-Belle River Facility (Michigan)

State Facility Unit Fuel

Capacity (MW)

Baseline Emissions (tons)

Control Technology

% Reduction Cost Model

Total Capital Investment [$M2005]

Total O&M Cost [$M2005]

Total Annualized Cost [$M2005]

Emission Reduction (tons)

Cost Effectiveness [$2005/ton]

Lowest Annualized Cost ($M2005)

Highest Annualized Cost ($M2005)

Lowest Emissions Reduced (tons)

HiEmRe(to

6 Coal 321 1,766 SCR 90 CUECost 25,234 2,886 6,278 1,589 3,950 846 13,028 618 1,5

IPM 41,972 2,180 7,821 1,589 4,921STAPPA - - - - 1000-2000

SNCR 35 CUECost 3,070 433 846 618 1,369

IPM 4,939 2,942 3,606 618 5,834STAPPA - - - - 800-1500

LNB 35 CUECost 8,701 195 1,364 618 2,207

IPM - - - 618 -STAPPA - - - - 200-1000

NGR 55 CUECost 7,844 11,974 13,028 971 13,414

IPM - - - 971 -STAPPA - - - - 500-2000

7 Coal 450 1,766 SCR 90 CUECost 33,526 4,143 8,648 1,589 5,442 1,214 10,190 618 1,5

IPM 53,710 2,972 10,190 1,589 6,412STAPPA - - - - 1000-2000

SNCR 35 CUECost 3,891 691 1,214 618 1,964

IPM 5,619 4,177 4,932 618 7,980STAPPA - - - - 800-1500

Plant Total 1,415 8,609 4,649 51,639 3,013 7,7

C-8
Table C-4. Consumers Energy Company/JH Campbell Facility (Michigan)

State Facility Unit Fuel

Capacity (MW)

Baseline Emissions (tons)

Control Technology

% Reduction Cost Model

Total Capital Investment [$M2005]

Total O&M Cost [$M2005]

Total Annualized Cost [$M2005]

Emission Reduction (tons)

Cost Effectiveness [$2005/ton]

Lowest Annualized Cost ($M2005)

Highest Annualized Cost ($M2005)

Lowest Emissions Reduced (tons)

HigEmRed(ton

MI JH Campbell 1 Coal 260 10,767 LSD 90 CUECost 78,193 11,709 23,423 9,690 2,417 14,483 24,314 9,690 10,2

IPM 57,580 5,858 14,483 9,690 1,495STAPPA - - - - 150-4000

LSFO 95 CUECost 93,492 10,309 24,314 10,229 2,377

IPM 84,520 7,077 19,738 10,229 1,930STAPPA - - - - 200-5000

2 Coal 355 12,986 LSD 90 CUECost 83,538 13,935 26,449 11,688 2,263 17,567 27,430 11,688 12,3

IPM 65,844 7,704 17,567 11,688 1,503STAPPA - - - - 150-4000

LSFO 95 CUECost 99,523 12,521 27,430 12,337 2,223

IPM 94,201 9,060 23,171 12,337 1,878STAPPA - - - - 200-5000

3 Coal 820 30,020 LSD 90 CUECost 112,653 24,860 41,735 27,018 1,545 32,371 47,039 27,018 28,5

IPM 119,585 14,457 32,371 27,018 1,198STAPPA - - - - 150-4000

LSFO 95 CUECost 156,806 23,550 47,039 28,519 1,649

IPM 136,680 17,580 38,055 28,519 1,334STAPPA - - - - 200-5000

Plant Total 1435 53773 64,421 98,783 48,396 51,0

State Facility Unit Fuel

Capacity (MW)

Baseline Emissions (tons)

Control Technology

% Reduction Cost Model

Total Capital Investment [$M2005]

Total O&M Cost [$M2005]

Total Annualized Cost [$M2005]

Emission Reduction (tons)

Cost Effectiveness [$2005/ton]

Lowest Annualized Cost ($M2005)

Highest Annualized Cost ($M2005)

Lowest Emissions Reduced (tons)

HigEmRed(ton

MI JH Campbell 1 Coal 260 3,153 SCR 78 CUECost 29,285 3,146 7,082 2,459 2,880 1,116 12,797 1,104 2,45

IPM 35,987 1,719 6,556 2,459 2,666STAPPA - - - - 1000-2000

SNCR 35 CUECost 3,316 671 1,116 1,104 1,012

IPM 4,559 2,250 2,862 1,104 2,594STAPPA - - - - 800-1500

LNB 35 CUECost 7,589 170 1,190 1,104 1,078

IPM - - - 1,104 -STAPPA - - - - 200-1000

NGR 55 CUECost 6,885 11,872 12,797 1,734 7,379

IPM - - - 1,734 -STAPPA - - - - 500-2000

Costs of SO2 Controls for EGUsCosts of NOx Controls for EGUs

C-9
Table C-4. Consumers Energy Company/JH Campbell Facility (Michigan)

State Facility Unit Fuel

Capacity (MW)

Baseline Emissions (tons)

Control Technology

% Reduction Cost Model

Total Capital Investment [$M2005]

Total O&M Cost [$M2005]

Total Annualized Cost [$M2005]

Emission Reduction (tons)

Cost Effectiveness [$2005/ton]

Lowest Annualized Cost ($M2005)

Highest Annualized Cost ($M2005)

Lowest Emissions Reduced (tons)

HigEmRed(ton

2 Coal 355 7,359 SCR 88 CUECost 33,388 4,005 8,492 6,476 1,311 1,457 15,574 2,576 6,47

IPM 45,173 2,336 8,407 6,476 1,298STAPPA - - - - 1000-2000

SNCR 35 CUECost 3,946 1,424 1,954 2,576 759

IPM 5,133 3,182 3,872 2,576 1,503STAPPA - - - - 800-1500

LNB 35 CUECost 9,292 208 1,457 2,576 566

IPM - - - 2,576 -STAPPA - - - - 200-1000

NGR 55 CUECost 8,375 14,448 15,574 4,047 3,848

IPM - - - 4,047 -STAPPA - - - - 500-2000

3 Coal 820 11,799 SCR 70 CUECost 64,401 8,825 17,481 8,259 2,117 2,511 17,481 4,130 8,25

IPM 90,557 4,830 17,000 8,259 2,058STAPPA - - - - 1000-2000

SNCR 35 CUECost 6,647 2,231 3,124 4,130 757

IPM 7,069 6,937 7,887 4,130 1,910STAPPA - - - - 800-1500

LNB 35 CUECost 16,012 359 2,511 4,130 608

IPM - - - 4,130 -STAPPA - - - - 200-1000

NGR 55 CUECost 17,069 6,921 9,215 6,489 1,420

IPM - - - 6,489 -STAPPA - - - - 500-2000

Plant Total 1435 22311 5,084 45,851 7,809 17,1

C-10
Table C-5. Wisconsin Electric/Presque Isle Facility (Michigan)

State Facility Unit Fuel

Capacity (MW)

Baseline Emissions (tons)

Control Technology

% Reduction Cost Model

Total Capital Investment [$M2005]

Total O&M Cost [$M2005]

Total Annualized Cost [$M2005]

Emission Reduction (tons)

Cost Effectiveness [$2005/ton]

Lowest Annualized Cost ($M2005)

Highest Annualized Cost ($M2005)

Lowest Emissions Reduced (tons)

HigEmRed(ton

MI

WI Electric/Presque Isle 5 Coal 88 3,431 LSD 90 CUECost 45,698 4,761 11,607 3,088 3,759 6,536 14,697 3,088 3,2

IPM 27,815 2,369 6,536 3,088 2,117STAPPA - - - - 150-4000

LSFO 95 CUECost 62,139 5,389 14,697 3,259 4,509

IPM 46,657 2,935 9,924 3,259 3,045STAPPA - - - - 200-5000

6 Coal 88 3,416 LSD 90 CUECost 45,635 4,750 11,586 3,075 3,768 6,536 14,680 3,075 3,2

IPM 27,815 2,369 6,536 3,075 2,126STAPPA - - - - 150-4000

LSFO 95 CUECost 62,076 5,381 14,680 3,245 4,523

IPM 46,657 2,935 9,924 3,245 3,058STAPPA - - - - 200-5000

7 Coal 88 2,046 LSD 90 CUECost 47,226 5,026 12,100 1,842 6,570 6,536 15,113 1,842 1,9

IPM 27,815 2,369 6,536 1,842 3,549STAPPA - - - - 150-4000

LSFO 95 CUECost 63,665 5,576 15,113 1,944 7,773

IPM 46,657 2,935 9,924 1,944 5,104STAPPA - - - - 200-5000

8 Coal 88 1,965 LSD 90 CUECost 46,584 4,914 11,893 1,768 6,726 6,536 14,938 1,768 1,8

IPM 27,815 2,369 6,536 1,768 3,697STAPPA - - - - 150-4000

LSFO 95 CUECost 63,027 5,497 14,938 1,866 8,004

IPM 46,657 2,935 9,924 1,866 5,317STAPPA - - - - 200-5000

9 Coal 88 1,967 LSD 90 CUECost 46,605 4,918 11,899 1,770 6,721 6,536 14,944 1,770 1,8

IPM 27,815 2,369 6,536 1,770 3,692STAPPA - - - - 150-4000

LSFO 95 CUECost 63,047 5,499 14,944 1,869 7,997

IPM 46,657 2,935 9,924 1,869 5,310STAPPA - - - - 200-5000

Plant Total 440 12,825 32,679 74,371 11,543 12,

State Facility Unit Fuel

Capacity (MW)

Baseline Emissions (tons)

Control Technology

% Reduction Cost Model

Total Capital Investment [$M2005]

Total O&M Cost [$M2005]

Total Annualized Cost [$M2005]

Emission Reduction (tons)

Cost Effectiveness [$2005/ton]

Lowest Annualized Cost ($M2005)

Highest Annualized Cost ($M2005)

Lowest Emissions Reduced (tons)

HigEmRed(ton

MI

WI Electric/Presque Isle 5 Coal 88 1,012 SCR 90 CUECost 12,663 988 2,690 910 2,954 427 4,066 354 910 

IPM 16,319 685 2,878 910 3,161STAPPA - - - - 1000-2000

SNCR 35 CUECost 1,916 288 546 354 1,542

IPM 3,023 799 1,205 354 3,404STAPPA - - - - 800-1500

Costs of SO2 Controls for EGUsCosts of NOx Controls for EGUs

C-11
Table C-5. Wisconsin Electric/Presque Isle Facility (Michigan)

State Facility Unit Fuel

Capacity (MW)

Baseline Emissions (tons)

Control Technology

% Reduction Cost Model

Total Capital Investment [$M2005]

Total O&M Cost [$M2005]

Total Annualized Cost [$M2005]

Emission Reduction (tons)

Cost Effectiveness [$2005/ton]

Lowest Annualized Cost ($M2005)

Highest Annualized Cost ($M2005)

Lowest Emissions Reduced (tons)

HigEmRed(ton

LNB 35 CUECost 2,720 61 427 354 1,205

IPM - - - 354 -STAPPA - - - - 200-1000

NGR 55 CUECost 3,962 3,534 4,066 556 7,308

IPM - - - 556 -STAPPA - - - - 500-2000

6 Coal 88 1,049 SCR 90 CUECost 12,630 984 2,681 944 2,839 427 4,051 367 944 

IPM 16,319 685 2,878 944 3,047STAPPA - - - - 1000-2000

SNCR 35 CUECost 1,913 288 545 367 1,483

IPM 3,023 799 1,205 367 3,282STAPPA - - - - 800-1500

LNB 35 CUECost 2,720 61 427 367 1,161

IPM - - - 367 -STAPPA - - - - 200-1000

NGR 55 CUECost 3,962 3,519 4,051 577 7,020

IPM - - - 577 -STAPPA - - - - 500-2000

7 Coal 88 1,218 SCR 90 CUECost 13,467 1,082 2,892 1,096 2,640 427 4,430 426 1,0

IPM 16,319 685 2,878 1,096 2,626STAPPA - - - - 1000-2000

SNCR 35 CUECost 1,982 308 574 426 1,348

IPM 3,023 799 1,205 426 2,828STAPPA - - - - 800-1500

LNB 35 CUECost 2,720 61 427 426 1,001

IPM - - - 426 -STAPPA - - - - 200-1000

NGR 55 CUECost 3,962 3,897 4,430 670 6,615

IPM - - - 670 -STAPPA - - - - 500-2000

8 Coal 88 1,063 SCR 90 CUECost 13,130 1,042 2,807 957 2,934 427 4,276 372 957 

IPM 16,319 108 2,302 957 2,406STAPPA - - - - 1000-2000

SNCR 35 CUECost 1,954 300 562 372 1,512

IPM 3,023 799 1,205 372 3,240STAPPA - - - - 800-1500

LNB 35 CUECost 2,720 61 427 372 1,146

IPM - - - 372 -STAPPA - - - - 200-1000

NGR 55 CUECost 3,962 3,744 4,276 585 7,314

IPM - - - 585 -STAPPA - - - - 500-2000

C-12
Table C-5. Wisconsin Electric/Presque Isle Facility (Michigan)

State Facility Unit Fuel

Capacity (MW)

Baseline Emissions (tons)

Control Technology

% Reduction Cost Model

Total Capital Investment [$M2005]

Total O&M Cost [$M2005]

Total Annualized Cost [$M2005]

Emission Reduction (tons)

Cost Effectiveness [$2005/ton]

Lowest Annualized Cost ($M2005)

Highest Annualized Cost ($M2005)

Lowest Emissions Reduced (tons)

HigEmRed(ton

9 Coal 88 1,120 SCR 90 CUECost 13,141 1,044 2,690 1,008 2,668 427 4,066 392 1,0

IPM 16,319 685 2,878 1,008 2,854STAPPA - - - - 1000-2000

SNCR 35 CUECost 1,955 300 546 392 1,392

IPM 3,023 799 1,205 392 3,074STAPPA - - - - 800-1500

LNB 35 CUECost 2,720 61 427 392 1,088

IPM - - - 392 -STAPPA - - - - 200-1000

NGR 55 CUECost 3,962 3,749 4,066 616 6,084

IPM - - - 616 -STAPPA - - - - 500-2000

Plant Total 440 5,462 2,133 20,890 1,912 4,9

C-13
Table C-6. Minnesota Power/Clay Boswell Facility (Minnesota)

State Facility Unit Fuel

Capacity (MW)

Baseline Emissions (tons)

Control Technology % Reduction Cost Model

Total Capital Investment [$M2005]

Total O&M Cost [$M2005]

Total Annualized Cost [$M2005]

Emission Reduction (tons)

Cost Effectiveness [$2005/ton]

Lowest Annualized Cost ($M2005)

Highest Annualized Cost ($M2005)

LowEmRed

MN Clay Boswell 1 Coal 69 2,587 LSD 90 CUECost 45,601 5,271 12,102 2,328 5,198 5,660 14,108 2,32

IPM 24,610 1,974 5,660 2,328 2,431

STAPPA - - - - 150-4000

LSFO 95 CUECost 59,232 5,235 14,108 2,458 5,741

IPM 42,536 2,469 8,841 2,458 3,598STAPPA - - - - 200-5000

2 Coal 69 2,572 LSD 90 CUECost 46,112 5,266 12,174 2,315 5,259 5,625 14,169 2,31

IPM 24,610 1,938 5,625 2,315 2,430

STAPPA - - - - 150-4000

LSFO 95 CUECost 59,739 5,220 14,169 2,443 5,799

IPM 42,536 2,434 8,806 2,443 3,604STAPPA - - - - 200-5000

Plant Total 138 5159 11,285 28,276 4,64

State Facility Unit Fuel

Capacity (MW)

Baseline Emissions (tons)

Control Technology % Reduction Cost Model

Total Capital Investment [$M2005]

Total O&M Cost [$M2005]

Total Annualized Cost [$M2005]

Emission Reduction (tons)

Cost Effectiveness [$2005/ton]

Lowest Annualized Cost ($M2005)

Highest Annualized Cost ($M2005)

LowEmRed

MN Clay Boswell 1 Coal 69 693 SCR 90 CUECost 10,693 761 2,198 624 3,524 472 3,157 243 

IPM 13,664 550 2,387 624 3,825

STAPPA - - - - 1000-2000

SNCR 35 CUECost 1,754 237 472 243 1,947

IPM 2,758 627 997 243 4,111STAPPA - - - - 800-1500

NGR 55 CUECost 3,635 2,669 3,157 381 8,281

IPM - - - 381 -STAPPA - - - - 500-2000

2 Coal 69 689 SCR 90 CUECost 10,937 781 2,251 620 3,628 474 3,142 241 

IPM 13,664 531 2,367 620 3,817

STAPPA - - - - 1000-2000

SNCR 35 CUECost 1,773 236 474 241 1,965

IPM 2,758 602 973 241 4,032STAPPA - - - - 800-1500

NGR 55 CUECost 3,635 2,654 3,142 379 8,289

IPM - - - 379 -STAPPA - - - - 500-2000

4 Coal 426 4,859 SCR 90 CUECost 36,447 3,805 8,703 4,373 1,990 1,408 23,558 1,70

IPM 51,611 3,525 10,461 4,373 2,392STAPPA - - - - 1000-2000

SNCR 35 CUECost 3,919 882 1,408 1,701 828

IPM 5,503 5,033 5,773 1,701 3,394STAPPA - - - - 800-1500

NGR 55 CUECost 9,854 22,234 23,558 2,673 8,815

IPM - - - 2,673 -

STAPPA - - - - 500-2000

Plant Total 564 6242 2,355 29,857 2,18

Costs of SO2 Controls for EGUsCosts of NOx Controls for EGUs

C-14
Table C-7. Minnesota Power/Syl Laskin Facility (Minnesota)*

State Facility Unit Fuel

Capacity (MW)

Baseline Emissions (tons)

Control Technology % Reduction Cost Model

Total Capital Investment [$M2005]

Total O&M Cost [$M2005]

Total Annualized Cost [$M2005]

Emission Reduction (tons)

Cost Effectiveness [$2005/ton]

Lowest Annualized Cost ($M2005)

Highest Annualized Cost ($M2005)

Lowest Emissions Reduced (tons)

MN Syl Laskin 1 Coal 55 951 LSD 90 CUECost 44,526 4,856 11,526 856 13,460 4,955 11,526 856 

IPM 21,945 1,668 4,955 856 5,786STAPPA - - - - 150-4000

LSFO 95 CUECost 37,652 4,253 9,894 904 10,945

IPM 39,005 2,106 7,949 904 8,794STAPPA - - - - 200-5000

2 Coal 55 950 LSD 90 CUECost 58,190 4,856 13,573 855 15,873 4,698 13,573 855 

IPM 21,945 1,662 4,949 855 5,788STAPPA - - - - 150-4000

LSFO 95 CUECost 58,192 4,852 13,569 903 15,033

IPM 39,005 2,100 7,943 903 8,800STAPPA - - - - 200-5000

Plant Total 110 1902 9,653 25,099 1,711 

* This facility is installing NOx controls so NOx control costs were not evaluated

Costs of SO2 Controls for EGUs

C-15
Table C-8. Northshore Mining Company/Silver Bay Facility (Minnesota)

State Facility Unit Fuel

Capacity (MW)

Baseline Emissions (tons)

Control Technology

% Reduction Cost Model

Total Capital Investment [$M2005]

Total O&M Cost [$M2005]

Total Annualized Cost [$M2005]

Emission Reduction (tons)

Cost Effectiveness [$2005/ton]

Lowest Annualized Cost ($M2005)

Highest Annualized Cost ($M2005)

Lowest Emissions Reduced (tons)

HigEmRed(ton

MN

Northshore/Silver Bay 1 Coal 85 851 LSD 90 CUECost 43,277,712 3,894 10,377 766 13,549 3,465 12,918 766 808 

IPM 17,737 808 3,465 766 4,524STAPPA - - - - 150-4000

LSFO 95 CUECost 58,235 4,195 12,918 808 15,979

IPM 33,215 1,156 6,132 808 7,585STAPPA - - - - 200-5000

Plant Total 85 851 3,465 12,918 766 808 

State Facility Unit Fuel

Capacity (MW)

Baseline Emissions (tons)

Control Technology

% Reduction Cost Model

Total Capital Investment [$M2005]

Total O&M Cost [$M2005]

Total Annualized Cost [$M2005]

Emission Reduction (tons)

Cost Effectiveness [$2005/ton]

Lowest Annualized Cost ($M2005)

Highest Annualized Cost ($M2005)

Lowest Emissions Reduced (tons)

HigEmRed(ton

MN

Northshore/Silver Bay 1 Coal 85 1122 SCR 90 CUECost 11,870 849 2,627 1,010 2,602 322 2,627 16 40 

IPM 8,498 56 1,199 1,010 1,187STAPPA - - - - 1000-2000

SNCR 35 CUECost 1,758 205 468 393 1,192

IPM 2,160 32 322 393 821

STAPPA - - - - 800-1500

LNB 35 CUECost 3,668 82 632 393 1,609

IPM 2,546 39 381 393 971

STAPPA - - - - 200-1000

NGR 55 CUECost 3,912 844 1,430 617 2,317

IPM - - - 617 -

STAPPA - - - - 500-2000

Plant Total 85 1122 322 2,627 16 40 

Costs of SO2 Controls for EGUsCosts of NOx Controls for EGUs

C-16
Table C-9. Virginia Public Utilities Commission Facility (Minnesota)

State Facility Unit Fuel

Capacity (MW)

Baseline Emissions (tons)

Control Technology

% Reduction Cost Model

Total Capital Investment [$M2005]

Total O&M Cost [$M2005]

Total Annualized Cost [$M2005]

Emission Reduction (tons)

Cost Effectiveness [$2005/ton]

Lowest Annualized Cost ($M2005)

Highest Annualized Cost ($M2005)

Lowest Emissions Reduced (tons)

HigheEmissReduc(tons)

MN Virginia PUC 7 Coal 10 584 LSD 90 CUECost 30,787 1,616 6,228 525 11,859 6,228 8,933 525 554 

IPM - - - 525 -STAPPA - - - - 150-4000

LSFO 95 CUECost 44,821 2,219 8,933 554 16,116

IPM - - - 554 -STAPPA - - - - 200-5000

9 Coal 10 584 LSD 90 CUECost 30,787 1,616 6,228 525 11,859 6,228 8,933 525 554 

IPM - - - 525 -STAPPA - - - - 150-4000

LSFO 95 CUECost 44,821 2,219 8,933 554 16,116

IPM - - - 554 -STAPPA - - - - 200-5000

10 Coal 10 12,606 LSD 90 CUECost 30,787 1,616 6,228 11,346 549 6,228 8,933 11,346 11,976 

IPM - - - 11,346 -STAPPA - - - - 150-4000

LSFO 95 CUECost 44,821 2,219 8,933 11,976 -

IPM - - - 11,976 -STAPPA - - - - 200-5000

Plant Total 30 13,773 18,684 26,800 12,396 13,085 

State Facility Unit Fuel

Capacity (MW)

Baseline Emissions (tons)

Control Technology

% Reduction Cost Model

Total Capital Investment [$M2005]

Total O&M Cost [$M2005]

Total Annualized Cost [$M2005]

Emission Reduction (tons)

Cost Effectiveness [$2005/ton]

Lowest Annualized Cost ($M2005)

Highest Annualized Cost ($M2005)

Lowest Emissions Reduced (tons)

HigheEmissReduc(tons)

MN Virginia PUC 7 Coal 10 125 SCR 90 CUECost 4,188 180 743 113 6,589 143 743 44 113 

IPM 3,254 68 505 113 4,481STAPPA - - - - 1000-2000

SNCR 35 CUECost 1,259 115 284 44 6,477

IPM 1,322 67 245 44 5,584STAPPA - - - - 800-1500

LNB 35 CUECost 913 20 143 44 3,264

IPM - - - 44 -STAPPA - - - 200-1000

NGR 55 CUECost 2,270 316 621 69 9,011

IPM - - - 69 -STAPPA - - - - 500-2000

9 Coal 10 125 SCR 90 CUECost 4,188 180 743 113 6,589 143 743 44 113 

IPM 3,254 68 505 113 4,481STAPPA - - - - 1000-2000

SNCR 35 CUECost 1,259 115 284 44 6,477

IPM 1,322 67 245 44 5,584STAPPA - - - - 800-1500

LNB 35 CUECost 913 20 143 44 3,264

IPM - - - 44 -STAPPA - - - 200-1000

NGR 55 CUECost 2,270 316 621 69 9,011

IPM - - - 69 -STAPPA - - - - 500-2000

Costs of SO2 Controls for EGUsCosts of NOx Controls for EGUs

C-17
Table C-9. Virginia Public Utilities Commission Facility (Minnesota)

State Facility Unit Fuel

Capacity (MW)

Baseline Emissions (tons)

Control Technology

% Reduction Cost Model

Total Capital Investment [$M2005]

Total O&M Cost [$M2005]

Total Annualized Cost [$M2005]

Emission Reduction (tons)

Cost Effectiveness [$2005/ton]

Lowest Annualized Cost ($M2005)

Highest Annualized Cost ($M2005)

Lowest Emissions Reduced (tons)

HigheEmissReduc(tons)

10 Coal 10 0 SCR 90 CUECost 4,188 180 743 0 - 108 743 0 0 

IPM - - - 0 -

STAPPA - - - - -

SNCR 35 CUECost 1,259 115 284 0 -

IPM 720 11 108 0 -

STAPPA - - - - -

LNB 35 CUECost 913 20 143 0 -

IPM - - - 0 -

STAPPA - - - - -

NGR 55 CUECost 2,270 316 621 0 -

IPM - - - 0 -

STAPPA - - - - -

Plant Total 30 251 394 2,229 88 226 

C-18
Table C-10. Dairyland Power Coop/Alma Facility (Wisconsin)

State Facility Unit Fuel

Capacity (MW)

Baseline Emissions (tons)

Control Technology

% Reduction Cost Model

Total Capital Investment [$M2005]

Total O&M Cost [$M2005]

Total Annualized Cost [$M2005]

Emission Reduction (tons)

Cost Effectiveness [$2005/ton]

Lowest Annualized Cost ($M2005)

Highest Annualized Cost ($M2005)

Lowest Emissions Reduced (tons)

Highest EmissionReduced (tons)

WI Dairyland1 Coal 18 1,384 LSD 90 CUECost 33,226 2,297 7,274 1,245 5,841 2,748 9,953 1,245 1,315 

IPM 12,606 859 2,748 1,245 2,206STAPPA - - - - 150-4000

LSFO 95 CUECost 47,057 2,904 9,953 1,315 7,571

IPM 25,663 1,101 4,945 1,315 3,762STAPPA - - - - 200-5000

2 Coal 18 1,165 LSD 90 CUECost 33,226 2,213 7,190 1,048 6,858 2,701 9,874 1,048 1,107 

IPM 12,606 813 2,701 1,048 2,576STAPPA - - - - 150-4000

LSFO 95 CUECost 47,057 2,825 9,874 1,107 8,922

IPM 25,663 1,054 4,899 1,107 4,426STAPPA - - - - 200-5000

3 Coal 22 1,396 LSD 90 CUECost 34,312 2,416 7,556 1,256 6,016 2,986 10,284 1,256 1,326 

IPM 13,805 918 2,986 1,256 2,378STAPPA - - - - 150-4000

LSFO 95 CUECost 48,384 3,036 10,284 1,326 7,757

IPM 27,487 1,184 5,302 1,326 3,999STAPPA - - - - 200-5000

4 Coal 57 2,415 LSD 90 CUECost 42,672 4,086 10,478 2,174 4,820 5,090 13,325 2,174 2,295 

IPM 22,357 1,741 5,090 2,174 2,341STAPPA - - - - 150-4000

LSFO 95 CUECost 57,570 4,701 13,325 2,295 5,807

IPM 39,561 2,188 8,114 2,295 3,536STAPPA - - - - 200-5000

5 Coal 77 3,514 LSD 90 CUECost 43,802 4,382 10,944 3,163 3,460 6,175 14,097 3,163 3,338 

IPM 26,064 2,271 6,175 3,163 1,953STAPPA - - - - 150-4000

LSFO 95 CUECost 60,464 5,039 14,097 3,338 4,223

IPM 44,421 2,798 9,453 3,338 2,832STAPPA - - - - 200-5000

Plant Total 192 9,874 19,701 57,533 8,886 9,380 

State Facility Unit Fuel

Capacity (MW)

Baseline Emissions (tons)

Control Technology % ReductionCost Model

Total Capital Investment [$M2005]

Total O&M Cost [$M2005]

Total Annualized Cost [$M2005]

Emission Reduction (tons)

Cost Effectiveness [$2005/ton]

Lowest Annualized Cost ($M2005)

Highest Annualized Cost ($M2005)

Lowest Emissions Reduced (tons)

Highest EmissionReduced (tons)

WI Dairyland1 Coal 18 316 SCR 90 CUECost 5,047 244 922 285 3,238 152 1,336 111 285 

IPM 5,178 221 917 285 3,223STAPPA - - - - 1000-2000

SNCR 35 CUECost 1,301 146 321 111 2,900

IPM 1,675 231 456 111 4,119STAPPA - - - - 800-1500

LNB 35 CUECost 970 22 152 111 1,373

IPM 1,214 31 194 111 1,753STAPPA - - - - 200-1000

NGR 55 CUECost 2,548 994 1,336 174 7,682

IPM - - - 174 -

STAPPA - - - - 500-2000

Costs of SO2 Controls for EGUsCosts of NOx Controls for EGUs

C-19
Table C-10. Dairyland Power Coop/Alma Facility (Wisconsin)

State Facility Unit Fuel

Capacity (MW)

Baseline Emissions (tons)

Control Technology

% Reduction Cost Model

Total Capital Investment [$M2005]

Total O&M Cost [$M2005]

Total Annualized Cost [$M2005]

Emission Reduction (tons)

Cost Effectiveness [$2005/ton]

Lowest Annualized Cost ($M2005)

Highest Annualized Cost ($M2005)

Lowest Emissions Reduced (tons)

Highest EmissionReduced (tons)

2 Coal 18 266 SCR 90 CUECost 5,047 242 920 240 3,840 152 1,226 93 240 

IPM 5,178 192 888 240 3,705STAPPA - - - - 1000-2000

SNCR 35 CUECost 1,300 139 314 93 3,369

IPM 1,675 198 423 93 4,544STAPPA - - - - 800-1500

LNB 35 CUECost 970 22 152 93 1,631

IPM 1,214 29 192 93 2,061

STAPPA - - - - 200-1000

NGR 55 CUECost 2,548 883 1,226 146 8,370

IPM - - - 146 -STAPPA - - - - 500-2000

3 Coal 22 319 SCR 90 CUECost 5,662 290 1,051 287 3,662 173 1,411 112 287 

IPM 5,908 224 1,018 287 3,547STAPPA - - - - 1000-2000

SNCR 35 CUECost 1,349 148 330 112 2,953

IPM 1,792 234 475 112 4,257STAPPA - - - - 800-1500

LNB 35 CUECost 1,105 25 173 112 1,552

IPM 1,363 33 216 112 1,939STAPPA - - - - 200-1000

NGR 55 CUECost 2,661 1,053 1,411 175 8,043

IPM - - - 175 -STAPPA - - - - 500-2000

4 Coal 57 773 SCR 90 CUECost 10,041 697 2,046 696 2,942 322 2,973 271 696 

IPM 11,888 479 2,076 696 2,985STAPPA - - - - 1000-2000

SNCR 35 CUECost 1,700 227 456 271 1,684

IPM 2,567 537 882 271 3,259STAPPA - - - - 800-1500

LNB 35 CUECost 2,051 46 322 271 1,189

IPM - - - 271 -STAPPA - - - - 200-1000

NGR 55 CUECost 3,418 2,513 2,973 425 6,993

IPM - - - 425 -

STAPPA - - - - 500-2000

5 Coal 77 1,124 SCR 90 CUECost 11,907 922 2,522 1,012 2,492 391 4,119 394 1,012 

IPM 14,851 676 2,672 1,012 2,640STAPPA - - - - 1000-2000

SNCR 35 CUECost 1,856 288 538 394 1,366

IPM 2,880 787 1,174 394 2,984STAPPA - - - - 800-1500

LNB 35 CUECost 2,494 56 391 394 994

IPM - - - 394 -STAPPA - - - 200-1000

NGR 55 CUECost 3,775 3,611 4,119 618 6,660

IPM - - - 618 -

STAPPA - - - - 500-2000

Plant Total 192 2,799 1,190 11,065 980 2,519 

C-20
Table C-11. Xcel Energy/Bay Front Facility (Wisconsin)

State Facility Unit Fuel

Capacity (MW)

Baseline Emissions (tons)

Control Technology

% Reduction Cost Model

Total Capital Investment [$M2005]

Total O&M Cost [$M2005]

Total Annualized Cost [$M2005]

Emission Reduction (tons)

Cost Effectiveness [$2005/ton]

Lowest Annualized Cost ($M2005)

Highest Annualized Cost ($M2005)

Lowest Emissions Reduced (tons)

WI Xcel Energ1 Coal 22 1,890 LSD 90 CUECost 37,322 2,701 8,291 1,701 4,876 2,953 11,074 1,701 

IPM 13,843 879 2,953 1,701 1,736

STAPPA - - - - 150-4000

LSFO 95 CUECost 51,934 3,294 11,074 1,795 6,169

IPM 27,544 1,146 5,272 1,795 2,937

STAPPA - - - - 200-5000

2 Coal 22 1,890 LSD 90 CUECost 36,222 2,666 8,092 1,701 4,758 2,992 10,865 1,701 

IPM 13,843 919 2,992 1,701 1,760

STAPPA - - - - 150-4000

LSFO 95 CUECost 50,684 3,272 10,865 1,795 6,053

IPM 27,544 1,186 5,312 1,795 2,959

STAPPA - - - - 200-5000

5 Coal 30 1,478 LSD 90 CUECost 36,662 2,553 8,045 1,330 6,047 3,457 10,888 1,330 

IPM 16,182 1,033 3,457 1,330 2,598

STAPPA - - - - 150-4000

LSFO 95 CUECost 51,173 3,222 10,888 1,404 7,753

IPM 30,991 1,348 5,991 1,404 4,266

STAPPA - - - - 200-5000

Plant Total 74 5,257 9,402 32,826 4,731 

State Facility Unit Fuel

Capacity (MW)

Baseline Emissions (tons)

Control Technology

% Reduction Cost Model

Total Capital Investment [$M2005]

Total O&M Cost [$M2005]

Total Annualized Cost [$M2005]

Emission Reduction (tons)

Cost Effectiveness [$2005/ton]

Lowest Annualized Cost ($M2005)

Highest Annualized Cost ($M2005)

Lowest Emissions Reduced (tons)

WI Xcel Energ1 Coal 22 509 SCR 90 CUECost 7,479 443 1,448 458 3,163 173 1,777 178 

IPM 5,932 199 996 458 2,175STAPPA - - - - 1000-2000

SNCR 35 CUECost 1,518 192 396 178 2,223

IPM 1,796 206 447 178 2,510STAPPA - - - - 800-1500

LNB 35 CUECost 1,105 25 173 178 973

IPM - - - 178 -STAPPA - - - - 200-1000

NGR 55 CUECost 2,661 1,419 1,777 280 6,350

IPM - - - 280 -STAPPA - - - - 500-2000

2 Coal 22 447 SCR 90 CUECost 6,757 384 1,292 402 3,213 173 1,777 156 

IPM 5,932 223 1,021 402 2,537STAPPA - - - - 1000-2000

SNCR 35 CUECost 1,437 168 361 156 2,310

IPM 1,796 233 475 156 3,036

STAPPA - - - - 800-1500

LNB 35 CUECost 1,105 25 173 156 1,107

IPM - - - 156 -STAPPA - - - - 200-1000

Costs of SO2 Controls for EGUsCosts of NOx Controls for EGUs

C-21
Table C-11. Xcel Energy/Bay Front Facility (Wisconsin)

State Facility Unit Fuel

Capacity (MW)

Baseline Emissions (tons)

Control Technology

% Reduction Cost Model

Total Capital Investment [$M2005]

Total O&M Cost [$M2005]

Total Annualized Cost [$M2005]

Emission Reduction (tons)

Cost Effectiveness [$2005/ton]

Lowest Annualized Cost ($M2005)

Highest Annualized Cost ($M2005)

Lowest Emissions Reduced (tons)

NGR 55 CUECost 2,661 1,419 1,777 246 7,227

IPM - - - 246 500-2000

STAPPA - - - - 1,285

5 Coal 30 517 SCR 90 CUECost 7,216 411 1,381 466 2,966 212 1,505 181 

IPM 7,439 229 1,229 466 2,640STAPPA - - - - 1000-2000

SNCR 35 CUECost 1,515 188 392 181 2,165

IPM 1,582 419 631 181 3,486STAPPA - - - - 800-1500

LNB 35 CUECost 1,352 30 212 181 1,170

IPM - - - 181 -

STAPPA - - - 181 200-1000

NGR 55 CUECost 2,862 1,120 1,505 285 5,287

IPM - - - 285 -

STAPPA - - - - 500-2000

Plant Total 74 1,473 558 5,058 516 

C-22
Table C-12. Alliant Energy-Wisconsin Power/Edgewater Facility (Wisconsin)

State Facility Unit Fuel

Capacity (MW)

Baseline Emissions (tons)

Control Technology

% Reduction Cost Model

Total Capital Investment [$M2005]

Total O&M Cost [$M2005]

Total Annualized Cost [$M2005]

Emission Reduction (tons)

Cost Effectiveness [$2005/ton]

Lowest Annualized Cost ($M2005)

Highest Annualized Cost ($M2005)

Lowest Emissions Reduced (tons)

Highest Emissions Reduced (tons)

Cost Effecti($2005

WI Alliant Ener3 Coal 75 1,864 LSD 90 CUECost 47,351 5,328 12,421 1,677 7,406 5,955 14,711 1,677 1,770 150-83

IPM 25,747 2,098 5,955 1,677 3,550STAPPA - - - - 150-4000

LSFO 95 CUECost 60,864 5,593 14,711 1,770 8,310

IPM 44,012 2,618 9,211 1,770 5,203STAPPA - - - - 200-5000

4 Coal 334 8,277 LSD 90 CUECost 86,380 17,366 30,306 7,449 4,068 17,153 31,414 7,449 7,863 150-40

IPM 63,174 7,690 17,153 7,449 2,303STAPPA - - - - 150-4000

LSFO 95 CUECost 98,542 16,653 31,414 7,863 3,995

IPM 91,600 8,963 22,684 7,863 2,885STAPPA - - - - 200-5000

5 Coal 422 10,672 LSD 90 CUECost 87,931 13,842 27,014 9,605 2,813 19,892 30,888 9,605 10,138 150-30

IPM 73,892 8,823 19,892 9,605 2,071STAPPA - - - - 150-4000

LSFO 95 CUECost 107,638 14,764 30,888 10,138 3,047

IPM 101,846 10,432 25,689 10,138 2,534STAPPA - - - - 200-5000

Plant Total 831 20,812 43,000 77,013 18,731 19,771 2296-3

State Facility Unit Fuel

Capacity (MW)

Baseline Emissions (tons)

Control Technology

% Reduction Cost Model

Total Capital Investment [$M2005]

Total O&M Cost [$M2005]

Total Annualized Cost [$M2005]

Emission Reduction (tons)

Cost Effectiveness [$2005/ton]

Lowest Annualized Cost ($M2005)

Highest Annualized Cost ($M2005)

Lowest Emissions Reduced (tons)

Highest Emissions Reduced (tons)

Cost Effecti($2005

WI Alliant Ener3 Coal 75 865 SCR 90 CUECost 11,459 844 2,384 779 3,061 497 3,501 303 779 200-73

IPM 14,589 590 2,550 779 3,275STAPPA - - - - 1000-2000

SNCR 35 CUECost 1,815 253 497 303 1,641

IPM 2,337 1,233 1,547 303 5,109STAPPA - - - - 800-1500

LNB 35 CUECost 3,382 76 530 303 1,751

IPM - - - 303 -STAPPA - - - - 200-1000

NGR 55 CUECost 3,743 2,998 3,501 476 7,355

IPM - - - 476 -STAPPA - - - - 500-2000

4 Coal 334 3,285 SCR 90 CUECost 28,738 3,183 7,045 2,957 2,383 1,232 14,090 1,150 2,957 200-77

IPM 43,182 2,370 8,174 2,957 2,764STAPPA - - - - 1000-2000

SNCR 35 CUECost 3,322 785 1,232 1,150 1,071

IPM 4,382 6,012 6,601 1,150 5,741STAPPA - - - - 800-1500

Costs of SO2 Controls for EGUsCosts of NOx Controls for EGUs

C-23
Table C-12. Alliant Energy-Wisconsin Power/Edgewater Facility (Wisconsin)

State Facility Unit Fuel

Capacity (MW)

Baseline Emissions (tons)

Control Technology

% Reduction Cost Model

Total Capital Investment [$M2005]

Total O&M Cost [$M2005]

Total Annualized Cost [$M2005]

Emission Reduction (tons)

Cost Effectiveness [$2005/ton]

Lowest Annualized Cost ($M2005)

Highest Annualized Cost ($M2005)

Lowest Emissions Reduced (tons)

Highest Emissions Reduced (tons)

Cost Effecti($2005

LNB 35 CUECost 8,929 200 1,400 1,150 1,218

IPM - - - 1,150 -STAPPA - - - - 200-1000

NGR 55 CUECost 8,058 13,007 14,090 1,807 7,797

IPM - - - 1,807 -STAPPA - - - - 500-2000

5 Coal 422 1,971 SCR 90 CUECost 33,963 3,698 8,263 1,774 4,659 863 16,789 690 1,774 200-15

IPM 51,214 2,727 9,610 1,774 5,419STAPPA - - - - 1000-2000

SNCR 35 CUECost 3,533 388 863 690 1,251

IPM 5,481 3,792 4,529 690 6,566STAPPA - - - - 800-1500

LNB 35 CUECost 7,536 169 1,182 690 1,713

IPM - - - 690 -STAPPA - - - - 200-1000

NGR 55 CUECost 9,791 15,474 16,789 1,084 15,491

IPM - - - 1,084 -STAPPA - - - - 500-2000

Plant Total 831 6,121 2,592 34,380 2,142 5,509 1210-6

C-24
Table C-13. Alliant Energy-Wisconsin Power/Nelson Dewey Facility (Wisconsin)

State Facility Unit Fuel

Capacity (MW)

Baseline Emissions (tons)

Control Technology

% Reduction Cost Model

Total Capital Investment [$M2005]

Total O&M Cost [$M2005]

Total Annualized Cost [$M2005]

Emission Reduction (tons)

Cost Effectiveness [$2005/ton]

Lowest Annualized Cost ($M2005)

Highest Annualized Cost ($M2005)

Lowest Emissions Reduced (tons)

HEmR(to

WI Alliant Energy/N1 Coal 108 4,206 LSD 90 CUECost 54,250 8,018 16,145 3,786 4,265 8,642 17,324 3,786 3,

IPM 36,950 3,107 8,642 3,786 2,283STAPPA - - - - 150-4000

LSFO 95 CUECost 66,535 7,357 17,324 3,996 4,335

IPM 60,457 3,864 12,921 3,996 3,233STAPPA - - - - 200-5000

2 Coal 111 4,127 LSD 90 CUECost 54,432 7,949 16,103 3,714 4,336 8,738 17,320 3,714 3,

IPM 37,434 3,131 8,738 3,714 2,353STAPPA - - - - 150-4000

LSFO 95 CUECost 66,701 7,328 17,320 3,920 4,418

IPM 61,054 3,898 13,044 3,920 3,327STAPPA - - - - 200-5000

Plant Total 219 8,333 17,381 17,320 7,500 7,

State Facility Unit Fuel

Capacity (MW)

Baseline Emissions (tons)

Control Technology

% Reduction Cost Model

Total Capital Investment [$M2005]

Total O&M Cost [$M2005]

Total Annualized Cost [$M2005]

Emission Reduction (tons)

Cost Effectiveness [$2005/ton]

Lowest Annualized Cost ($M2005)

Highest Annualized Cost ($M2005)

Lowest Emissions Reduced (tons)

HEmR(to

WI Alliant Energy/N1 Coal 108 1,262 SCR 90 CUECost 14,058 1,159 3,049 1,136 2,684 487 4,904 442 1,

IPM 18,912 849 3,391 1,136 2,986STAPPA - - - - 1000-2000

SNCR 35 CUECost 2,033 326 599 442 1,357

IPM 2,716 1,871 2,236 442 5,063STAPPA - - - - 800-1500

LNB 35 CUECost 3,108 70 487 442 1,103

IPM - - - 442 -STAPPA - - - - 200-1000

NGR 55 CUECost 4,294 4,327 4,904 694 7,066

IPM - - - 694 -STAPPA - - - - 500-2000

2 Coal 111 1,238 SCR 90 CUECost 14,135 1,161 3,061 1,114 2,747 496 4,830 433 1,

IPM 19,272 850 3,440 1,114 3,087STAPPA - - - - 1000-2000

SNCR 35 CUECost 2,039 322 596 433 1,375

IPM 2,746 1,871 2,240 433 5,171STAPPA - - - - 800-1500

LNB 35 CUECost 3,163 71 496 433 1,145

IPM - - - 433 -STAPPA - - - - 200-1000

NGR 55 CUECost 4,343 4,246 4,830 681 7,093

IPM - - - 681 -STAPPA - - - - 500-2000

Plant Total 219 2,500 983 9,734 875 2,

Costs of SO2 Controls for EGUsCosts of NOx Controls for EGUs

C-25
Table C-14. Boise Cascade Corporation (Minnesota)

State Facility Unit Fuel

Capacity (MW)

Baseline Emissions (tons)

Control Technology

% Reduction Cost Model

Total Capital Investment [$M2005]

Total O&M Cost [$M2005]

Total Annualized Cost [$M2005]

Emission Reduction (tons)

 CostEffectiveness [$2005/ton]

Lowest Annualized Cost ($M2005)

Highest Annualized Cost ($M2005)

LoweEmisRedu(tons

MI Boise Cascade Corp. 2 Gas 38 48 LSD 90 CUECost 51,688 3,169 10,912 43 254,398 3,966 10,912 43 

IPM 18,130 1,373 4,089 43 95,333Khan (2003)* 17,294 1,376 3,966 43 92,472STAPPA - - - - 1,011

LSFO 95 CUECost 32,346 2,199 7,044 45 155,586

IPM 33,769 1,730 6,789 45 149,938Khan (2003)* 17,294 1,376 3,966 45 87,605STAPPA - - - - 1,011

Plant Total 38 48 3,966 10,912 43 

State Facility Unit Fuel

Capacity (MW)

Baseline Emissions (tons)

Control Technology

% Reduction Cost Model

Total Capital Investment [$M2005]

Total O&M Cost [$M2005]

Total Annualized Cost [$M2005]

Emission Reduction (tons)

 CostEffectiveness [$2005/ton]

Lowest Annualized Cost ($M2005)

Highest Annualized Cost ($M2005)

LoweEmisRedu(tons

MI Boise Cascade Corp. 1 Gas 38 104 SCR 80 CUECost 7,076 398 1,349 84 16,146 120 2,769 37 

IPM 2,768 129 501 84 5,990

Khan (2003)* 2,485 238 572 84 6,847STAPPA - - - - 1,354

SNCR 50 CUECost 1,366 116 299 52 5,733

IPM 1,353 219 401 52 7,678Khan (2003)* 1,307 299 475 52 9,094STAPPA - - - - 2,193

LNB 35 CUECost 2,174 49 341 37 9,322

IPM 1,023 2 139 37 3,805Khan (2003)* 792 61 167 37 4,569STAPPA - - - 424

NGR 61 CUECost 3,041 2,360 2,769 64 43,450

IPM - - - 64 -Khan (2003)* 446 61 120 64 1,891STAPPA - - - - -

Costs of SO2 Controls for ICIsCosts of NOx Controls for ICIs

C-26
Table C-14. Boise Cascade Corporation (Minnesota)

State Facility Unit Fuel

Capacity (MW)

Baseline Emissions (tons)

Control Technology

% Reduction Cost Model

Total Capital Investment [$M2005]

Total O&M Cost [$M2005]

Total Annualized Cost [$M2005]

Emission Reduction (tons)

 CostEffectiveness [$2005/ton]

Lowest Annualized Cost ($M2005)

Highest Annualized Cost ($M2005)

LoweEmisRedu(tons

2 Gas 38 331 SCR 90 CUECost 7,331 421 1,406 265 5,307 169 1,406 116 

IPM 2,749 127 497 265 1,875Khan (2003)* 2,511 241 579 265 2,185STAPPA - - - - 1,354

SNCR 35 CUECost 1,448 159 354 166 2,137

IPM 1,347 217 398 166 2,401Khan (2003)* 1,321 304 482 166 2,908STAPPA - - - - 2,193

LNB 35 CUECost 2,159 48 339 37 9,258

IPM 2 1,016 1,017 37 27,803Khan (2003)* 801 61 169 37 4,623STAPPA - - - 424

3 Gas 35 25 SCR 90 CUECost 6,669 361 1,257 20 62,895 117 1,652 9 

IPM 2,624 97 450 20 22,500Khan (2003)* 2,413 230 554 20 27,716STAPPA - - - - 2,330

SNCR 35 CUECost 1,322 101 279 12 22,303

IPM 1,307 96 271 12 21,728Khan (2003)* 1,269 287 458 12 36,626STAPPA - - - - 3,116

LNB 35 CUECost 2,061 46 323 9 36,942

IPM 1,550 28 236 9 27,018Khan (2003)* 769 58 162 9 18,501STAPPA 797

NGR 61 CUECost 2,975 1,252 1,652 15 108,392

IPM - - - 15 -Khan (2003)* 433 58 117 15 7,648STAPPA - - - - -

Plant Total 76 436 406 5,827 161 

* "Total O&M Costs" for Khan (2003) also includes annual costs (e.g., annual catalyst replacement, fuel costs). For all other models "Total O&M Costs" do not contain any annual costs.

C-27
APC Technology Choices

Suggested Default

Description Units Range Values Boiler 1 Boiler 2 Boiler 3 Boiler 3 Boiler 3

FGD Process Integer 1 or 2 1 1 2 1 21

 (1 = LSFO, 2 = LSD)

Particulate Control Integer 1 or 2 1 1 1 1 11

 (1 = Fabric Filter, 2 = ESP)

NOx Control Integer 1 - 4 1 1 2 1 24

 (1 = SCR, 2 = SNCR, 3 = LNBs, 4 = NGR)

INPUTS

Default

Description Units Range Values Boiler 1 Boiler 2 Boiler 3 Boiler 3 Boiler 3

General Plant Technical Inputs

Location - State Abbrev. All States PA MI MI MI MI MI

MW Equivalent of Flue Gas to Control System MW 100-2000 500 260 355 820 820 820

Net Plant Heat Rate (w/o APC) Btu/kWhr 10,500 13,269 11,243 11,814 11,814 11,814

Plant Capacity Factor % 40-90% 65% 77% 81% 77% 77% 77%

Percent Excess Air in Boiler % 120% 120% 120% 120% 120% 120%

Air Heater Inleakage % 12% 12% 12% 12% 12% 12%

Air Heater Outlet Gas Temperature °F 300 300 300 300 300 300

Inlet Air Temperature °F 80 80 80 80 80 80

Ambient Absolute Pressure In. of Hg 29.4 29.4 29.4 29.4 29.4 29.4

Pressure After Air Heater In. of H2O -12 -12 -12 -12 -12 -12

Moisture in Air lb/lb dry air 0.013 0.013 0.013 0.013 0.013 0.013

Ash Split:

 Fly Ash % 80% 80% 80% 80% 80% 80%

 Bottom Ash % 20% 20% 20% 20% 20% 20%

Seismic Zone Integer 1-5 1 1 1 1 11

Retrofit Factor Integer 1.0-3.0 1.3 1.3 1.3 1.3 1.3 1.3

 (1.0 = new, 1.3 = medium, 1.6 = difficult)

Select Coal Integer 1-8 1 8 8 8 88

Is Selected Coal a Powder River Basin Coal? Yes / No See Column K Yes No No No No No

Coals Available in Library

Coal 1, Wyoming PRB: 8,227 Btu, 0.37% S, 5.32% ash

Coal 2, Armstrong, PA: 13,100 Btu, 2.6% S, 9.1% ash

Coal 3, Jefferson, OH: 11,922 Btu, 3.43% S, 13% ash

Coal 4, Logan, WV: 12,058 Btu, 0.89% S, 16.6% ash

Coal 5, No. 6 Illinois: 10,100 Btu, 4% S, 16% ash

Coal 6, Rosebud, MT: 8,789 Btu, 0.56% S, 8.15% ash

Coal 7, Lignite, ND: 7,500 Btu, 0.94% S, 5.9% ash

Coal 8, "User Specified": 12,062 Btu, 1% S, 16.6% ash

Economic Inputs

Cost Basis -Year Dollars Year 1998 2005 2005 2005 2005 2005

Sevice Life (levelization period) Years 30 15 15 15 15 15

Inflation Rate % 3.00% 3.99% 3.99% 3.99% 3.99% 3.99%

After Tax Discount Rate (current $'s) % 9.20% 9.20% 9.20% 9.20% 9.20% 9.20%

AFDC Rate (current $'s) % 10.80% 10.80% 10.80% 10.80% 10.80% 10.80%

First-year Carrying Charge (current $'s) % 22.30% 14.98% 14.98% 14.98% 14.98% 14.98%

Levelized Carrying Charge (current $'s) % 16.90% 16.90% 16.90% 16.90% 16.90% 16.90%

First-year Carrying Charge (constant $'s) % 15.70% 15.70% 15.70% 15.70% 15.70% 15.70%

Levelized Carrying Charge (constant $'s) % 11.70% 11.70% 11.70% 11.70% 11.70% 11.70%

Sales Tax % 6% 6% 6% 6% 6% 6%

Escalation Rates:

 Consumables (O&M) % 3% 3% 3% 3% 3% 3%

 Capital Costs:

 Is Chem. Eng. Cost Index available? Yes / No Yes Yes Yes Yes Yes Yes

 If "Yes" input cost basis CE Plant Index. Integer 388 468.3 468.3 468.3 468.3 468.3

 If "No" input escalation rate. % 3% 3% 3% 3% 3% 3%

Construction Labor Rate $/hr $35 $32 $32 $32 $32 $32

Prime Contractor's Markup % 3% 3% 3% 3% 3% 3%

Operating Labor Rate $/hr $30 $31 $31 $31 $31 $31

Power Cost Mills/kWh 25 68.3 68.3 68.3 68.3 68.3

Steam Cost $/1000 lbs 3.5 7.44 7.44 7.44 7.44 7.44

Limestone Forced Oxidation (LSFO) Inputs

SO2 Removal Required % 90-98% 95% 95% 95% 95% 95% 95%

L/G Ratio gal / 1000 acf 95-160 125 125 125 125 125 125

Design Scrubber with Dibasic Acid Addition? Integer 1 or 2 2 2 2 2 22

 (1 = yes, 2 = no)

Adiabatic Saturation Temperature °F 100-170 127 127 127 127 127 127

Table C-15. CUECost Example - Input Data for Analysis (JH Campbell, Michigan)

C-28
Table C-15. CUECost Example - Input Data for Analysis (JH Campbell, Michigan)

Reagent Feed Ratio Factor 1.0-2.0 1.05 1.05 1.05 1.05 1.05 1.05

 (Mole CaCO3 / Mole SO2 removed)

Scrubber Slurry Solids Concentration Wt. % 15% 15% 15% 15% 15% 15%

Stacking, Landfill, Wallboard Integer 1,2,3 1 1 1 1 11

 (1 = stacking, 2 = landfill, 3 = wallboard)

Number of Absorbers Integer 1-6 1 1 1 1 11

 (Max. Capacity = 700 MW per absorber)

Absorber Material Integer 1 or 2 1 1 1 1 11

 (1 = alloy, 2 = RLCS)

Absorber Pressure Drop in. H2O 6 6 6 6 66

Reheat Required ? Integer 1 or 2 1 1 1 1 11

 (1 = yes, 2 = no)

Amount of Reheat °F 0-50 25 25 25 25 25 25

Reagent Bulk Storage Days 60 60 60 60 60 60

Reagent Cost (delivered) $/ton $15 $15 $15 $15 $15 $15

Landfill Disposal Cost $/ton $30 $30 $30 $30 $30 $30

Stacking Disposal Cost $/ton $6 $6 $6 $6 $6 $6

Credit for Gypsum Byproduct $/ton $2 $2 $2 $2 $2 $2

Maintenance Factors by Area (% of Installed Cost)

 Reagent Feed % 5% 5% 5% 5% 5% 5%

 SO2 Removal % 5% 5% 5% 5% 5% 5%

 Flue Gas Handling % 5% 5% 5% 5% 5% 5%

 Waste / Byproduct % 5% 5% 5% 5% 5% 5%

 Support Equipment % 5% 5% 5% 5% 5% 5%

Contingency by Area (% of Installed Cost)

 Reagent Feed % 20% 20% 20% 20% 20% 20%

 SO2 Removal % 20% 20% 20% 20% 20% 20%

 Flue Gas Handling % 20% 20% 20% 20% 20% 20%

 Waste / Byproduct % 20% 20% 20% 20% 20% 20%

 Support Equipment % 20% 20% 20% 20% 20% 20%

General Facilities by Area (% of Installed Cost)

 Reagent Feed % 10% 10% 10% 10% 10% 10%

 SO2 Removal % 10% 10% 10% 10% 10% 10%

 Flue Gas Handling % 10% 10% 10% 10% 10% 10%

 Waste / Byproduct % 10% 10% 10% 10% 10% 10%

 Support Equipment % 10% 10% 10% 10% 10% 10%

Engineering Fees by Area (% of Installed Cost)

 Reagent Feed % 10% 10% 10% 10% 10% 10%

 SO2 Removal % 10% 10% 10% 10% 10% 10%

 Flue Gas Handling % 10% 10% 10% 10% 10% 10%

 Waste / Byproduct % 10% 10% 10% 10% 10% 10%

 Support Equipment % 10% 10% 10% 10% 10% 10%

Lime Spray Dryer (LSD) Inputs

SO2 Removal Required % 90-95% 90% 90% 90% 90% 90% 90%

Adiabatic Saturation Temperature °F 100-170 127 127 127 127 127 127

Flue Gas Approach to Saturation °F 10.-50 20 20 20 20 20 20

Spray Dryer Outlet Temperature °F 110-220 147 147 147 147 147 147

Reagent Feed Ratio Factor Calc. Based on %S 0.90 1.04 1.04 1.04 1.04 1.04

 (Mole CaO / Mole Inlet SO2)

Recycle Rate Factor Calculated 30 7.5 7.5 7.5 7.5 7.5

 (lb recycle / lb lime feed)

Recycle Slurry Solids Concentration Wt. % 10-50 35% 35% 35% 35% 35% 35%

Number of Absorbers Integer 1-7 2 2 2 2 22

 (Max. Capacity = 300 MW per spray dryer)

Absorber Material Integer 1 or 2 1 1 1 1 11

 (1 = alloy, 2 = RLCS)

Spray Dryer Pressure Drop in. H2O 5 5 5 5 55

Reagent Bulk Storage Days 60 60 60 60 60 60

Reagent Cost (delivered) $/ton $65 $65 $65 $65 $65 $65

Dry Waste Disposal Cost $/ton $30 $30 $30 $30 $30 $30

Maintenance Factors by Area (% of Installed Cost)

 Reagent Feed % 5% 5% 5% 5% 5% 5%

 SO2 Removal % 5% 5% 5% 5% 5% 5%

 Flue Gas Handling % 5% 5% 5% 5% 5% 5%

 Waste / Byproduct % 5% 5% 5% 5% 5% 5%

 Support Equipment % 5% 5% 5% 5% 5% 5%

Contingency by Area (% of Installed Cost)

 Reagent Feed % 20% 20% 20% 20% 20% 20%

 SO2 Removal % 20% 20% 20% 20% 20% 20%

 Flue Gas Handling % 20% 20% 20% 20% 20% 20%

 Waste / Byproduct % 20% 20% 20% 20% 20% 20%

 Support Equipment % 20% 20% 20% 20% 20% 20%

General Facilities by Area (% of Installed Cost)

 Reagent Feed % 10% 10% 10% 10% 10% 10%

 SO2 Removal % 10% 10% 10% 10% 10% 10%

 Flue Gas Handling % 10% 10% 10% 10% 10% 10%

C-29
Table C-15. CUECost Example - Input Data for Analysis (JH Campbell, Michigan)

 Waste / Byproduct % 10% 10% 10% 10% 10% 10%

 Support Equipment % 10% 10% 10% 10% 10% 10%

Engineering Fees by Area (% of Installed Cost)

 Reagent Feed % 10% 10% 10% 10% 10% 10%

 SO2 Removal % 10% 10% 10% 10% 10% 10%

 Flue Gas Handling % 10% 10% 10% 10% 10% 10%

 Waste / Byproduct % 10% 10% 10% 10% 10% 10%

 Support Equipment % 10% 10% 10% 10% 10% 10%

NOx Control Inputs

Selective Catalytic Reduction (SCR) Inputs

NH3/NOX Stoichiometric Ratio NH3/NOX 0.7-1.0 0.9 D D D DD

NOX Reduction Efficiency Fraction 0.60-0.90 0.70 0.9 0.9 0.9 0.9 0.9

Inlet NOx lbs/MMBtu 0.9 0.27 0.5225 0.3624 0.3624 0.3624

Space Velocity (Calculated if zero) 1/hr 0 D D D DD

Overall Catalyst Life years 2-5 3 D D D DD

Ammonia Cost $/ton 206 D D D DD

Catalyst Cost $/ft3 356 D D D DD

Solid Waste Disposal Cost $/ton 11.48 D D D DD

Maintenance (% of installed cost) % 1.5% D D D DD

Contingency (% of installed cost) % 20% D D D DD

General Facilities (% of installed cost) % 5% D D D DD

Engineering Fees (% of installed cost) % 10% D D D DD

Number of Reactors integer 2 D D D DD

Number of Air Preheaters integer 1 D D D DD

Selective NonCatalytic Reduction (SNCR) Inputs

Reagent integer 1:Urea 2:Ammonia 1 D D D DD

Number of Injector Levels integer 3 D D D DD

Number of Injectors integer 18 D D D DD

Number of Lance Levels integer 0 D D D DD

Number of Lances integer 0 D D D DD

Steam or Air Injection for Ammonia integer 1: Steam, 2: Air 1 D D D DD

NOX Reduction Efficiency fraction 0.30-0.70 0.50 0.35 0.35 0.35 0.35 0.35

Inlet NOx lbs/MMBtu 0.9 0.27 0.5225 0.3624 0.3624 0.3624

NH3/NOX Stoichiometric Ratio NH3/NOX 0.8-2.0 1.2 D D D DD

Urea/NOX Stoichiometric Ratio Urea/NOX 0.8-2.0 1.2 D D D DD

Urea Cost $/ton 225 D D D DD

Ammonia Cost $/ton 206 D D D DD

Water Cost $/1,000 gal 0.4 D D D DD

Maintenance (% of installed cost) % 1.5% D D D DD

Contingency (% of installed cost) % 20% D D D DD

General Facilities (% of installed cost) % 5% D D D DD

Engineering Fees (% of installed cost) % 10% D D D DD

Low NOX Burner Technology Inputs

NOX Reduction Efficiency fraction 0.15-0.60 0.35 D D D DD

Boiler Type T:T-fired, W:Wall T D D D DD

Retrofit Difficulty

L:Low, A:Average, 

H:High A D D D DD

Maintenance Labor (% of installed cost) % 0.8% D D D DD

Maintenance Materials (% of installed cost) % 1.2% D D D DD

Natural Gas Reburning Inputs

NOX Reduction Efficiency fraction 0.55-0.65 0.61 D D D DD

Gas Reburn Fraction fraction 0.08 - 0.20 0.15 D D D DD

Waste Disposal Cost $/ton 11.48 D D D DD

Natural Gas Cost $/MMBtu 2.31 5 5 5 55

Maintenance (% of installed cost) % 1.5% D D D DD

Contingency (% of installed cost) % 20% D D D DD

General Facilities (% of installed cost) % 2% D D D DD

Engineering Fees (% of installed cost) % 10% D D D DD

C-30
Table C-16. CUECost Example - Results Output of Analysis

(JH Campbell facility, Michigan)

SUMMARY OF COSTS

Description Units Boiler 1 Boiler 2

APC Technologies

NOx Control SCR SNCR

Particulate Control PJFF PJFF

SO2 Control LSFO LSD

NOx Control Costs SCR SNCR

Total Capital Requirement (TCR) $ $29,284,539 $3,945,946

$/kW $112.6 $11.1

First Year Costs

 Fixed O&M $ $407,517 $117,261

$/kW-Yr 1.57 0.33

Mills/kWH 0.23 0.05

$/ton NOx removed $109 $66

 Variable O&M $ $2,738,948 $1,306,727

$/kW-Yr 10.53 3.68

Mills/kWH 1.56 0.52

$/ton NOx removed $733 $739

 Fixed Charges $ $4,386,824 $591,103

$/kW-Yr 16.87 1.67

Mills/kWH 2.50 0.23

$/ton NOx removed $1,174 $334

 TOTAL $ $7,533,289 $2,015,091

$/kW-Yr 28.97 5.68

Mills/kWH 4.30 0.80

$/ton NOx removed $2,016 $1,140

Levelized Current Dollars

 Fixed O&M $/kW-Yr 1.91 0.40

Mills/kWH 0.28 0.06

$/ton NOx removed $133 $81

 Variable O&M $/kW-Yr 12.83 4.48

Mills/kWH 1.90 0.63

$/ton NOx removed $893 $900

 Fixed Charges $/kW-Yr 19.03 1.88

Mills/kWH 2.82 0.26

$/ton NOx removed $1,325 $377

 TOTAL $/kW-Yr 33.77 6.76

Mills/kWH 5.01 0.95

$/ton NOx removed $2,350 $1,358

Levelized Constant Dollars

 Fixed O&M $/kW-Yr 1.57 0.33

Mills/kWH 0.23 0.05

$/ton NOx removed $109 $66

 Variable O&M $/kW-Yr 10.53 3.68

Mills/kWH 1.56 0.52

$/ton NOx removed $733 $739

 Fixed Charges $/kW-Yr 13.18 1.30

Mills/kWH 1.86 0.17

$/ton NOx removed $875 $249

 TOTAL $/kW-Yr 25.28 5.31

Mills/kWH 3.66 0.74

$/ton NOx removed $1,717 $1,054

SO2 Control Costs LSFO LSD

Total Capital Requirement (TCR) $ $93,491,840 $83,537,509

$/kW $360 $235

First Year Costs

 Fixed O&M $ $5,268,554 $4,777,549

$/kW-Yr 20.26 13.46

Mills/kWH 3.00 1.90

$/ton SO2 removed $287.8 $226.3

 Variable O&M $ $5,040,781 $9,157,340

$/kW-Yr 19.39 25.80

Mills/kWH 2.87 3.64

$/ton SO2 removed $275.3 $433.8

 Fixed Charges $ $14,005,078 $12,513,919

$/kW-Yr 53.87 35.25

Mills/kWH 7.99 4.97

$/ton SO2 removed $764.9 $592.8

 TOTAL $ $24,314,412 $26,448,808

$/kW-Yr 93.52 74.50

Mills/kWH 13.86 10.50

$/ton SO2 removed $1,328 $1,253

Levelized Current Dollars

 Fixed O&M $/kW-Yr 24.67 16.39

Mills/kWH 3.66 2.31

$/ton SO2 removed $350.4 $275.6

 Variable O&M $/kW-Yr 23.61 31.41

C-31
Table C-16. CUECost Example - Results Output of Analysis

(JH Campbell facility, Michigan)

Mills/kWH 3.50 4.43

$/ton SO2 removed $335.2 $528.2

 Fixed Charges $/kW-Yr 60.77 39.77

Mills/kWH 9.01 5.60

$/ton SO2 removed $863.0 $668.8

 TOTAL $/kW-Yr 109.05 87.56

Mills/kWH 16.17 12.34

$/ton SO2 removed $1,548.6 $1,472.6

Levelized Constant Dollars

 Fixed O&M $/kW-Yr 20.26 13.46

Mills/kWH 3.00 1.90

$/ton SO2 removed $287.8 $226.3

 Variable O&M $/kW-Yr 19.39 25.80

Mills/kWH 2.87 3.64

$/ton SO2 removed $275.3 $433.8

 Fixed Charges $/kW-Yr 42.07 27.53

Mills/kWH 5.95 3.70

$/ton SO2 removed $570.0 $441.8

 TOTAL $/kW-Yr 81.72 66.79

Mills/kWH 11.83 9.23

$/ton SO2 removed $1,133.1 $1,101.9

Due to the detailed nature of CUECost, the resulting cost effectiveness figures will not 

match exactly to what is reported in Section 5.1.6. However, the differences are 

insignificant and well within the +/- 30% range.

C-32
Public Notice 

Ohio Environmental Protection Agency 

Regional Haze 

State Implementation Plan 

Notice is hereby given that the Director of the Ohio Environmental Protection Agency, 

(Ohio EPA) is submitting Ohio’s Regional Haze State Implementation Plan (SIP) to the 

United States Environmental Protection Agency (U.S. EPA). 

This SIP is being submitted in accordance with the Regional Haze Rule requirements 

contained in Section 51.308 of Part 40 of the Code of Federal Regulations. The goal of the 

Regional Haze Rule is to restore national parks and wilderness areas (Class I areas) to the 

“pristine” condition of atmospheric clarity that would prevail in the absence of human 

impacts by the year 2064. The Regional Haze Rule requires States with Class I areas to 

make reasonable progress towards achieving this goal. Ohio does not contain any Class I 

areas. However, the Regional Haze Rule requires States that do not have Class I areas to 

determine if their emissions may impact other States’ Class I areas. When a State is found 

to impact a neighboring States’ Class I areas they are required to work cooperatively and 

develop a long term strategy for achieving the goal. Ohio’s SIP submittal discusses Ohio’s 

impact on neighboring Class I areas and Ohio’s long term strategy. 

The State of Ohio will request that U.S. EPA review and approve the long term strategy 

and other elements of the SIP. 

 

These actions must be noticed to allow public comment and to satisfy U.S. EPA 

requirements for public involvement in SIP related activities. This notice addresses Ohio 

EPA’s reliance on the emission projections as evidence of having an acceptable long term 

strategy. Written comments may be received on or before February 26, 2009 at the 

following address: 

E-mail: Jennifer.hunter@epa.state.oh.us

Mailing address: Jennifer Hunter 

Ohio Environmental Protection Agency, DAPC 

Lazarus Government Center 

P.O. Box 1049 

Columbus, Ohio 43216-1049 

Phone: (614) 644-3696 

Pursuant to the Code of Federal Regulations Part 40 Section 51.103, a public hearing on 

these rule changes will be conducted as follows: February 26, 2009 at 3:30 PM, in the Ohio 

Environmental Protection Agency Central Office located at 50 West Town Street, Suite 

700, Columbus, Ohio.

All interested persons are entitled to attend or be represented at the hearings and give 

written or oral comments on this action. All oral comments presented at the hearing, and 
all written statements submitted at the hearing or to the above address by the close of 

business on February 26, 2009, will be considered by Ohio EPA prior to final action on this 

submittal. Written statements submitted after February 26, 2009, may be considered as 

time and circumstances permit, but will not be part of the official record of the hearing. 

This SIP is available on Ohio EPA DAPC’s Web page at: 

http://www.epa.state.oh.us/dapc/ for electronic downloading by clicking on “State 

implementation plan” under the “topics” drop-down box. Questions regarding accessing the 

web site should be directed to Arunee Niamlarb at (614) 728-1342; other questions or 

comments about this document should be directed to Jennifer Hunter at (614) 644-3696, 

jennifer.hunter@epa.state.oh.us or mailed to Jennifer Hunter at the above address. 
BEFORE THE OHIO ENVIRONMENTAL PROTECTION AGENCY

PUBLIC HEARING

IN THE MATTER OF:

PLAN TO ADDRESS REGIONAL HAZE

TRANSCRIPT OF PROCEEDINGS

In the above-captioned matter, taken before

Teresa A. Pollard, a Court Reporter and Notary Public

in and for the State of Ohio, at the Ohio EPA, Public

InteresL Center, 50 West Town Street, Suite 600,

Room A, Columbus, Ohio, on Thursday, February 26,

2009, at 3:30 p.m.

RECEIVED

~1AR 16 2009

PiC

Newark, Ohio

(740) 345-B556

1y\~1U:J.QffL\~~

8036 Smoke Road

Pataskala, Ohio 43062

(740) 927-333B

(BOO) 852-6163

Fax (740) 927-3436

e--mail: FraleyCooper@earthlink.net

Columbus, Ohio

(614) 22B-OOH\
1

2

2

IN THE MATTER OF PLAN TO ADDRESS REGIONAL HAZE

APPEARANCES

3 - - -

4 MS. MARY McCARRON, Public Involvement Manager

OHIO ENVIRONMENTAL PROTECTION AGENCY

5 PUBLIC INTEREST CENTER

Lazarus Government Center

6 50 ~Jest Town Street, Suite 700

Columbus, Ohio 43215

7 (614) 644-2.160

8

9

~o

11

2

14

15

~6

17

18

19

20

21

22

23

24

FRALEY, COOPER & ASSOCIATES

(800) 852-6163 (614) 228-0018 (740) 345-8556
3

,--------------------------------------··1

Thursday Afternoon

2

3

4

Session,

MS. McCARRON:

February 26, 2009.

3:30 p.m.

My name is Mary McCarron.

5 I'm public involvement manager at Ohio EPA's Public

6 Interest Center and I'll be presiding over the

7 hearing today. Thank you for taking time to attend

8 the hearing.

9 The purpose of the hearing today is to

10 obtain comments from any interested person regarding

11 Ohio EPA's proposed plan. Ohio EPA has submitted to

12 O.S. EPA a plan that insures emissions from Ohio

13 facilities will not impact visibility ar national

14 parks and wilderness areas. The plan is required by

15 the Federal Regional Haze Rule of 1999 and the Clean

16 Air Act.

17 All interested persons are en~itled to

18 attend or be represented at public hearings such as

19 this. All written and oral comments that we receive

20 as part of the official record will be considered by

21 the Ohio EPA's director.

22 To be included on the official, written

23 comments must be received by the Ohio EPA at the

24 close of bus.i.ness today, February 26, 2009, and can

FRALEY, COOPER & ASSOCIATES

(800) 852-6163 (614) 228-0018 (740) 345-8556
4

1 be e-mailed to Jennifer, J-E-N-N-I-F-E-R, dot,

2 Hunter, H-U-N-T-E-R, at EPA dot STATE dot O-H dot

3 U-S.

4 All written comments submitted for the

5 record receive the same consideration as any oral

6 testimony given today. Written comments submitted

7 after today will be considered as time and

8 circumstances permit but won't be part of the

9 official record for the hearing.

10 I'm going to call folks up in the order that

11 they signed in on the sign-in sheet. If you don't

12 want to submit any comments, just go ahead and say

13 "pass" and we will move on to the next name.

1 4

15

There is no cross-examination of

representatives of Ohio EPA at public hearings. Ohio

16 EPA public hearings such as this afford citizens che

17 opportunity to submit comments on the official

18 record, so we won't be able to answer ques~ions

19 during the public hearing. However! members of Ohio

20 EPA may ask clarifying questions to make sure your

21 testimony is as accurate as possible.

22 I'm gOlng to go ahead and read the names off

23 of people who have registered and if you would like

24 to submit testimony, I Just ask that you state and

FRALEY, COOPER & P,SSOCIATES

(800) 852-6163 (614) 228-0018 (740) 345-8556
5

1 spell your name for the court reporter.

2

3 Wiedeman.

The first person who has signed in is Kathy

4 MS. KATHY WIEDEMAN: Wiedeman.

5 MS. McCARRON: Would you like to submit

6 testimony?

7 MS. KATHY WIEDEMAN: Pass.

8 I would like to make sure that you received

9 written comments that we submitted earlier.

10 MS. McCARRON: Yes.

MS. KATHY WIEDEMAN: Okay.

12 MS. McCARRON: Edward Huffman?

13 MR. EDWARD HUFFMAN: Pass.

14 MS. McCARRON: Okay. And Nachy Kanfer?

15 MR. NACHY KANFER: I will go ahead and

16 submit some comments.

17 MS. McCARRON: Okay. If you can state your

18 name, spell it for the court reporter and then go

19 ahead and proceed.

20 MR. NACHY KANFER: Sure.

21 Did I miss introductions? Were there

22 introductions?

23

24

MS. McCARRON: No, I didn't do

FRALEY, COOPER & ASSOCIATES

(800) 852-6163 (614) 228-0018 (740) 345-8556
II ITt Mary McCarron, obviously. This is

6

2 Jennifer Hunter with DAPC and this is Dana Thompson

3 with DAPC as well.

4 MR. NACHY KANFER: Great.

5 MS. McCARRON: Sorry about that. If you

6 would like to go ahead and proceed with your

7 testimony, that would be great.

8 MR. NACHY KANFER: Sure. My name is Nachy

9

10

Kanfer. That's spelled N-A-C-H-Y K-A-N-F-E-R.

I represent the Sierra Club National Coal

Campaign in Ohio. Sierra Club has nearly 20,000

12 members across Ohio. Often our members accompany

13 staff to public hearings. However, when public

14 hearings are held at 3:30 p.m. on weekdays, 11:

15 becomes a little harder.

16 I would like to thank Ohio EPA staff very

17 much for the opportunity to submit these comments.

8 Sierra Club will not be submitting written comments

19 because Sierra Club staff are overworked at the

20

21

moment. So this is all you get.

But let me start vlith, first, a sort of

22 general observation that Ohio EPA's Regional Haze

23 Plan is -- ie's a plan that proposes, basically, to

24 comply with ancther program - that being the Clean

FRALEY, COOPER & ASSOCIATES

(800) 852-6163 (614) 228-001.8 (740) 345-8556
1 Air Interstate Rule - and not much beyond that.

7

2 does require the installation of controls on one

3 facility in Ohio but Ohio EPA should really be taking

4 further steps. It should be requiring controls on

5 existing electric generating units, of which there

6 are many in Ohio including many very polluting ones,

7 and other sources and addressing proposed sources as

8 well, including the AMP-Ohio generating station.

9 that is in order -- if we really are to achieve all

10 of the public health benefits, the air quality

11 benefits, visibility benefits and obviously our

12 national parks, that really full compliance with this

13 Regional Haze Program, the Regional Haze Rule, can

14 achieve.

l5 So first I would point out that Ohio EPA is

16 really acknowledging that it's only seeking to do the

1. 7 bare minimum here. For example, on page 20 there's a

18 sentence whi e Ohio has made the decision that CAIR

19 will suffice for their control. You know, there I S DO

20 acknovJledgment, there! s no real av,Jareness that the

21 State should not simply be aiming for a bare minimum

22 but should be working to achieve the maximum

23 reductions In air emissions especially air emlSSlons

24 that reduce visibility in Class I areas.

FRALEY, COOPER & ASSOCIATES

(800) 852-6163 (614) 228-0018 (740) 345-8556
1

8

As another example, on page 35, right --

2 this document, this is the Regional Haze SIP by the

3 way. We are talking about the loca~ions that are

4 most highly impacted by Ohio sources - such as Dolly

5 Sods, for example, in West Virginia - and the

6 document shows satisfactory progress. Well, the term

7 "satisfactory" is subjective of course.

8 Ohio EPA should be aiming to show that there

9 is maximum progress allowed by the that can be

10 achieved under the Regional Haze Rule, under BART

11 controls.

12 Secondly, I would say that it is

13 inappropriate to use CAIR in general as an excuse for

14 not engaglng in plant specific ccntrol. CAIR is a

15 cap and trade program that allows decreases and

16 increases in emissions across an area of 28 states,

right, that are covered. BART and other programs

18 require plant specific controls. So, its

19 inappropriate to avoid BART obligations by simply

20 claiming that BART eligible EGUs and BART eligible

21 other sources that are not EGOs will be made to

22 comply with CAIR. That!s not a sufficient excuse.

I would also say that looking at various

24 answers on pages 27 and 31, there are these

FRALEY, COOPER & ASSOCIATES

(800) 852-6163 (614) 228-0018 (740) 345-8556
9

1 statements, right, controlling EGUs beyond CAIR

2 control levels would have the most effect on

3 visibility improvement. And again, modeling

4 indicated that significant beyond-CAIR reductions

5 from EGUs - especially for sulphur dioxide - would be

6 the most effective control for improving visibility.

7 The plan fails to justify not requiring

8 those beyond-CAIR controls. Ohio EPA should be

9 evaluating on a plant-by-plant basis whether

10 plant-speoific BART controls are justified at each of

these 37 EGUs identified on page, I believe it was -

12 sorry - page 20 here. It lists all the electric

13 generating stations in Ohio and -- yes, Ohio EPA

14 should be justifying its decision to not establish

15 BART controls on each one of these.

16 One other major concern is that the modeling

17 that Ohio EPA is relying upon here doesn't include

18 any proposed new sources in Ohio. One that's most

19 obviously apparent, of course, is the AI'1P-Ohio

20 generating station proposed for Meigs County. Those

21 new sources will impact visibility - assumlng they're

22

23

built - they will impact visibility.

impac~ other things in Class I areas

They will

Dolly Sods,

24 Shenandoah, other various areas east of here. They

FRALEY, COOPER & ASSOCIATES

(800) 852-6163 (614) 228-0018 (740) 345-8556
10

1 need to be factored into the plan.

2 I would also add that Ohio EPA, in general,

3 should be addressing those Class I impacts when the

4 permitting process for those new scurces takes place.

5 And, finally, let me just point out thae:: --

6 this isn't really my area of expertise, but looking

7 at the non-EGU source, this Glatfelter facility, Ohio

8 EPA has really failed to justify why they're not

9 requiring maximum reduction of 302 emissions. We

10 have these three possibilities of control

11 technologies, and they are capable of 90 percent, 90

12 percent and 60 percent removal of S02 respectively.

13 The company, unsurprisingly, chooses the 60 percent

14 removal and Ohio EPA concurs. Well, that -- there I s

15 really no justification of that written in the plan.

16 \fI,ie believe, Sierra Club believes, that

17 ninety percent removal of S02 is best available and

18 should be achieved through that -- either one of

19 those two control technologies.

20 That concludes my comments.

21 MS. McCARRON: Okay. Thank you.

22 At this point there is nobody else who would

23 like to submit comments, so we will go off the record

24 until four o'clock to see if there are any late

FRALEY, COOPER & ASSOCIATES

(800) 852-6163 (614) 228-0018 (740) 345-8556
1

2

3

4

comers.

(Recess taken.)

11

5

6 record.

[Vis. [VicCARRON: We will go back on the

7 At this point, I donlt see any other

8 requests for testimony. I am just going to remind

9 you that written commen~s are due by the close of

10 business today, February 26. Thanks for attending.

11

~2

13

14

15

16

18

19

20

21

22

23

24

The time is now 4:00 p.m. and this hearing

adjourned.

Thereupon, at 4:00 p.m., on Thursday,

February 26, 2009, the hearing "las concluded.

___________________J

FRALEY, COOPER & ASSOCIATES

(800) 852-6163 (614) 228-0018 (740) 345-8556
12

1

2 STATE OF OHIO

SS:

3 COUNTY OF FRANKLIN

4

I, Teresa 1'1.. Pollard, a Notary Public in and

5 for the State of Ohio, duly commissioned and

qualified, do hereby certify that the aforesaid

6 proceeding on February 26, 2009, was by me reduced to

stenotype and afterward transcribed upon a compu~er;

7 that the foregoing is a true and correct transcript of

the proceedings; that the proceeding was taken at the

8 time and place in the caption specified and was

adjourned; and that I am in no way related to or

9 employed by any attorney or party hereto, or

financially interested in the action . ., n ..lU

IN WITNESS WHEREOF, I have hereunto se~ my

11 hand and affixed my seal of office at Columbus, Ohio,

on this 7th of March, 2009.

12

13

14

15

16

17

18

19

TERESA A. POLLARD

NOTARY PUBLIC-STATE OF OHIO

20 My Commission Expires: October 21, 2012.

21

22

23

24

FRALEY, COOPER & ASSOCIATES

(800) 852-6163 (614) 228-0018 (740) 345-8556

In the matter of: Plan to Address Regional Haze, taken 011 February 26, 2009

Page I

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let 6:21 10:5

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Fraley, Cooper & Associates (614) 228-0018 (800) 852-6163 (740) 345-8556
In the matter of: Plan to Address Regional Haze, taken on February 26, 2009

Page 2

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Fraley, Cooper & Associates (614) 228-0018 (800) 852-6163 (740) 345-8556
GLATFELTER

Beyond Paper

February 26, 2009

Ms. Jennifer Hunter

Ohio EPA, Division of Air Pollution Control

Lazarus Government Center

50 West Town Street, Suite 700

Columbus,OH 43215

Re: Ohio's State Implementation Plan (SIP) for Regional Haze

Dear Ms. Hunter:

P.H. Glatfelter Company - Chillicothe Facility (Glatfelter) is pleased to provide the following

comments on Ohio's State Implementation Plan (SIP) for Regional Haze. Glatfelter's facility

includes two (2) sources that are specifically identified in the SIP as affected units that must

comply with the requirements of Best Available Retrofit Technology (BART). The Chillicothe

facility and Ohio EPA have worked cooperatively for a number of years on these requirements

and Glatfelter appreciates the efforts and considerations of your staff.

1. Control Technology

The SIP identifies the Overfire Air and Sorbent Injection System (OASIS) as BART (page 21 of

37). OASIS is one technology that was evaluated in the Engineering Analysis process. Glatfelter

is prepared to accept that the emission levels achieved by OASIS can serve as BART; however,

as indicated in Appendix 0, Glatfelter should be permitted to select alternative technologies or

strategies that achieve emission levels equivalent or better than levels based on the control

capabilities of OASIS.

The SIP identifies (page 22 of 37) the demonstration of compliance with the daily emission

limitation by December 31,2012. On July 6,2005, US EPA published Appendix Y of 40 CFR

Part 51 "Guidelines for BART Determinations under the Regional Haze Rule". Section V

Enforceable Limits/Compliance specifies that compliance limits are required no later than five

years after EPA approves the Regional Haze SIP. The Regional Haze SIP was due by

December 17, 2007; however, Ohio EPA submitted their Regional Haze SIP on December 31,

2008, and US EPA has up to one year to approve Ohio's SIP. This would give Glatfelter only up

to three years to attain compliance with these new limits. This would be less time than the SIP

provides for electric generating units to meet BART requirements by complying with EPA's Clean

Air Interstate Rule ("CAIR"), which phases in tighter emission limits for a higher-emitting range of

sources by the year 2015.

In addition, the US EPA is expected to impose additional requirements that may also impact

these sources and the selection of appropriate control technology. One such regulation is the

Environmental Department 401 South Paint Street • Chillicothe, OH 45601-0997 U.S.A. • Phone 740-772-3037' Fax 740 772-0014

www.glatfelter.com
Ms. Jennifer Hunter

February 26, 2009

Page 2

vacated Industrial Boiler MACT (40 CFR Part 63, Subpart DDDDD). That regulation will likely

impose emission control requirements for a range of hazardous pollutants which could very well

affect the cost or effectiveness of the ,BART controls if those controls are not designed to reflect

the ultimate Boiler MACT requirements as well.

Given the delay in the submittal and approval of the SIP, and the uncertainty of US EPA's

response as well as potential future upcoming regulations such as the Boiler MACT rule, it is

impossible to adequately design, order, and install control equipment by the date suggested.

Glatfelter urges Ohio EPA to require compliance no earlier than the full five (5) years after US

EPA approval, as afforded by Appendix Y. That schedule would still be well within the 2018

timeframe set out for SIP reassessment.

3. Economic Conditions

As mentioned in the Long Term Strategy (page 27 of 37), the current bleak economic condition in

Ohio precludes justifying additional haze reductions covering a range of additional sources. The

economic conditions in Ohio and across the United States are unprecedented. When Glatfelter

submitted its BART Engineering Analysis to the Ohio EPA in the fall of 2007, the economic

conditions were quite different. Due to these unfortunate and impactful economic times,

Glatfelter's Cost Impact Evaluation and Financial Analyses included in the Engineering Analysis

(Appendix G) must be reconsidered. Glatfelter should be given the opportunity to reevaluate the

cost impact and resubmit the reevaluation for consideration.

Glatfelter appreciates your considera~ion of these comments and looks forward to further working

with Ohio EPA on these requirements. Glatfelter reserves the right to submit future comments on

the SIP as permitted and on the anticipated revised permit-to-install for the affected units.

Should you have any questions concerning these comments, please contact me at 740.772.3387.

Sincerely,

Kathy Wiedeman

Director, Environmental, Health and Safety

KAW:tc

File 3.28,1

c: Skip Missimer - Global Director, Environmental Affairs
IN REPLY REfER TO·

United States Department ofthe Interior

NATIONAL PARK SERVICE

Air Resources Division

P.O. Box 25287

Denver, CO 80225

(0/

February 26, 2009

N36I5 (2350)

Mr. Robert Hodanbosi

Director, Ohio EPA Division ofAir Pollution Control

P.O. Box 1049

Columbus, Ohio 43216-1049

Ms. Cheryl Newton

Air and Radiation Division

U.S. EPA Region 5

77 WestJackson Boulevard (A-18J)

Chicago, lllinois 60604

Dear Mr. Hodanbosi and Ms. Newton:

MAR 102009

This letter acknowledges that the U.S. Department of the Interior, U.S. Fish and Wildlife

Service (FWS), and National Park Service (NPS) have received and conducted a substantive

review of the Ohio revised proposed Regional Haze Rule implementation plan, dated

December 31, 2008. Since this plan has already been submitted to the U.S. Environmental

Protection Agency, Region 5, (EPA) we are providing comments to both the State and EPA.

As outlined in a letter to all States, dated August 1, 2006, our review of the regional haze

protection plan revisions focuses on eight basic content areas that are priorities for the federal

land management agencies. In addition to issues related to content, we are concerned that

Ohio did not provide adequate time for federal land manager consultation on their plan before

submitting their revisions to EPA. As noted in the enclosed comments, we have serious

concerns regarding the adequacy of the plan revisions to address the requirements of 40 CRF

51.300-308. We believe the plan would have been improved through consultation.

Section 40 CFR 51.308(i)(3) requires a State's response to comments received during

consultation with a federal land manager. Since the plan has already been submitted to EPA,

we would appreciate a commitment from the State and EPA Region 5 to work together to

respond to our concerns, and revise the plan as appropriate, before EPA takes any action

regarding approval. Assuming the necessary plan revisions would be subject to public notice

and comment, our concern regarding inadequate consultation on this plan would be alleviated.
2

If you or your staff have any concerns or questions regarding the enclosed comments, please

contact Bruce Polkowsky (NPS Air Resources Division) at (303) 987-6944, or Tim Allen

(FWS Branch of Air Quality) at (303) 914-3802.

We appreciate the opportunity to work closely with EPA Region 5 and the State of Ohio to

improve the plan as submitted to provide significant improvement in our nation's air quality

values and visibility.

Sincerely,

Christine L. Shaver

Chief, Air Resources Division

National Park Service

Enclosure

cc:

Ms. Jelmifer Hunter

Ohio EPA Division of Air Pollution Control

P.O. Box 1049

Columbus, Ohio 43216-1049

John Summerhays

Air and Radiation Division

U.S. EPA Region 5

77 West Jackson Boulevard (A-18J)

Chicago, Illinois 60604

Sincerely,

Sandra V. Silva

Chief, Branch of Air Quality

U.S. Fish & Wildlife Service
National Park Service and U.S. Fish and Wildlife Service Comments Regarding

Ohio Regional Haze Rule State Implementation Plan Submitted to EPA in

December 2008

On December 31, 2008, the State of Ohio submitted a Regional Haze Rule State

implementation plan (SIP), pursuant to the requirements codified in federal rule at 40

CFR 51.300-308, to the U.S. Environmental Protection Agency, Region 5 (EPA). The

Department of the Interior, National Park Service (NPS) and the U.S. Fish and Wildlife

Service (FWS) received a copy of the submittal on January 5, 2009. The NPS and FWS

air programs have conducted a substantivc review of the submitted plan, and provide the

comments listed below. We look forward to working with EPA and thc Ohio Department

of Air Pollution Control (ODAPC) on revisions to the submitted plan. We note that such

revisions would scrve as an alternative to responses required under section 40 CFR

51.308(i)(3). For further information regarding these comments, pleasc contact Bruce

Polkowsky (NPS) at (303) 987-6944 or Tim Allen (FWS) at (303) 914-3802.

OVERALL COMMENT

We provided the State informal comments on the draft regional haze SIP via email on

October 15, 2008. Some of our concerns have been addressed by the SIP submitted to

EPA in late December. However, the SIP as submitted does not address all ofthe issues

we raised in our infonnal comments.

SPECIFIC COMMENTS

The remaining comments, below, are organized according to the priorities that we

presented in our August I, 2006, letter, which outlined the Regional Haze concepts that

are of importance to the NPS and FWS.

Baseline, Natural Condition, and Uniform Rate

We appreciate the statement in the SIP that ODAPC accepts the Midwest Regional

Planning Organizations (MWRPO) assessments of baseline and the use of U.S. EPA

defaults for natural conditions (page 4). We had raised the lack of this acknowledgment

as a major concern in earlier comments.

Emission Inventories

The December 2008 SIP greatly expanded the discussion of emissions inventories and

projections from the October 2008 draft. The State should clarify if these are the

emissions reductions used by MWRPO in the assessment of visibility change referenced

in Chapter 7 and explain any differences.

The projected emissions reductions are based on "on-the-books" controls which should

be elaborated upon in the long-term strategy section of the regional haze SIP. Specific

listing of the other rule and requirements within the regional haze portion of the SIP
provides linking mechanism so that changes in other programs require a review of the

regional haze portion of the SIP as well. The long-term strategy should also contain a

requirement for tracking and reporting on the progress of these programs to ensure that

they fulfill the expected result of satisfying Ohio's obligation to contribute to reasonable

progress a Class I areas influenced by the emissions from the State.

Area of Influence

The December 2008 SIP does identify which Class I areas are affected by emissions from

Ohio by summarizing contribution assessment work of the MWRPO, the Visibility

Improvement State and Tribal Association of the Southeast (VISTAS), Mid Atlantic and

North East Visibility Union (MANE-VU) regional planning organizations. The Ohio SIP

must address all emissions which are "reasonable anticipated to cause or contribute to"

visibility impairment in any Class I areas. We request a summary statement be added to

this section that acknowledges Ohio's responsibility for assisting in continued reasonable

progress in the identified Class I areas. The area ofinfluence information should also be

used in the long-term strategy decision on what control strategies are appropriate for

"reasonable progress" as noted below.

Reasonable Progress Goals and Long Term Strategy

The Long Term Strategy and Reasonable Progress section of the December 2008 SIP is

greatly improved from the previous draft. We appreciate the discussion of EPA's Clean

Air Interstate Rule (CAIR) and understand that the majority of Ohio's long-term strategy

relies on reductions expected from implementation of that rule. We note that the recent

court ruling on CAIR still leaves large uncertainty regarding the magnitude and location

of emissions reductions to be implemented under that program. We request that ODAPC

acknowledge this uncertainty regarding the emissions projections for its sources and that

the SIP commit the State to re-examine actual and future emissions changes in the midterm review required by the regional haze rule. At that time ifin-state emissions for 2018

are likely to fall short of projections adopted in this plan, the ODAPC must initiate plan

revisions for the long-term strategy. Ohio could list possible measures, such as those

found cost-effective under the MWRPO reasonable progress assessment, conducted by

EC/R Incorporated for consideration in future SIP revisions, should anticipated

reductions from on-the-books programs fall short of established goals.

We recognize that most difficult process within the regional haze SIP dcvelopment is

addressing reasonable progress for all Class I areas affected by emissions from a State.

On pages 28 through 37, the SIP reviews ongoing programs and assesses CUiTent and

future contribution to visibility impairment as the basis for relying on on-the-books

controls for this first regional haze plan. Much of the cost information noted in the SIP

comes from the MWRPO reasonable progress analysis. That information was develop

based on regional control options and focused on the Class I areas in the upper mid-west.

The study may not reflect costs regarding additional controls for speciflc Class 1 areas

outside ofthe MWRPO.

2
Fire

We recognize that prescribed fire and wild fire are not currently a major portion of

visibility impairment at Class I areas affected by emissions from Ohio. We appreciate

the ODAPC's efforts to develop a smoke management program. We encourage ODAPC

to include Class I areas as sensitive receptors when assessing smoke impacts under the

future program and to require best management practices to reduce impacts when

sensitive receptors are affected.

Regional Consistency

The SIP mentions the MANE-VU request for cooperation in assisting their states to meet

what they consider to be reasonable progress regarding reductions in sulfur dioxide

emissions. The MANE-VU request is directed at specifie staeks located at coal-fired,

eleetric generating facilities, and includes a general reduction target for S02 emissions

from all point sources. The MANE-VU request acknowledges that their request could be

met using a combination of electric utility reductions and other rcductions. ODAPC

should list reductions expectcd at the facilities identified by MANE-VU and calculate

whether additional controls at other facilities meet the additional sulfur reduction targets

noted in the MANE-VU request.

All State SIPs for regional haze protection mnst address the goal of protecting the 20

percent best visibility days at Class I areas potentially affected by emissions from within

the State. We request Ohio to recognize, in the regional haze SIP, the requirements of

full consultation with the federal land managers for review of visibility impacts required

by New Source Review and Prevention of Significant Deterioration (NSRJPSD)

programs. Given the long range effect major sources can have on visibility, the regional

haze rules should establish a policy that ODAPC will consult with federal land managers,

for all sources subject to NSR/PSD requirement, early in the permitting process.

We are also concerned that Ohio EPA's current approved SIP is deficient with respect to

visibility protection under New Source Review, because it lacks Federal Land Manager

(FLM) notification and consultation procedures that are identified in federal EPA

regulations (see 40 CFR 52.2I(p) and 40 CFR 51.307) for new sources of air pollution

that may impact mandatory federal Class I areas. Specifically, thc procedures do not

establish a process by which FLM notification should occur, including what information

should be submitted for FLM review, when this infonnation should be submitted, and

when FLM concerns and agency responses should appear in a public notice. The FLMs

are charged with an "affirmative responsibility" under the Clean Air Act (CAA) to

protect the air quality related values (AQRVs), including visibility, in Class I areas that

we manage. This responsibility places the utmost importance on the FLMs receiving

necessary and timely information from the state air regulatory agcncies, such as Ohio

EPA, in order to make an informed determination.

Regardless ofwhat OH DAPC has currently established in their SIP under OAC 3745-31

for New Source Review, the visibility SIP required by 40 CFR 51.307 must at a

minimum incorporate the FLM consultation procedures found in the federal regulation

3
for the purposes of visibility protection. Our position on this issue has been documented

in detail in our comment letters on several recent PSD permitting actions in Ohio.

Therefore, we ask that you consider these comments and take action to rectify the

procedures established under the Ohio SIP so that it may enable, rather than impede, an

appropriate role for the FLM as provided by the CAA.

Verification and Contingencies

We appreciate the statement on page 34 that ODAPC will enforce all emiSSIons

limitations and control measures used to meet reasonable progress goals through this SIP

action. We interpret this to mean that the overall emissions targets, noted on Pages 5

through 7, and the rules and measures establish to meet them, are enforceable as

requirements for regional haze as well.

Coordination and Consultation

The SIP should contain provisions for ongoing coordination and consultation with the

Federal Land Managers on any future SIP revisions and reporting. The Federal Land

Managers are committed to supporting State progress and will inform the State of our

ongoing monitoring and assessment activitics. While much of this coordination has been

accomplished through the Regional Planning Organizations (RPOs), the future of RPOs

is uncertain and a specific statement of the tasks to be coordinated on will provide better

assurance that all States and Federal Land Managers will be kept up to date over the long

implementation period ofthese rules.

BART

With respect to the decision to accept CAIR as Best Available Retrofit Technology

(BART) for electric utilities, we point out that Ohio still needs to address particulate

matter (PM) emissions from EGU sources in the BART analyses for the regional haze

SIP.

Through interaetion with the MWRPO and the ODPAC over the last year, we have

reviewed the air quality modeling performed to assess sources snbject to BART. We

agree with ODAPC's conclusion that only the P. H. Glatfelter facility is subject to

BART.

We have serious concerns with the BART determination for the Glatfelter facility. The

determination that the least total cost engineering option as BART does not correctly

consider the visibility improvement factor. Neither the SIP language on pages 21-22 nor

Appendix G provides sufficient assessment of the trade-off between total cost and degree

of visibility improvement. On a dollar per ton of emissions reduced basis, the three

engineering solutions are essentially equal, yet the high levels of control eliminate all

days of impact greater than five percent of extinction change while the minimal control,

chosen by the ODAPC as BART, still results in multiple days at multiple Class I areas of

impacts above the contribution threshold. Given equal removal efficiency costs, the

4
option with the greatest improvement in visibility should be selected. Using an air

quality model to back-calculate a BART emission limit violates the intcnt of the BART

determination, which should be primarily an engineering determination. This is

especially true when all BART control options have equivalent cost per ton emission

reductions.

We also caution that the current assessment of visibility effects at from the Glatfelter

facility with the 60 percent reduction scenario did not appear to include impacts from

condensable particulates that may be substantially greater than those from the filterable

particnlates modeled. For several years we have posted recommendations on our website

for speciating particulates using EPA emission factors. In order for ODAPC to exempt

the Glatfelter facility from BART, it must show that that Glatfelter's impacts do not

exceed the visibility exemption thresholds whcn all visibility impairing emissions are

modeled appropriately. The documentation included with the SIP does not make such a

showing. Even if such a demonstration is succcssful, establishment of emissions limits

needed to remove the Glatfclter facility from consideration for BART must address these

emiSSIOns.

The source can take voluntary emissions limits to reduce its impact below the threshold

that triggers BART assessment. However, those emissions limits are not BART. In

addition those emissions limits should be met more quickly than the five year

implementation period for a BART-determined limit. Such an approach also nceds

recognize that reasonable progress requirements would likely require review additional

emission reductions at that source, since such emissions reductions are likely very costeffective compared with the alternatives.

We request that ODAPC revise the Glatfelter BART determination to be 90 percent

controL If ODAPC does not revise the BART determination, it could establish emissions

limits that removes the source from BART consideration now, but leaves it subject to

review for reasonable progress in the future.

5
USDA United States

Department of

Agriculture

Forest

Service

Eastern Region 626 E. Wisconsin

Snite 800

Milwaukee, WI 53202

Ms. Jennifer Hunter

Environmental Manager State Implementation Plan

(SIP) Development

Ohio Environmental Protection Agency, DAPC

Lazarus Government Center

P.O. Box 1049

Columbus, OH 43216-1049

Dear Ms. Hunter:

File Code: 2580

Date: FEB 2 5 Z009

This is in response to the proposed Ohio Regional Haze Rule State Implementation Plan

(Plan). Since you are the responsible agency, we are providing you our technical review

comments which focus on the eight content areas as outlined in our October 13, 2006, letter to

Bob Hodanbosi. We believe our major concerns in bold typeface warrant further consultation prior

to final adoption of the Plan.

The Forest Service has a new Air Resource Management Team available to work with you and your

staff on all air resource issues. Please add the Air Resources Specialist for Ohio, Edward Huffman at

(304) 636-1800 xl920r elhuffman@fs.fed.us,toyourFederalLandManagerlist. As required in the

Code of Federal Regulations, consultation and collaboration with our Agency can be maintained

through Mr. Huffman.

We look forward to working with you to improve air quality values, including progress towards the

visibility goal set by Congress for our Class I areas. In spite of our legal involvement in this process,

it is our understanding that only the United States Environmental Protection Agency can make a

determination about the document's completeness and provide final approval.

We would appreciate a response to this letter and our comments per Code of Federal Regulations

(CFR) listed in section 40 CFR 51.308(i)(3). Please contact Mr. Huffman if you have technical

questions about the substance of our comments.

Sincerely,

'"

ORe~;lri ~ib;,;,;~ ~~rester

Enclosures (2)

cc: Ann Acheson, Edward L Huffman, Richard Gillam, Paul Stockinger, Scott A Copeland,

John Summerhays, Cheryl Newton

Caring for the Land and Serving People

#!'<

Printed on Recycled Paper ..,
Enclosure 1

USDA Forest Service Comments Regarding

Ohio Draft Regional Haze Rule State Implementation Plan (SIP)

February 24, 2009

The air program staff of the Forest Service conducted a substantive review ofthe Ohio draft

Regional Hazc State Implementation Plan and has provided the comments listcd below. We look

forward to the Ohio Environmental Protection Agency response as required in the Code of

Federal Regulations (CFR) per section 40 CFR 51.308(i)(3). For further information regarding

these comments, please contact Edward Huffman (304) 636-1800 x 192 or Scott Copeland at

(307) 332-9737. The comments below are categorized by the emphasis areas outlined in our

letter to Mr. Hodanbosi (10/13/2006). That lettcr discussed our perspectives relevant to Regional

Haze SIP preparation.

Overall Conm1ents:

We are interested in the Ohio Regional Haze SIP because Ohio sources have been shown to

affect visibility in Forest Service Class I areas in the states of Vermont, New Hampshire,

Missouri, Arkansas, West Virginia, and Virginia (see Table 14, Regional Air Quality Analyses

for Ozone, PM2.5, and Regional Haze: Final Technical Support Document dated April 25, 2008,

done by Lake Michigan Air Directors Consortium (LADCO) and included in your SIP.

Specific Comments:

Natural Condition and Uniform Rate (Ohio SIP for Regional Haze p. 4)

• No conm1ents on this section

Emission Inventories (Ohio SIP for Regional Haze p. 5-15)

• The US .Forest Service would like Ohio to commit to annually tracking emissions and

reporting how the projected emissions compare to actual emissions in 2012 and 2018.

• The emission reductions in 2018 for Ohio appear to be rather impressive. Please clarify

the reductions based on known projects (e.g. Clean Air Interstate Rule (CAIR), source

retirements) versus those projected by the Integrated Planning Model.

• Please clarify whether the emissions inventory data in section 6 is the same as that used

in section 7 for the modeling assessment. If not, please explain any differences between

the data in Section 6 and the infoffi1ation provided in the LADCO summary reports

referenced in Section 7. It is also important to understand any differences for future

comparisons with actual emissions in 2012 and 2018 as discussed above.

Area ofInfluence (Ohio SIP for Regional Haze p. 22-26)

• We are pleased that Ohio adopted the work ofthe Midwest Regional Plmming

. organization (MRPO) and listed the potentially impacted Class I areas in the SIP.

Page I of6
USDA Forest Service Comments Regarding

Ohio Draft Regional Haze Rule State Implementation Plan

• The New Hampshire SIP for Regional Haze lists Ohio as impacting both oftheir Class I

areas: Great Gulf Wilderness and Presidential Range-Dry River Wilderness. Ohio

indicates they impact Great Gulf but not the adjacent Presidential Range-Dry River,

Forest Service Class 1areas. As the Mid-AtlanticlNortheast Visibility Union (MANEVU) analysis lumps the two Class I areas and New Hampshire lists Ohio as impacting

both areas please include Presidential Range-Dry River as a "Yes" in the table on page

23.

Reasonable Progress Goals and Long Term Strategy (Ohio SIP for Regional Haze p. 26-35)

• On page 35, Ohio indicates it does not significantly contribute to visibility problems

in the upper Great Lakes, New Jersey, Maine or Missouri, which are areas where

MRPO's analyses show that the uniform rate-of-progress "glide path" will not be

achieved. However, page 36 displays predicted contributions above 2 percent (both

in 2005 and 2018), which is the contribution threshold defined by MRPO. Further,

the table on page 23 displays these same Class I areas as being impacted by

emissions from Ohio. Please explain this discrepancy and further explain Ohio's

rationale for considering these contributions to be insignificant.

• Based on Ohio EPA's data and analysis presented in the SIP, the Forest Service

concludes that Ohio emission sources have a significant effect on visibility within FS

Class I areas in Missouri. These effects occur evcn when Ohio's contribution to

Regional Haze is reduced in the future, as is projected to occur by 2018 (the table on

page 36 shows the impacts are still projected to be greater than the 2 percent

contribution threshold). Please provide additional justification for Ohio's decision

that the existing "on-the-books" controls for Ohio sources represents its "fair share"

of emissions reductions to meet the reasonable progress goalsestablished by

Missouri for its Class I areas. This discussion should specifically explain how the

decision is supported by the Clean Air Act Reasonable Progress factor-analysis.

Please also provide specific information regarding consultation with Missouri on

impacts from Ohio's emission sources.

• We have concerns about the factor-analysis done by Ohio EPA (pages 29-31 and

summarized on page 27). The discussion refers to an analysis done by MRPO

(contained in Appendix F) which is based on an evaluation offour specific Class I

areas in the upper mid-west (Voyageurs, Boundary Waters, Isle Royale, and Seney).

This factor-analysis may not be applicable to the other Class I areas impacted by

emissions from Ohio sources, including the Missouri Class I areas discussed above.

Further, the conclusions and statements within the text are not validated by the

analysis. The analysis and past EPA cost figures actually appear to show that

beyond "on-the-books" controls are justified and cost-effective. There are several

assertions on page 27 highlighting why beyond "on-the-books" controls are not

justified.

o "controlling beyond CArR at this time cannot be justified because Ohio

utilities are still in the process of installing controls for CAIR",

Page 2 of6
USDA Forest Service Comments Regarding

Ohio Draft Regional Haze Rule State Implementation Plan

o "[Industrial, Commercial and Institutional] leI boiler controls arc estimated

to be a little more expensive than [electrical generating unit] EGU controls

and have much less impact on visibility improvements than EGUs", and

o "With the current bleak economic condition in Ohio, pursuing controls on

these other sectors for haze reduction cannot be justified."

These reasons are not relevant issues within a 5-factor analysis as prescribed by

EPA and are not supported by the analysis. Please address beyond "on-the-books"

within the 5-factors and provide the information supporting the analysis. Our

understanding is that the costs presented within the "factor analysis" for beyond-on

the-books-controls for EGUs are in the same range as those for other EPA

regulations.

• Please clarify Ohio's response to MANE-VU's "ASK" from 2007. Vermont and

New Hampshire use emissions reductions from the ASK to show reasonable

progress for the Class I areas in their states (Lye Brook, Great Gulf, Presidential

Range-Dry River Wilderness areas managed by FS).

• We request that Ohio provide language in their SIP linking the Regional Haze and New

Source Review programs and continued FLM coordination between these programs.

Currently there is no mechanism in the SIP to ensure that the emissions from new

stationary sources or major modifications of existing sources will make reasonable

progress toward the national visibility goal (40 CFR 51.307). This could be especially

important for emissions from new sources that were not anticipated in 2018 emission

inventories.

• Page 27 states that ICI boiler controls are more expensive and less effective than controls

on EGUs. However this conflicts with statements on page 30 " .. .lCI controls were

slightly less expensive than control for EGUs on a $/deciview basis... " Please clarify

these statements and the metrics associated with them.

• The section discussing Ohio's share of emission reductions appears to imply that Ohio

needs reductions in other states to meet its own "fair share" of emission reductions (p. 28

section 10.2). "Ohio has determined that itsfair share ofemission reductions needed to

meet reasonable progress constitutes on-the-books controls and other controls that

upwind states will implement, but that are 110t yet in place." Please clarify this sentence

as 40 CFR 51.308(d)(3) does not allow for the use of another State's emission reductions

to be accounted for in Ohio's fair share of emission reductions.

Wildland Fire (Ohio SIP for Regional Haze p. 13, 33-34)

• We are pleased to see that Ohio will be developing a Smoke Management Program. The

Forest Service would like to assist in the development ofsuch a program.

• We agree that smoke from wildfires and prescribed fires is not a significant emission

source for Ohio or a contributor to regional haze in downwind Class I areas at this time.

Regional Consistency (Ohio SIP for Regional Haze p. 2-3)

• There is an inconsistency in Regional Haze SIPs among states, for instance between

Vermont and Ohio. Vermont assumes the MANE-VU ASK is being addressed by Ohio

Page 3 of6
USDA Forest Service Comments Regarding

Ohio Draft Regional Haze Rule State Implementation Plan

and VT includes the associated emission reductions while Ohio has not committed to

these emission reductions. This could lead to Class I areas within MANE-VU states not

meeting reasonable progress goals set by those states. Consultation between Ohio and

other states within MANE-VU that have asked for emissions reductions beyond "on-thebooks" controls has not been resolved.

Verification and Contingencies (Ohio SIP for Regional Haze p. 37)

• There is uncertainty regarding how CAIR might be modified in the future by EPA in

response to the recent court decisions. The number, size and location of new EGU and

non-EGU sources between now and 2018 are also unknown. How will the SIP address

this uncertainty and respond ifin 2012 and/or 2018 conditions are quite different from

those predicted?

We would also like Ohio to consider contingency measures or procedures for unexpected

or unforeseen circumstances; e.g., future emissions are not reduced to the same degree or

in the same geographic area as projected, or emission inventories are incorrect or flawed.

Are there adaptive management or increased review strategies which could be

implemented in those situations?

Coordination and Consultation (Ohio SIP for Regional Haze p. 3-4, 36)

• As part of the SIP and the strategy to implement the SIP, we request that Ohio

express its intent to improve consultation and coordination with all impacted FLMs,

including the Forest Service. For example, the Forest Service did not receive your

original draft plan dated September 9, 2008, until September 12 through a NPS colleague.

We were made aware that the plan was being withdrawn prior to being able to provide

comments on the plan. While we work closely with our counterparts in the Department

ofthe Interior our comments were not addressed in this draft as stated on page 3-4 of

Ohio's SIP. We also did not receive the current SIP until forwarded by the same NPS

colleague. We are disappointed by this lack of coordination and consultation and are

committed to improving this situation.

• Given the withdraw ofthe previous (September 2008) draft and significant changes made

to the current draft ofthe SIP the FLM has not had 60 days to comment prior to the

hearing to be held on February 26,2009. Additionally, we request that Ohio provides

FLM comments and Ohio's response to these comments to the public at or before the

public meeting.

• Also, coordination should occur during SIP revisions (including reasonable progress

reports) and at steps necessary to address adequacy of the SIP.

The EPA has addressed FLM consultation in its September 2006 Question and Answer (Q

and A) document as follows:

Q - What are EPA's expectations and the basisfor consultation requirements regarding

formal consultative procedures? What constitutes effective FLM communication? Can it be

Page 4 of6
USDA Forest Service Comments Regarding

Ohio Draft Regional Haze Rule State Implementation Plan

assumed that ifthe FLM attendl' the RPO meeting,i' and calls and doesn't raise any concerns

it has no problems with a State ',I' SIP?

A - "40 CFR 51,308(i) requires that States consult with FLMs before adopting and

submitting their RH SIPs, These requirements are summarized asfollows:

States must provide the FLM an opportunity for consultation, in person and at

least 60 days prior to holding any public hearing on the SIP. The State must also

provide the opportunity for the FLMI' to discuss their: (i) assessment 0/

impairment a/visibility in any Class I area; and, (ii) recommendations on the

development 0/the RPG and on the development and implementation ofstrategies

to address visibility impairment. Further, the State must include in the SIP a

description a/how it addressed any comments provided by the FLMs. Lastly, the

SIP must provide proceduresfor continuing consultation between the State and

FLMs on the implementation 0/51.308, including development and review a/SIP

revisions and 5-year progress reports, and on the implementation ofother

programs having the potential to contribute to impairment ofvisibility in Class I

areas.

This is aformal consultative process. The basisfor requiring written consultation

procedures is 40 CFR 51.308(i)(4). To satisfY this requirement, States should contact the

FLM~ to ensure their input to the RH SIP process is solicited and documented. While

effective FLM consultation relies on both parties (States and FLMs) communicating early

and often, the State is only required to meet the provisions of40 CFR 51.308(i) and is not

responsible ifa f"'LM chooses not to participate in the either the RPO activities or the SIP

development and review process. In such cases, the State should document its outreach

efforts to the FLM "

Best Available Retrofit Technology (BART) (Ohio SIP for Regional Haze p. 16-22)

We have concerns about the initial analysis to determine sources subject to BART.

The "screen-out" analysis done by LADCO specifies that it uses the Q/D metric for

its analysis (where Q should equal the sum of tons per year of S02 + NOx + PM10 +

H2S04), but in fact a metric of LID was used (where L = tons per year of S02 +

NOx). The change in numerator values could result in fewer emission sources being

considered as subject to BART. Please address whether additional sources would

have been considered had the QID metric been applied instead of LID.

Our understanding of EPA direction is that particulate matter (PM) emissions from

EGU sources should be considered in the BART analysis for the regional haze SIP.

In a September, 2006 Question and Answer (Q and A) document the EPA wrote: "States

subject to andparticipating in the CA1R cap and trade program/or S02 and NOx are

allowed to treat the CA1R requirementsfor EGUs as a substitute for the application of

BART controls per 40 CFR 51.308(e)(4). This does not mean EGUs are exemptfor S02

and NOx, only that CAIR satisfies the BART requirement/or those pollutants. The

Page 5 of 6
USDA Forest Service Comments Regarding

Ohio Draft Regional Haze Rule State Implementation Plan

remaining visibility pollutants to considerfor determining BART-eligible sources are

PM, and, using judgment, VOCs, and ammonia. For PM, the July 6, 2005, final BART

rule at 70 FR 39160 notes PM1 0 may be used an indicatorfor PMin this step ofthe

determination and thus, PM10 can be usedfor the exemption modeling." - Our review

indicates the proposed OH Regional Haze SIP is counter to EPA direction.

We have concerns about the BART control options and the methodology used to

reach a conclusion. The standard approach to determining BART control options is

that it should primarily be an engineering determination not an air quality

modeling exercise. A BART limit is defined as "an emission limitation based on the

degree of reduction achievable through the application of the best system of

continuous emission reduction... ". With regard to the P.H. Glatfelter facility,

please clarify why one of two higher performing control options (90% removal)

should not be considered BART as opposed to the 60% removal proposed by the

company. Our understanding is the cost per ton for each of the final three control

options are essentially equivalent for sulfur dioxide.

Page 6 of6
USDA

~­II

United States

Department of

Agriculture

Forest

Service

Eastern Region 626 E. Wisconsin

Suite 800

Milwaukee, WI 53202

File Code: 2580-2

Date: October 13, 2006

Mr. Bob Hodanbosi

Chief, Division ofAir Pollution Control

Ohio Environmental Protection Agency

P.O. Box 1049

Columbus, OH 43216-1049

Dear Mr. Hodanbosi:

Over the past several years, members of both our staff and yours have participated with neighboring

states and tribes in the Central States Regional Air Partnership to develop best approaches and tools

for preparing plans that will reduce haze in Class I areas. With preparation of your Regional Haze

State Implementation Plan (SIP) at hand, we want to focus on collaboration with you and your staff

to ensure success. As you know, consultation with you is required in the Regional Haze Rule

(RHR). This is a priority for our air program.

Our focus will be on Class I wildernesses, which the United States Department ofAgriculture

(USDA) Forest Service (FS) is responsible for. We are coordinating with the other Class I area

managers, the National Park Service, and the US Fish and Wildlife Service to facilitate a common

message from all federal land managers (FLM). We anticipate leveraging strengths of each FLM to

our joint advantage. Since the FLM will be seeking a close working relationship with every state in

this SIP writing process, the expectation is to share ideas from across the nation. The objective of

every SIP is to playa critical role in a national emissions reduction plan.

Enclosed are detailed perspectives pertinent to the SIP preparation. Any comments or questions

should be directed to Chuck Sams, the principal FS point of contact, at (414) 297-3529 or

9.?lusVi1fs.fed.us. He will consult on your SIP throughout the required 60-day comment period,

sharing our best insights and recommendations. Chuck will also work with others on our staff,

especially our National Haze Coordinator, Aml Mebane and the Department ofInterior. Ann can be

contacted at (307) 587-4597 or amebaneClilfs.fed.us.

As required in the RHR, please identify, at your earliest convenience, your key point(s) of contact.

Send all correspondence electronically to both Trent Wickman and Aml Mebane to ensure a

successful consultation and SIP.

Sincerely,

/s/ Forrest 1. Starkey (for)

RANDY MOORE

Regional Forester

Enclosure

Caring for tbe Land and Serving People

#'!!:

Printed on Recycled Paper ..,
Enclosure 1

Subject: Ohio and Regional Haze Rule Consultation with the United States Department of

Agriculture (USDA) Forest Service (FS)

September 2006

Thefollowing perspectives are merely suggestions or recommendations not direction or

requirements. They are deliberately very similar to those prepared by the Department ofInterior to

contribute to a common sense ofpurpose for improving haze in all Class I areas. We are sending

these perspectives to each state. In so doing, we hope tofacilitate inter-state coordination. At the

same time, wefully acknowledge the discretion afforded in the Regional Haze Rule (RHR) for

unique and creative solutions by individual states in writing plans that reduce haze.

Natural Condition and Uniform Rate

These factors apply mainly to states that have Class I areas. Other states that contribute to visibility

impairment in Class I areas located in a different state might consider including discussion and

conclusions on these factors in their individual plans.

The basic calculation of baseline, natural condition, and unifoffi1 rate builds the foundation for the

entire RHR State Implementation Plan (SIP) process. Considerable discussion and debate at the

science and policy level has occurred regarding appropriate methods to be used. As a consequence,

several equations that include varying parameters or multipliers are available. Because these

calculations can have a significant effect on the resulting progress goal, it is important to provide a

detailed description ofthe methods used in the SIP. Calculations that include only portions of

established methods or utilize unique approaches will be better understood ifthe rationale for these

differences is fully explained in the SIP or its supporting documentation. We encourage states to

use calculations that are based on equations recommended by the Interagency Monitoring of

Protected Visual Environments (IMPROVE) steering committee and that are consistent with

recommended approaches from the pertinent Regional Planning Organization (RPO) and the

Environmental Protection Agency (EPA) region.

Emission Inventories

Given the complexities associated with modern comprehensive emission inventories, spending

some considerable effort in describing how these inventories were developed and used will be

important. Emission descriptions will be most informative ifthey include an evolutionary

discussion that includes an actual, base-year inventory used to evaluate model performance; a

typical base-year inventory that represents the five year, average state which establishes modeled

visibility impacts; and various future year, controlled inventories that demonstrate future visibility

conditions. Consider adding future year inventories that are clearly partitioned to delineate source

types (by text, charts, or graphics) that are included in each model simulation. Benefits to future

visibility conditions suggested in the SIP that are not also clearly linked to a future inventory or are

not clearly included in future model analysis, will warrant additional discussion.

One part of your emission inventory includes the implementation of"Best Available Retrofit

Technology" (BART) on a subset of pre-Prevention of Significant Deterioration sources. The

BART source identification, elimination, and level determination will be of particular interest for

review. We would prefer to see a clear progression through the three basic BART phases and a

thorough description ofthe RHR prescribed factor analysis (if applicable). Consider discussing

whether BART levels apply to individual or grouped source categories.
Area ofInfluence

The area ofinfluence ofsignificant visibility-impairing sources is an important SIP element. We

suggest that that each state clearly identify and apportion by state, or other geographic means, the

significant levels of pollutants contributed to each Class I area by source. Developing this

information together with neighboring States and Tribes will facilitate consistency. Discussions of

changing source area contributions at both the base- and future-year levels will help demonstrate

SIP progress. Consider the benefits of presenting this information in the form oftransported mass

by pollutant or through individualIy calculated visibility impairment measures. Using a percentage

or 'Top 10" ranking for current contributions by geographic area mayor may not clearly describe

progress over time.

Reasonable Progress Goals and Long Term Strategy

Establishing reasonable progress goals for Class I areas in your state and/or acknowledging

reasonable progress goals for Class [ areas in other states that are affected by emissions from your

state, as well as defining associated emissions strategies to meet these goals, form the basis ofthe

SIP process under the RHR.

In developing the statute's required Long Term Strategy (LTS), your state is offered broad

flexibility when determining reasonable progress goals and associated emissions. As noted earlier,

the RHR includes a requirement for states to assess a unifoffil rate of progress and compare that rate

to the reasonable progress goals set by those states with Class I areas. We feel that this unifol1n rate

of progress assessment is useful in determining the geographic and economic extent a state can

consider when developing the LTS associated with the reasonable progress goals.

In general, we will be looking at the degree to which the LTS is supported by RPO technical work

and at the level of consistency among the contributing states. For Class I areas where your state is

setting a year 2018 reasonable progress goal of equal or less impairment compared to the uniform

rate of progress, our review will focus holistically on (I) whether strategies are applied equitably

across source types; (2) ifboth local and regional emission strategies have been fully examined; and

(3) how consistent assessments and strategies are applied regionally.

For Class I areas where the reasonable progress goal is more impaired than the unifoffil rate of

progress, consider presenting information on a component basis. Components could consist Of

emission source category as before, but also include contributions from individual pollutants or by

geographic source area. Our intent is to better understand where and why a strategy falls short of

the uniform progress rate goal.

Because each region has focused their emission control strategy on different conditions, presenting

results in a component fOffilat may assist in showing what level ofprogress was made in the focus

area, verses other less controllable factors.

Wildland Fire

Your state has considerable flexibility as it addresses all anthropogenic sources of visibility

impairment, including fire. The RHR requires consideration ofsmoke management techniques for

agricultural and forestry management practices in the development ofthe LTS part ofthe SIP. On a

short-term basis, fire has the potential to cause significant visibility reduction in Class I areas. If

fire contributes to the index used to track long-term, reasonable progress in a Class I area, the

visibility SIP should identify how it will be addressed. Your state may already have a smoke
management program (SMP) that adequately describes how visibility impailment from fire will be

addressed. Iffire has been determined to contribute to visibility impairment, we suggest including a

fire emissions inventory along with a comment about its reliability and a projection for changes to

the future inventory. If your state has a SMP, is it a basic smoke management program or an

enhanced smoke management plan? And has the SMP been certified by the Environmental

Protection Agency (EPA) Interim Air Quality Policy on Wildland and Prescribed Fire? Identify the

specific SMP requirements for minimizing visibility impairment in Class I areas. Are there

differences in state rcgulation for the way in which smoke from agricultural burning and forest fires

are treated? Is there a difference in the way emissions from wildfire, prescribed fire, and wildlandfire-use (WFU) fire are identified and treated on private, state, and federal lands?

Regional Consistency

The RPOs have been working toward regionally-consistent approaches to address visibility

impairment throughout the SIP development process. There may be circumstances when diffcrent

methods were used or impairment assessments reached different conclusions. The FLM

understands that each state knows what emission control methods or air quality management

strategies work best for its areas. Each state may wish to develop strategies that are independent

from RPO or neighboring areas.

In this context, our review of "regional consistency" will have less to do with individual discretion

each state has in making dccisions, and more on how well a group ofstates identifics and addresses

similar agreed upon goals for each Class I area within a common area ofinfluence.

Regional consistency can also be difficult to evaluate if neighboring SIPs (or portions of SIPs) are

released for review at different times. We expect that thorough inter-state consultation processes

will lead to consistent descriptions of apportionment and emission control goals, thus resulting in

development ofsimilar progress goals, regardless ofrelease dates.

Verification and Contingencies

Little emphasis has been placed in the RHR on verification and even less on contingency planning.

By rule, each SIP must identify the monitoring data used to specify the original baseline and also as

part of an ongoing progress review at five year intervals.

Given the uncertain future of any individual monitoring site, we suggest that the SIP address the

representation of both primary and alternative data sites for each Class I area.

Consider not only the data necessary to measure progress, but also how to account for and mitigate

both unexpected and reasonably foreseeable emissions growth, changes to the geographic

distribution of emissions, and substantive errors that may be found in emission inventories or other

technical bases ofthe SIPs. These factors, as well as other unanticipated circumstances, may

adversely affect your state's ability to achieve the emissions reductions projected by the SIP.

Considering these factors through adaptive management or continual review strategies may assist in

avoiding these circumstances.

Coordination and Consultation

The 1999 RHR requires states to consult with the FLM agencies at least 60 days prior to holding

any public hearing on a RHR, SIP, or SIP revision (40 CFR 5I.308(i). As named in the cover letter

to this enclosure, a single FS air specialist has been assigned to your state.
Page | 1 

Division of Air Pollution Control 

Ohio’s Regional Haze State Implementation Plan Recommendation 

Agency Contact for this Package

Jennifer Hunter, Division of Air Pollution Control, (614) 644-3696, 

jennifer.hunter@epa.state.oh.us

General/Overall Concerns

Comment 1: We are interested in the Ohio Regional Haze SIP because Ohio 

sources have been shown to affect visibility in Forest Service 

Class I areas in the states of Vermont, New Hampshire, 

Missouri, Arkansas, West Virginia, and Virginia (see Table 14, 

Regional Air Quality Analyses for Ozone, PM2.5, and Regional 

Haze: Final Technical Support Document dated April 25, 2008, 

done by Lake Michigan Air Directors Consortium (LADCO) and 

included in your SIP. (USDA Forest Service) 

Response 1: No response necessary. 

Comment 2: Emission Inventories (Ohio SIP for Regional Haze p. 5-15) 

The US Forest Service would like Ohio to commit to annually 

tracking emissions and reporting how the projected emissions 

compare to actual emissions in 2012 and 2018. (USDA Forest 

Service) 

Ohio EPA held a public hearing in Columbus, OH on February 26, 2009, regarding 

the Regional Haze State Implementation Plan recommendations for the State of 

Ohio. This document summarizes the comments and questions received at the public 

hearing and during the associated comment period, which ended on February 26, 

2009. 

Ohio EPA reviewed and considered all comments received during the public 

comment period. By law, Ohio EPA has authority to consider specific issues related 

to protection of the environment and public health. 

 

In an effort to help you review this document, the questions are grouped by topic and 

organized in a consistent format. The name of the commenter follows the comment 

in parentheses. 
Page | 2 

Response 2: Ohio EPA updated Section 12 of the SIP to include Ohio’s 

commitment to periodically update its inventory. However, 

USEPA’s Regional Haze Rule (RHR) does not require annual 

tracking and reporting of emissions as part of this SIP. Rather, the 

RHR requires a “commitment to update the inventory periodically” 

and an analysis of emission changes during the periodic reports 

process. Although Ohio EPA frequently reviews emissions 

reported to Ohio EPA on an annual basis, Ohio EPA believes it is 

reasonable to commit to 3-year updates as part of USEPA’s 

Consolidated Emissions Reporting Rule (CERR) requirements and 

during the periodic reporting process. 

Comment 3: Emission Inventories (Ohio SIP for Regional Haze p. 5-15) 

The emission reductions in 2018 for Ohio appear to be rather 

impressive. Please clarify the reductions based on known 

projects (e.g. Clean Air Interstate Rule (CAIR), source 

retirements) versus those projected by the Integrated Planning 

Model. (USDA Forest Service) 

The projected emissions reductions are based on “on-thebooks” controls which should be elaborated upon in the longterm strategy section of the regional haze SIP. Specific listing 

of the other rule and requirements within the regional haze 

portion of the SIP provides linking mechanism so that changes 

in other programs require a review of the regional haze portion 

of the SIP as well. The long-term strategy should also contain 

a requirement for tracking and reporting on the progress of 

these programs to ensure that they fulfill the expected result 

of satisfying Ohio’s obligation to contribute to reasonable 

progress a Class I areas influenced by the emissions from the 

State. (National Park Service and U.S. Fish and Wildlife 

Service) 

 

Response 3: Emissions from electric generating units (EGUs) are based on the 

Integrated Planning Model as indicated on page 6 of the SIP. Page 

59 of LADCO’s Technical Support Document (TSD) identifies the 

known controls (on-the-books) included in the model for future 

projections: 

A “base” control scenario was prepared for each future 

year based on the following “on the books” controls: 

 On-Highway Mobile Sources 

• Federal Motor Vehicle Emission Control Program, lowsulfur gasoline and ultra-low sulfur diesel fuel 

• Inspection - maintenance programs, including IL’s 

vehicle emissions tests (NE IL), IN’s vehicle emissions 
Page | 3 

testing program (NW IN), OH’s E-check program (NE 

OH), and WI’s vehicle inspection program (SE WI) – 

note: a special emissions modeling run was done for the 

Cincinnati/Dayton area to reflect the removal of the 

state’s E-check program and inclusion of low RVP 

gasoline 

• Reformulated gasoline, including in Chicago-Gary,-Lake 

County, IL,IN; and Milwaukee, Racine, WI 

Off-Highway Mobile Sources 

• Federal control programs incorporated into NONROAD 

model (e.g., nonroad diesel rule), plus the evaporative 

Large Spark Ignition and Recreational Vehicle standards 

• Heavy-duty diesel (2007) engine standard/Low sulfur fuel 

• Federal railroad/locomotive standards 

• Federal commercial marine vessel engine standards 

Area Sources (Base M only) 

• Consumer solvents 

• AIM coatings 

• Aerosol coatings 

• Portable fuel containers 

Power Plants 

• Title IV (Phases I and II) 

• NOx SIP Call 

• Clean Air Interstate Rule 

Other Point Sources 

• VOC 2-, 4-, 7-, and 10-year MACT standards 

• Combustion turbine MACT 

Other controls included in the modeling include: 

consent decrees (refineries, ethanol plants, and 

ALCOA)1

, NOx RACT in Illinois and Ohio2, and BART 

for a few non-EGU sources in Indiana and Wisconsin. 

Ohio EPA will update and include this listing in the long-term 

strategy section. The “Plan Revisions and Progress Reports” 

 

1

 E.H. Pechan’s original control file included control factors for three sources in Wayne County, MI. 

These control factors were not applied in the regional-scale modeling to avoid double-counting with the 

State’s local-scale analysis for PM2.5. 

2

 NOx RACT in Wisconsin is included in the 2005 basecase (and EGU “will do” scenario). NOx RACT in 

Indiana was not included in the modeling inventory. 
Page | 4 

section of the Regional Haze SIP contains a commitment to 

evaluate progress and will be updated with additional clarification 

based on comments consistent with the Regional Haze program 

requirements. 

Comment 4: Emission Inventories (Ohio SIP for Regional Haze p. 5-15) 

Please clarify whether the emissions inventory data in section 

6 is the same as that used in section 7 for the modeling 

assessment. If not, please explain any differences between 

the data in Section 6 and the information provided in the 

LADCO summary reports referenced in Section 7. It is also 

important to understand any differences for future 

comparisons with actual emissions in 2012 and 2018 as 

discussed above. (USDA Forest Service) 

The December 2008 SIP greatly expanded the discussion of 

emissions inventories and projections from the October 2008 

draft. The State should clarify if these are the emissions 

reductions used by MWRPO in the assessment of visibility 

change referenced in Chapter 7 and explain any differences. 

(National Park Service and U.S. Fish and Wildlife Service) 

Response 4: Section 6’s emissions inventories provide references to the data 

sources. The 2002 base year inventory data is intended to be 

actual emissions data (from point and area sources) and was 

obtained for USEPA’s national emissions inventory (NEI). The 

2005 emissions inventory is also based on actual emissions data 

(from point and area sources) as supplied to LADCO by Ohio EPA 

for the purpose of future year modeling. However, as indicated in 

the SIP, for 2005, on-road data (or mobile source emissions) was 

obtained again from USEPA’s NEI. Future year projections for 

2018 are derived by applying growth and control factors to the 2005 

base year inventory as part of LADCO’s modeling. LADCO’s TSD 

and Base M Modeling Strategy report provide additional details on 

inventories and modeling protocols (links to both documents are 

included in the SIP). For the purpose of the modeling discussed in 

Section 7, LADCO used the 2005 inventory (Base M) for modeling 

that produced the results for the inventories in this SIP. The SIP 

document discusses both the 2002 (Base K) and 2005 (Base M) 

inventories although only the 2005 inventory was used for the 

future 2018 projections. Ohio EPA is clarifying this in Section 7. 

Section 6.1, detailed nonpoint source emissions, was compiled 

from the 2002 NEI. As indicated in the text of Ohio EPA’s SIP, 

fugitive dust and road dust nonpoint sources are included in the 

discussion under Section 6.1 but are not included in the 2002, 2005 
Page | 5 

and 2018 inventories. The purpose of which is to allow for 

consideration of fugitive particulate emissions in Ohio. These 

fugitive emissions should not be directly compared to the emissions 

projected in the LADCO modeling. 

Comment 5: We appreciate the statement on page 34 that ODAPC will 

enforce all emissions limitations and control measures used to 

meet reasonable progress goals through this SIP action. We 

interpret this to mean that the overall emissions targets, noted 

on Pages 5 through 7, and the rules and measures establish to 

meet them, are enforceable as requirements for regional haze 

as well. (National Park Service and U.S. Fish and Wildlife 

Service) 

Response 5: The Regional Haze program requires that emissions strategies 

themselves, used for visibility improvement in the Regional Haze 

SIP, must be implemented through an enforceable mechanism 

(e.g., rulemaking incorporated into the SIP such as Ohio’s CAIR 

program, permits issued as draft and then final actions for BART 

sources, etc.). To further clarify, the RHR states: 

“Some commenters expressed concern that the State would 

be subject to sanctions or enforcement actions in the event 

that a State fails to meet a reasonable progress target. As 

noted above, the reasonable progress goal is a goal and not 

a mandatory standard which must be achieved by a 

particular date as is the case with the NAAQS. Once a State 

has adopted a reasonable progress goal and determined 

what progress will be made toward that goal over a 10-year 

period, the goal itself is not enforceable. All that is 

‘‘enforceable’’ is the set of control measures which the State 

has adopted to meet that goal.” 

Comment 6: Area of Influence (Ohio SIP for Regional Haze p. 22-26) 

We are pleased that Ohio adopted the work of the Midwest 

Regional Planning organization (MRPO) and listed the 

potentially impacted Class I areas in the SIP. 

 (USDA Forest Service) 

We appreciate the statement in the SIP that ODAPC accepts 

the Midwest Regional Planning Organizations (MWRPO) 

assessments of baseline and the use of U.S. EPA defaults for 

natural conditions (page 4). We had raised the lack of this 
Page | 6 

acknowledgment as a major concern in earlier comments. 

(National Park Service and U.S. Fish and Wildlife Service) 

Response 6: Thank you. 

Comment 7: The December 2008 SIP does identify which Class I areas are 

affected by emissions from Ohio by summarizing contribution 

assessment work of the MWRPO, the Visibility Improvement 

State and Tribal Association of the Southeast (VISTAS), Mid 

Atlantic and North East Visibility Union (MANE-VU) regional 

planning organizations. The Ohio SIP must address all 

emissions which are “reasonable anticipated to cause or 

contribute to” visibility impairment in any Class I areas. We 

request a summary statement be added to this section that 

acknowledges Ohio’s responsibility for assisting in continued 

reasonable progress in the identified Class I areas. The area 

of influence information should also be used in the long-term 

strategy decision on what control strategies are appropriate 

for “reasonable progress” as noted below. (National Park 

Service and U.S. Fish and Wildlife Service)

Response 7: Based on comments received Ohio EPA will be expanding the Area 

of Influence, Long-Term Strategy and Reasonable Progress, and 

Anticipated Net Effect on Visibility Resulting from Projected 

Changes to Emissions Sections of the SIP document. We 

anticipate the changes will address the comment above. 

Comment 8: Area of Influence (Ohio SIP for Regional Haze p. 22-26) 

The New Hampshire SIP for Regional Haze lists Ohio as 

impacting both of their Class I areas: Great Gulf Wilderness 

and Presidential Range-Dry River Wilderness. Ohio indicates 

they impact Great Gulf but not the adjacent Presidential 

Range-Dry River, Forest Service Class I areas. As the MidAtlantic/Northeast Visibility Union (MANE-VU) analysis lumps 

the two Class I areas and New Hampshire lists Ohio as 

impacting both areas please include Presidential Range-Dry 

River as a “Yes” in the table on page 23. 

 (USDA Forest Service) 

Response 8: Based on a review of the MANE-VU contribution assessment 

report, it appears that the analyses looked at Great Gulf and given 

its proximity to Presidential Range-Dry River, an assumption was 

made if a state impacted Great Gulf, then it also impacted 

Presidential Range-Dry River. This is further supported in the New 

Hampshire SIP which states Great Gulf and Presidential Range - 
Page | 7 

Dry River share a single monitoring site. Each of the other MANEVU Class I areas has its own monitoring site. Ohio EPA believes 

this is a reasonable assumption and will incorporate the requested 

change. 

Comment 9: Reasonable Progress Goals and Long Term Strategy (Ohio SIP 

for Regional Haze p. 26-35)

On page 35, Ohio indicates it does not significantly contribute 

to visibility problems in the upper Great Lakes, New Jersey, 

Maine or Missouri, which are areas where MRPO’s analyses 

show that the uniform rate-of-progress “glide path” will not be 

achieved. However, page 36 displays predicted contributions 

above 2 percent (both in 2005 and 2018), which is the 

contribution threshold defined by MRPO. Further, the table on 

page 23 displays these same Class I areas as being impacted 

by emissions from Ohio. Please explain this discrepancy and 

further explain Ohio’s rationale for considering these 

contributions to be insignificant. (USDA Forest Service) 

Based on Ohio EPA’s data and analysis presented in the SIP, 

the Forest Service concludes that Ohio emission sources have 

a significant effect on visibility within FS Class I areas in 

Missouri. These effects occur even when Ohio’s contribution 

to Regional Haze is reduced in the future, as is projected to 

occur by 2018 (the table on page 36 shows the impacts are still 

projected to be greater than the 2 percent contribution 

threshold). Please provide additional justification for Ohio’s 

decision that the existing “on-the-books” controls for Ohio 

sources represents its “fair share” of emissions reductions to 

meet the reasonable progress goals established by Missouri 

for its Class I areas. This discussion should specifically 

explain how the decision is supported by the Clean Air Act 

Reasonable Progress factor-analysis. Please also provide 

specific information regarding consultation with Missouri on 

impacts from Ohio’s emission sources. (USDA Forest Service) 

Response 9: Ohio EPA will be rephrasing the language in this section. To 

clarify, in most cases Ohio EPA believes the contribution from Ohio 

is small relative to other states. Ohio EPA also believes the 

significant reductions that are expected by 2018 from Ohio’s 

predominant sources (e.g., EGUs) will provide satisfactory 

progress. Furthermore, over the next few years Ohio will be 

preparing for and implementing additional strategies to reduce both 

ozone levels and PM2.5 (and precursor) levels as a part of 

implementation of the new ozone and PM2.5 standards. It is our 
Page | 8 

intent to revisit and reevaluate our Regional Haze commitment 

during our next review period which will follow implementation of 

these new standards. In the meantime, Ohio believes we will 

continue to see the progress that will be needed under the Regional 

Haze program. 

With respect to the MRPO contribution threshold of 2 percent; this 

level was not chosen as a level to determine significance of a 

contribution. Rather, the purpose of the 2 percent level was as a 

minimum threshold for including a state as a contributing state. 

With respect to Missouri, Ohio EPA participated in multi-state 

consultation process regarding its Class I areas specifically in April 

and May of 2007 (see Appendix N of Missouri’s Regional Haze 

SIP). With respect to Ohio’s impact on Class I areas in Missouri, 

Ohio’s SIP shows Ohio’s contributions as follows: 

Mingo: 9% in 2005 and is reduced to 6% by 2018. 

Hercules-Glades: 7% in 2005 and is reduced to 4% by 2018. 

 

As stated above, the MRPO contribution threshold of 2 percent is a 

minimum threshold for contributing and is not intended to indicate 

the significance of the contribution. Ohio maintains that existing 

“on-the-books” controls are representative of Ohio’s “fair share” of 

reductions necessary for Missouri to meet its reasonable progress 

goals. This is further support by Missouri’s SIP. 

 Missouri states in their Regional Haze SIP: 

“Nine states, including Missouri, Arkansas, Kentucky, Illinois, 

Indiana, Ohio, Oklahoma, Tennessee and Texas, were 

identified as contributing to visibility in Mingo and/or 

Hercules Glades Class I areas. The modeling demonstration 

has shown that the emission reductions from these 

contributing states are sufficient to achieve RPGs in 

Missouri’s Class I areas.” 

 And 

“Ongoing air pollution control programs ... are sufficient to 

meet the 2018 Uniform Rate of Progress for the Mingo and 

Hercules Glades Class I areas. These ongoing programs 

such as CAIR, BACT, or BART have been demonstrated to 

be very cost effective in reducing the visibility in Missouri’s 

Class I areas.” 
Page | 9 

Appendix E of Missouri’s SIP identifies Ohio contributing to Mingo 

and Hercules Glades with respect to sulfate but not nitrate. 
Page | 10 

 Missouri is the largest contributor as demonstrated above and 

Missouri states in its SIP that existing programs are sufficient for its 

state and the other contributing states. As further support, the 

largest contributions from Ohio for SO2 are identified in its SIP as: 

Conesville, Cinergy Beckjord and Killen. Two of these three 

facilities have already installed SO2 controls. 

 

The RHR requires States with Class I areas to identify and analyze 

the “emissions measures that would be needed to achieve this 

amount of progress during the period covered by the first long-term 

strategy, and to determine whether those measures are reasonable 

based on the statutory factors. These factors are the costs of 

compliance with the measures, the time necessary for compliance 

with the measures, the energy and nonair quality environmental 

impacts of the compliance with the measures, and the remaining 

useful life of any existing source subject to the measures.” 

 The RHR requires states with emissions that may affect Class I 

areas in another state to develop a “long-term strategy” with 

measures “necessary to achieve the reasonable progress goals 

established by states having mandatory Class I Federal areas.” In 
Page | 11 

establishing this strategy, the states are required to included all 

“measures needed to achieve its apportionment of emission 

reduction obligations agreed upon” during the collaborative 

process. In developing the long-term strategy the states must 

consider “emission reductions due to ongoing air pollution control 

programs,” “measures to mitigate impacts of construction activities,” 

“emissions limitations and schedules for compliance to achieve the 

reasonable progress goal,” “source retirement and replacement 

schedules,” “smoke management techniques,” “enforceability of 

emissions limitations and control measures,” and “the anticipated 

net effect on visibility due to projected changes in...emissions over 

the period addressed by the long-term strategy.” 

USEPA guidance also states: 

“In determining reasonable progress, CAA §169A(g)(1) 

requires States to take into consideration a number of 

factors. However, you have flexibility in how to take into 

consideration these statutory factors and any other factors 

that you have determined to be relevant. For example, the 

factors could be used to select which sources or activities 

should or should not be regulated, or they could be used to 

determine the level or stringency of control, if any, for 

selected sources or activities, or some combination of both. 

The factors may be considered both individually and/or in 

combination. As noted in section 4.1, given the significant 

emissions reductions that we anticipate to result from BART, 

the CAIR, and the implementation of other CAA programs, 

these reductions may be all that is necessary to achieve 

reasonable progress in the first planning period for some 

States.” 

Missouri’s SIP, as stated above, determined the “emission 

reductions from these contributing states are sufficient to achieve 

RPGs in Missouri’s Class I areas” based upon the RHR and 

USEPA guidance. In summary, Ohio believes the decision is 

supported by the Clean Air Act requirements including the 

reasonable progress factor-analysis approach. 

Comment 10: Reasonable Progress Goals and Long Term Strategy (Ohio SIP 

for Regional Haze p. 26-35) 

We have concerns about the factor-analysis done by Ohio EPA 

(pages 29-31 and summarized on page 27). The discussion 

refers to an analysis done by MRPO (contained in Appendix F) 

which is based on an evaluation of four specific Class I areas 
Page | 12 

in the upper mid-west (Voyageurs, Boundary Waters, Isle 

Royale, and Seney). This factor-analysis may not be 

applicable to the other Class I areas impacted by emissions 

from Ohio sources, including the Missouri Class I areas 

discussed above. Further, the conclusions and statements 

within the text are not validated by the analysis. The analysis 

and past EPA cost figures actually appear to show that beyond 

“on-the-books” controls are justified and cost-effective. There 

are several assertions on page 27 highlighting why beyond 

“on-the-books” controls are not justified. 

 “controlling beyond CAIR at this time cannot be justified 

because Ohio utilities are still in the process of installing 

controls for CAIR”, 

 “[Industrial, Commercial and Institutional] ICI boiler 

controls are estimated to be a little more expensive than 

[electrical generating unit] EGU controls and have much 

less impact on visibility improvements than EGUs”, and 

 “With the current bleak economic condition in Ohio, 

pursuing controls on these other sectors for haze reduction 

cannot be justified.” 

These reasons are not relevant issues within a 5-factor 

analysis as prescribed by EPA and are not supported by the 

analysis. Please address beyond “on-the-books” within the 5-

factors and provide the information supporting the analysis. 

Our understanding is that the costs presented within the 

“factor analysis” for beyond-on the-books-controls for EGUs 

are in the same range as those for other EPA regulations. 

(USDA Forest Service) 

We recognize that most difficult process within the regional 

haze SIP development is addressing reasonable progress for 

all Class I areas affected by emissions from a State. On pages 

28 through 37, the SIP reviews ongoing programs and 

assesses current and future contribution to visibility 

impairment as the basis for relying on on-the-books controls 

for this first regional haze plan. Much of the cost information 

noted in the SIP comes from the MWRPO reasonable progress 

analysis. That information was develop based on regional 

control options and focused on the Class I areas in the upper 

mid-west. The study may not reflect costs regarding 

additional controls for specific Class I areas outside of the 
Page | 13 

MWRPO. (National Park Service and U.S. Fish and Wildlife 

Service) 

Response 10: Ohio EPA believes the factor analysis performed by EC/R regarding 

the MRPO Class I areas can, in many cases, be applied to other 

Class I areas. However, Ohio EPA will be revising this section to 

further address the commenters concerns. 

 Ohio EPA does wish to clarify that the factor analysis is required for 

setting reasonable progress goals for states with Class I areas. 

Ohio does not have any Class I areas. It is the responsibility of 

states shown to impact a Class I area in another state to document 

the technical basis, including modeling, monitoring and emissions 

information that the state is relying on to determine its 

apportionment of emission reduction obligations. 

 USEPA has clarified that “some States may conclude that control 

strategies specifically for protection of visibility are not needed at 

this time because the analyses may show that existing measures 

are sufficient to meet reasonable progress goals” and that USEPA 

is “requiring States to document their analyses, including any 

consultations with other States in support of their conclusions that 

further controls are not needed at this time.” [64 FR 35714] 

Although additional control measures may appear cost effective, 

when a State with a Class I area sets a reasonable progress goal 

all of the following four factors are weighed together: 

• Cost of compliance; 

• Time necessary for compliance; 

• Energy and nonair quality impacts; 

• Remaining useful life of existing sources 

USEPA does not set any “presumptive targets” and gives states the 

“flexibility in determining their reasonable progress goals based on 

consideration of all the factors.” As part of this reasonable progress 

analyses states must “identify and analyze the emissions measures 

that would be needed to achieve this amount of progress during the 

first long-term strategy, and to determine whether those measures 

are reasonable based on the statutory factors” and then consults 

with other states that area anticipated to contribute. If it is 

determined reasonable, the State should identify this amount of 

progress “as its reasonable progress goal for the first long-term 

strategy [2018], unless it determines that additional progress 

beyond this amount is also reasonable.” If that is the case, the 
Page | 14 

“state should adopt that amount of progress as its goal.” If a 

contributing State cannot agree with the State establishing the 

reasonable progress goal, “the State setting the goal must describe 

the actions taken to resolve the disagreement.” [64 FR 35714] 

States without Class I areas do not set reasonable progress goals 

but rather participate, through consultation, with the State 

containing a Class I area(s) for which it potentially impacts. 

However, States without Class I areas and States with Class I 

areas do need to provide a long-term strategy covering the first 

long-term period. As part of the long-term strategy seven factors 

are considered, including: 

• The anticipated net effect on visibility due to projected 

changes in emissions over the long-term period. 

However, USEPA decided not to include the four factors identified 

above as a requirement for the long-term strategy because they are 

included as part of the reasonable progress factors. 

As part of the long-term strategy, States like Ohio need to include 

“all measures necessary to obtain its share of the emissions 

needed to meet the progress goal” for the area. 

Ohio continues to believe on-the-books controls in Ohio will provide 

for reasonable progress in the Class I areas for which Ohio 

significantly impacts. Additional information will be included in 

Ohio’s SIP to support this conclusion. 

Comment 11: Reasonable Progress Goals and Long Term Strategy (Ohio SIP 

for Regional Haze p. 26-35) 

Please clarify Ohio’s response to MANE-VU’s “ASK” from 

2007. Vermont and New Hampshire use emissions reductions 

from the ASK to show reasonable progress for the Class I 

areas in their states (Lye Brook, Great Gulf, Presidential 

Range-Dry River wilderness areas managed by FS). (USDA 

Forest Service) 

Regional Consistency (Ohio SIP for Regional Haze p. 2-3) 

There is an inconsistency in Regional Haze SIPs among states, 

for instance between Vermont and Ohio. Vermont assumes 

the MANE-VU ASK is being addressed by Ohio and VT 

includes the associated emission reductions while Ohio has 

not committed to these emission reductions. This could lead 
Page | 15 

to Class I areas within MANE-VU states not meeting 

reasonable progress goals set by those states. Consultation 

between Ohio and other states within MANE-VU that have 

asked for emissions reductions beyond “on-the-books” 

controls has not been resolved. (USDA Forest Service) 

The SIP mentions the MANE-VU request for cooperation in 

assisting their states to meet what they consider to be 

reasonable progress regarding reductions in sulfur dioxide 

emissions. The MANE-VU request is directed at specific 

stacks located at coal-fired, electric generating facilities, and 

includes a general reduction target for SO2 emissions from all 

point sources. The MANE-VU request acknowledges that their 

request could be met using a combination of electric utility 

reductions and other reductions. ODAPC should list 

reductions expected at the facilities identified by MANE-VU 

and calculate whether additional controls at other facilities 

meet the additional sulfur reduction targets noted in the 

MANE-VU request. (National Park Service and U.S. Fish and 

Wildlife Service) 

Response 11: MWRPO’s analysis shows a less than 2% contribution from Ohio 

on New Hampshire’s Class I areas. The modeling shows that 62% 

of Vermont’s visibility impact comes from MANE-VU states in 2018 

with an additional 8% from Pennsylvania. Ohio’s 2018 contribution 

comprises 3%. Ohio does not believe this is a significant 

contribution. 

As described in Ohio’s SIP, Ohio received a letter from MANE-VU 

on July 30, 2007 requesting a course of action for reasonable 

progress at their Class I areas. Ohio participated, along with other 

MRPO states, in consultations and discussions with MANE-VU and 

was provided a consultation summary by MANE-VU on August 6, 

2007. Ohio EPA provided a response on October 3, 2007. In this 

response, Ohio requested additional information and work to be 

done before Ohio could properly respond to MANE-VU’s request. 

The MANE-VU ask consists of the following: 

• Application of Best Available Retrofit Technology (BART) 

• 90% (or greater) reduction in SO2 emissions from each of the 

EGU stacks on MANE-VU’s list of 167 stacks (located in 19 

states), which reflect those stacks determined to be reasonably 

anticipated to cause or contribute to visibility impairment in the 

MANE-VU Class I areas. Note: the selection of the 167 stacks 

is based on 2002 emissions data.
Page | 16 

• 28% reduction in non-EGU (point, area, on-road, and off-road) 

SO2 emissions relative to on-the-books, on-the-way 2018 

projections 

• Continued evaluation of other measures, including measures to 

reduce SO2 and NOx emissions from coal-burning facilities and 

promulgation of new source performance standards for wood 

combustion 

• Further reduction in power plant SO2 (and NOx) emissions 

beyond the current Clean Air Interstate Rule program 

Of the 167 stacks, 28 are from 14 sources in Ohio. Most of these 

stacks have post-combustion emission controls (i.e., scrubbers) 

installed since 2002. 

More recent modeling has been done for MANE-VU 

(www.nescaum.org/topics/regional-haze/regional-haze-documents) 

for projecting visibility in 2018. As part of this modeling, they found 

“the uniform Rate is achieved and exceeded at all MANE-VU Class 

I sites." 

In MANE-VU’s May 13, 2008 2018 Visibility Projections document it 

further states: 

 

MANE-VU received comments from several stakeholders 

and another RPO related to the fact that the modeling 

described in this report included control measures and 

emission reductions that went beyond currently existing 

regulations. Commenters suggested that since the CAIR 

program and other “on the books” or “on the way” measures 

are projected to achieve uniform rates of progress as 

previously modeled, additional reductions to both EGU and 

non-EGU sectors were unnecessary. As described below, 

there are two reasons why MANE-VU has chosen to include 

these measures in this modeling analysis. 

First, while the results of the modeling described in this 

report suggest individual MANE-VU Class I areas will be 

able to meet or exceed uniform rates of progress by 2018, 

our current analysis also suggests that this would be difficult 

without including additional measures beyond 

implementation of CAIR. This result is due, in part, to our 

assumptions about the effectiveness of CAIR. We believe 

that it is appropriate for MANE-VU to take a conservative 

approach to estimating the potential for emissions reductions 

under the CAIR program. Therefore MANE-VU added EGU 
Page | 17 

emissions to estimate the impact of banking and trading 

under CAIR. Additional EGU reductions would be feasible 

with additional federal action to control EGU emissions (e.g., 

a third phase of CAIR), but MANE-VU does not believe that 

these reductions are likely to occur absent additional 

regulation. 

MWRPO used USEPA’s approved IPM modeling and projections to 

project EGU emissions for 2018. Ohio EPA does not agree with 

MANE-VU’s “add back” due to the uncertainty of CAIR. 

Further support is found in MANE-VU’s February 7, 2008 document 

entitled “MANE-VU Modeling for Reasonable Progress Goals.” 

The following projections were made for 2018: 
Page | 18 

As seen above, for Arcadia (the Class I area for which Ohio has the 

highest contribution in 2018 (4%)), a 4.39 deciview, or 19%, 

reduction is predicted based on on-the-book controls and 

restrictions on fuel sulfur content in the MANE-VU region. Adding 

additional controls incorporated into MANE-VU’s Ask results in an 

additional 0.55 deciview, or 2%, change. Important to note; in all 

cases, including on-the-books control, the uniform rate of 

improvement is met at Arcadia as depicted graphically below in 

MANE-VU’s document: 

The same results are seen in this document for all MANE-VU Class 

I areas. 

Ohio EPA committed to continuing work with MANE-VU states but 

continues to believe that on-the-books controls, for this first 

planning period, represents reasonable progress. This is further 

supported by the additional information provided above. 

As stated before, if a contributing State cannot agree with the State 

establishing the reasonable progress goal, “the State setting the 

goal must describe the actions taken to resolve the disagreement.” 

[64 FR 35714]. It appears the approach that Vermont and New 

Hampshire have taken is to assume other states, like Ohio, will 

implement the requested controls in their “Ask” without providing 

the additional information requested by Ohio and others and 

continuing the consultation process. 

To assist in addressing comments regarding MANE-VU’s “Ask”, 

Ohio EPA will be adding additional discussions in the SIP. 
Page | 19 

Comment 12: Reasonable Progress Goals and Long Term Strategy (Ohio SIP 

for Regional Haze p. 26-35) 

We request that Ohio provide language in their SIP linking the 

Regional Haze and New Source Review programs and 

continued FLM coordination between these programs. 

Currently there is no mechanism in the SIP to ensure that the 

emissions from new stationary sources or major modifications 

of existing sources will make reasonable progress toward the 

national visibility goal (40 CFR 51.307). This could be 

especially important for emissions from new sources that were 

not anticipated in 2018 emission inventories. (USDA Forest 

Service) 

Coordination and Consultation (Ohio SIP for Regional Haze p. 

3-4, 36) 

As part of the SIP and the strategy to implement the SIP, we 

request that Ohio express its intent to improve consultation 

and coordination with all impacted FLMs, including the Forest 

Service. For example, the Forest Service did not receive your 

original draft plan dated September 9, 2008, until September 12 

through a NPS colleague. We were made aware that the plan 

was being withdrawn prior to being able to provide comments 

on the plan. While we work closely with our counterparts in 

the Department of the Interior our comments were not 

addressed in this draft as stated on page 3-4 of Ohio’s SIP. 

We also did not receive the current SIP until forwarded by the 

same NPS colleague. We are disappointed by this lack of 

coordination and consultation and are committed to improving 

this situation. (USDA Forest Service) 

Coordination and Consultation (Ohio SIP for Regional Haze p. 

3-4, 36) 

Given the withdraw of the previous (September 2008) draft and 

significant changes made to the current draft of the SIP the 

FLM has not had 60 days to comment prior to the hearing to be 

held on February 26, 2009. Additionally, we request that Ohio 

provides FLM comments and Ohio’s response to these 

comments to the public at or before the public meeting. (USDA 

Forest Service) 

We provided the State informal comments on the draft regional 

haze SIP via email on October 15, 2008. Some of our concerns 

have been addressed by the SIP submitted to EPA in late 
Page | 20 

December. However, the SIP as submitted does not address 

all of the issues we raised in our informal comments. (National 

Park Service and U.S. Fish and Wildlife Service) 

The EPA has addressed FLM consultation in its September 

2006 Question and Answer (Q and A) document as follows: 

Q - What are EPA's expectations and the basis for consultation 

requirements regarding formal consultative procedures? 

What constitutes effective FLM communication? Can it be 

assumed that if the FLM attends the RPO meetings and calls 

and doesn’t raise any concerns it has no problems with a 

State’s SIP? 

A - “40 CFR 51.308(i) requires that States consult with FLMs 

before adopting and submitting their RH SIPs. These 

requirements are summarized as follows: 

States must provide the FLM an opportunity for consultation, in 

person and at least 60 days prior to holding any public hearing 

on the SIP. The State must also provide the opportunity for the 

FLMs to discuss their: (i) assessment of impairment of visibility 

in any Class I area; and, (ii) recommendations on the 

development of the RPG and on the development and 

implementation of strategies to address visibility impairment. 

Further, the State must include in the SIP a description of how it 

addressed any comments provided by the FLMs. Lastly, the SIP 

must provide procedures for continuing consultation between the 

State and FLMs on the implementation of 51.308, including 

development and review of SIP revisions and 5-year progress 

reports, and on the implementation of other programs having the 

potential to contribute to impairment of visibility in Class I areas. 

This is a formal consultative process. The basis for requiring 

written consultation procedures is 40 CFR 51.308(i)(4). To 

satisfy this requirement, States should contact the FLMs to 

ensure their input to the RH SIP process is solicited and 

documented. While effective FLM consultation relies on both 

parties (States and FLMs) communicating early and often, the 

State is only required to meet the provisions of 40 CFR 

51.308(i) and is not responsible if a FLM chooses not to 

participate in the either the RPO activities or the SIP 

development and review process. In such cases, the State 

should document its outreach efforts to the FLM.” (USDA 

Forest Service) 
Page | 21 

All State SIPs for regional haze protection must address the 

goal of protecting the 20 percent best visibility days at Class I 

areas potentially affected by emissions from within the State. 

We request Ohio to recognize, in the regional haze SIP, the 

requirements of full consultation with the federal land 

managers for review of visibility impacts required by New 

Source Review and Prevention of Significant Deterioration 

(NSR/PSD) programs. Given the long range effect major 

sources can have on visibility, the regional haze rules should 

establish a policy that ODAPC will consult with federal land 

managers, for all sources subject to NSR/PSD requirement, 

early in the permitting process. 

We are also concerned that Ohio EPA’s current approved SIP 

is deficient with respect to visibility protection under New 

Source Review, because it lacks Federal Land Manager (FLM) 

notification and consultation procedures that are identified in 

federal EPA regulations (see 40 CFR 52.21(p) and 40 CFR 

51.307) for new sources of air pollution that may impact 

mandatory federal Class I areas. Specifically, the procedures 

do not establish a process by which FLM notification should 

occur, including what information should be submitted for 

FLM review, when this information should be submitted, and 

when FLM concerns and agency responses should appear in a 

public notice. The FLMs are charged with an “affirmative 

responsibility” under the Clean Air Act (CAA) to protect the air 

quality related values (AQRVs), including visibility, in Class I 

areas that we manage. This responsibility places the utmost 

importance on the FLMs receiving necessary and timely 

information from the state air regulatory agencies, such as 

Ohio EPA, in order to make an informed determination. 

Regardless of what OH DAPC has currently established in 

their SIP under OAC 3745-31 for New Source Review, the 

visibility SIP required by 40 CFR 51.307 must at a minimum 

incorporate the FLM consultation procedures found in the 

federal regulation for the purposes of visibility protection. Our 

position on this issue has been documented in detail in our 

comment letters on several recent PSD permitting actions in 

Ohio. Therefore, we ask that you consider these comments 

and take action to rectify the procedures established under the 

Ohio SIP so that it may enable, rather than impede, an 

appropriate role for the FLM as provided by the CAA. (National 

Park Service and U.S. Fish and Wildlife Service) 

 
Page | 22 

Response 12: Ohio EPA addressed the FLM coordination requirements in Section 

3 of Ohio’s SIP: 

“Ohio will continue to coordinate and consult with the FLMs 

during the development of future progress reports and 

revisions of this plan, as well as during the implementation of 

programs having the potential to contribute to visibility 

impairment in the mandatory Class I areas. This includes 

coordination with the FLMs during new source review (NSR) 

of sources that may impact Class I areas.” 

The new source review requirements for sources wishing to locate 

or expand in Ohio are contained in Chapter 3745-31 of Ohio’s 

Administrative Code. Ohio has a SIP approved NSR program that 

meets the federal requirements for new source review. Ohio does 

not feel any additional clarification is necessary in the Regional 

Haze SIP regarding NSR. However, it is worth noting that Ohio 

EPA will be making amendments to Chapter 3745-31 regarding 

FLM coordination on NSR actions. Once the rulemaking is 

completed, Ohio EPA will be submitting its NSR regulations for a 

revision of its NSR SIP requirements. Ohio EPA urges the FLMs to 

participate in the public comment process related to the rulemaking 

action. 

Ohio EPA apologizes for the confusion regarding our first 2008 

draft. Ohio EPA’s SIP Section has recently acquired several new 

staff and management. The Section’s new manager has ensured 

that FLM coordination will occur smoothly on all Regional Haze 

related matters in the future. Significant effort was made to ensure 

a complete list of FLM staff whom should receive documentation 

has been identified. 

Ohio EPA did provide an initial draft in September of 2008. 

Comments were given to Ohio EPA on October 15, 2008. On 

October 30, 2008 Ohio EPA indicated to FLM staff that we would 

not be submitting the SIP at this time in order to address 

comments. As a result of comments, Ohio EPA provided a second, 

much improved draft, on December 29, 2008. USEPA had 

informed Ohio that deficiency letters for failing to submit on time 

were impending for all states who had yet to submit their SIPs. 

This was discussed with FLM staff and Ohio requested any 

comments on the second draft quickly. However, FLM staff 

indicated they were currently reviewing a significant number of 

SIPs. Ohio committed that if the FLM staff could not review and 

comment on Ohio’s second draft before it was necessary for Ohio 

to submit its SIP, Ohio would commit to reviewing and addressing 
Page | 23 

comments from the FLM staff during the forthcoming public 

comment period. Ohio then submitted its Regional Haze SIP on 

December 31, 2008. We understand FLM staff believe because 

there were such significant changes between the first and second 

draft that they were not afforded 60 days of comment. 

Comment 13: One other major concern is that the modeling that Ohio EPA is 

relying upon here doesn't include any proposed new sources 

in Ohio. One that's most obviously apparent, of course, is the 

AMP-Ohio generating station proposed for Meigs County. 

Those new sources will impact visibility - assuming they're 

built - they will impact visibility. They will impact other things 

in Class I areas -- Dolly Sods, Shenandoah, other various 

areas east of here. They need to be factored into the plan. I 

would also add that Ohio EPA, in general, should be 

addressing those Class I impacts when the permitting process 

for those new sources takes place. (Nachy Kanfer, 

representing Sierra Club) 

Response 13: The modeling conducted by LADCO and other states’ RPOs does 

account for new sources. Projecting new source growth is a more 

challenging aspect for modeling future emissions, especially when 

considering the lengthy planning periods being forecasted by the 

models. Additional information regarding growth factors 

incorporated into Ohio’s modeling for the various sectors, including 

EGUs can be found in EH Pechan’s “Development of 2005 Base 

Year Growth and Control Factors for Lake Michigan Air Directors 

Consortium (LADCO)” final report at: 

http://www.ladco.org/reports/technical_support_document/referenc

es/ladco_2005_base_yr_growth_and_controls_report_final.pdf. 

Ohio EPA, as part of new source review, does address impacts on 

Class I areas. Please refer to the following Ohio Administrative 

Code rule applicable to attainment areas: 

3745-31-17 – “Attainment provisions - additional impact analysis” at 

http://www.epa.ohio.gov/portals/27/regs/3745-31/3745-31-17f.pdf. 

This rule requires that any new source being proposed in an area 

designated as attainment must provide an analysis of all possible 

impairment to visibility. 

Whereas for new sources in nonattainment areas; they must obtain 

offsets that provide for a positive net air quality benefit as required 

under the following rule: 
Page | 24 

3745-31-22 – “Nonattainment provisions - conditions for approval” 

at 

http://www.epa.ohio.gov/portals/27/regs/3745-31/3745-31-17f.pdf. 

It should also be noted that the specific facility in question raised by 

the commenter, AMP-Ohio generating station in Meigs County, will 

not be constructed in the future. 

Comment 14: Reasonable Progress Goals and Long Term Strategy (Ohio SIP 

for Regional Haze p. 26-35) 

Page 27 states that ICI boiler controls are more expensive and 

less effective than controls on EGUs. However this conflicts 

with statements on page 30 “...ICI controls were slightly less 

expensive than control for EGUs on a $/deciview basis...” 

Please clarify these statements and the metrics associated 

with them. (USDA Forest Service) 

Response 14: As can be seen in the following table from the EC/R factor analysis 

document; the cost of control per ton of emissions is greater (more 

expensive) for ICI boilers compared to EGUs. 

 

However, control of EGUs has a higher positive impact on deciview 

estimations compared to control of ICI boilers as depicted in the 

following table: 
Page | 25 

 

 

And by viewing the following table you can see that the cost per 

visibility improvement ($million/deciview) is greater for EGU control 

compared to ICI boiler control. 

Comment 15: Reasonable Progress Goals and Long Term Strategy (Ohio SIP 

for Regional Haze p. 26-35) 

The section discussing Ohio’s share of emission reductions 

appears to imply that Ohio needs reductions in other states to 

meet its own “fair share” of emission reductions (p. 28 section 

10.2). “Ohio has determined that its fair share of emission 

reductions needed to meet reasonable progress constitutes 

on-the-books controls and other controls that upwind states 
Page | 26 

will implement, but that are not yet in place.” Please clarify 

this sentence as 40 CFR 51.308(d)(3) does not allow for the use 

of another State’s emission reductions to be accounted for in 

Ohio’s fair share of emission reductions. (USDA Forest 

Service) 

Response 15: Ohio EPA will rephrase the statement. The intent was that 

emission reductions that are being achieved, or will be achieved, by 

Ohio and other states constitutes reasonable progress. 

Comment 16: As another example, on page 35, right -- this document, this is 

the Regional Haze SIP by the way. We are talking about the 

locations that are most highly impacted by Ohio sources - 

such as Dolly Sods, for example, in West Virginia - and the 

document shows satisfactory progress. Well, the term 

"satisfactory" is subjective of course. Ohio EPA should be 

aiming to show that there is maximum progress allowed by the 

-- that can be achieved under the Regional Haze Rule, under 

BART controls. (Nachy Kanfer, representing Sierra Club) 

Response 16: The commenter is referring to the following statement: 

“The locations most highly impacted by Ohio sources, such 

as Dolly Sods in West Virginia, Mammoth Cave in Kentucky, 

and Shenandoah Valley and James River in Virginia, show 

satisfactory progress. “ 

Ohio EPA should clarify that Ohio’s intent is to demonstrate that 

Ohio believes it has accounted for its fair share of reductions 

needed for these areas. As discussed previously in Ohio’s 

response to comments and as will be clarified in the SIP document, 

other than the MANE-VU “Ask”, other states with Class I areas are 

in agreement with Ohio EPA’s approach for our fair share of 

emission reductions needed in these areas. MANE-VU’s “Ask” has 

also been discussed in other responses to comments in this 

document and will also be clarified in the SIP document. 

USEPA’s RHR did not intend that states develop programs that 

achieve the 2064 goal within the first planning period (up to 2018). 

Rather, this first SIP is intended to provide strategies for the initial 

implementation period extending to the year 2018. USEPA states 

that “achieving the national visibility goal will require a substantial, 

long-term program. Accordingly, the Regional Haze program 

requires the periodic review by each State of whether “reasonable 

progress” is being achieved and revisions of implementation plans 

as needed to continue progress toward the national visibility goal.” 
Page | 27 

Ohio EPA, because of the lack of Class I areas within the state, is 

not required to set “reasonable progress goals.” USEPA states 

they interpret ““long-term strategy” as the control measures that are 

needed to ensure reasonable progress, together with a 

demonstration that those measures will provide for reasonable 

progress during the 10 to 15 year period.” 

USEPA has clarified that “some States may conclude that control 

strategies specifically for protection of visibility are not needed at 

this time because the analyses may show that existing measures 

are sufficient to meet reasonable progress goals” and that USEPA 

is “requiring States to document their analyses, including any 

consultations with other States in support of their conclusions that 

further controls are not needed at this time.” [64 FR 35714] 

This is the determination that Ohio EPA has made and believes it 

does provide for the necessary improvements for the first planning 

period. Upon a review of progress in the future, Ohio EPA may 

determine additional measures may be necessary in order to 

continue or progress improvement. This will all be a part of the 

process for this long-term program. 

Comment 17: Wildland Fire (Ohio SIP for Regional Haze p. 13, 33-34) 

We are pleased to see that Ohio will be developing a Smoke 

Management Program. The Forest Service would like to assist 

in the development of such a program. (USDA Forest Service) 

We recognize that prescribed fire and wild fire are not 

currently a major portion of visibility impairment at Class I 

areas affected by emissions from Ohio. We appreciate the 

ODAPC’s efforts to develop a smoke management program. 

We encourage ODAPC to include Class I areas as sensitive 

receptors when assessing smoke impacts under the future 

program and to require best management practices to reduce 

impacts when sensitive receptors are affected. (National Park 

Service and U.S. Fish and Wildlife Service) 

 

Response 17: No response necessary. 

Comment 18: Wildland Fire (Ohio SIP for Regional Haze p. 13, 33-34) 

We agree that smoke from wildfires and prescribed fires is not 

a significant emission source for Ohio or a contributor to 
Page | 28 

regional haze in downwind Class I areas at this time. (USDA 

Forest Service) 

Response 18: No response necessary. 

Comment 19: Let me start with, first, a sort of general observation that Ohio 

EPA's Regional Haze Plan is -- it's a plan that proposes, 

basically, to comply with another program - that being the 

Clean Air Interstate Rule - and not much beyond that. It does 

require the installation of controls on one facility in Ohio but 

Ohio EPA should really be taking further steps. It should be 

requiring controls on existing electric generating units, of 

which there are many in Ohio including many very polluting 

ones, and other sources and addressing proposed sources as 

well, including the AMP-Ohio generating station. And that is in 

order -- if we really are to achieve all of the public health 

benefits, the air quality benefits, visibility benefits and 

obviously our national parks, that really full compliance with 

this Regional Haze Program, the Regional Haze Rule, can 

achieve. 

So first I would point out that Ohio EPA is really 

acknowledging that it's only seeking to do the bare minimum 

here. For example, on page 20 there's a sentence while Ohio 

has made the decision that CAIR will suffice for their control. 

You know, there's no acknowledgment, there's no real 

awareness that the State should not simply be aiming for a 

bare minimum but should be working to achieve the maximum 

reductions in air emissions especially air emissions that 

reduce visibility in Class I areas. (Nachy Kanfer, representing 

Sierra Club) 

Response 19: Ohio EPA disagrees that CAIR is a “bare minimum.” The CAIR 

program, and its impending replacement (the Transport Rule) is 

projected to account for significant reductions in pollutants of 

concern for Regional Haze. For example, in Ohio alone it is 

projected that CAIR will result in emissions of NOx and SO2, 

declining between 2002 and 2018 by 63% and 62%, respectively. 

Comment 20: Secondly, I would say that it is inappropriate to use CAIR in 

general as an excuse for not engaging in plant specific 

control. CAIR is a cap and trade program that allows 

decreases and increases in emissions across an area of 28 

states, right, that are covered. BART and other programs 

require plant specific controls. So, its inappropriate to avoid 

BART obligations by simply claiming that BART eligible EGUs 
Page | 29 

and BART eligible other sources that are not EGUs will be 

made to comply with CAIR. That's not a sufficient excuse. 

(Nachy Kanfer, representing Sierra Club) 

Response 20: In USEPA’s implementation guidelines for BART [40 CFR 39104], it 

is recognized that the CAIR program will result in reductions in 

emissions for SO2 and NOx within the 28 eastern States of 70% 

and 60%, respectively. To achieve these reductions, EGUs have 

installed plant specific controls to reduce SO2 and NOx emissions. 

The guidelines provide a detailed discussion of USEPA’s analysis 

and conclusion that for EGUs, CAIR will provide for greater 

reductions than if BART were required. 

Additionally, as clarified in the revised Regional Haze SIP, USEPA 

proposed a replacement to the CAIR program, the Transport Rule, 

on July 6, 2010. [75 FR 45210] Upon finalization, it will further 

assist states in addressing their obligations regarding regionally 

transported pollution by providing reductions in NOx and SO2

emissions in 2012 and 2014. It also addresses many of the 

concerns raised by the Court’s remand in regards to the cap and 

trade portion of the CAIR program. 

Comment 21: I would also say that looking at various answers on pages 27 

and 31, there are these statements, right, controlling EGUs 

beyond CAIR control levels would have the most effect on 

visibility improvement. And again, modeling indicated that 

significant beyond-CAIR reductions from EGUs - especially for 

sulfur dioxide - would be the most effective control for 

improving visibility. The plan fails to justify not requiring those 

beyond-CAIR controls. Ohio EPA should be evaluating on a 

plant-by-plant basis whether plant-specific BART controls are 

justified at each of these 37 EGUs identified on page, I believe 

it was - sorry - page 20 here. It lists all the electric generating 

stations in Ohio and -- yes, Ohio EPA should be justifying its 

decision to not establish BART controls on each one of these. 

(Nachy Kanfer, representing Sierra Club) 

Response 21: As discussed in the response above and as will be clarified in the 

SIP document, Ohio EPA believes additional control for EGUs is 

not warranted during this first planning period. While the SIP 

document indicates control of EGUs would be the “most” costeffective method for improving visibility, the document does not 

necessarily imply it is cost-effective for this first planning period. 

Ohio EPA has established its long-term strategy for its fair share of 
Page | 30 

emissions reductions necessary as a part of the reasonable 

progress goals set by those areas with Class I areas. 

The commenter is referring to the list of the BART-EGUs in Ohio 

that were not subjected to extensive BART analysis or modeling 

because of Ohio’s decision to adopt USEPA’s option that CAIR will 

suffice for BART at EGUs. Therefore, per the response above, 

additional justification is not required for why BART is not 

established for these sources. 

Comment 22: Verification and Contingencies (Ohio SIP for Regional Haze p. 

37) 

There is uncertainty regarding how CAIR might be modified in 

the future by EPA in response to the recent court decisions. 

The number, size and location of new EGU and non-EGU 

sources between now and 2018 are also unknown. How will 

the SIP address this uncertainty and respond if in 2012 and/or 

2018 conditions are quite different from those predicted? 

We would also like Ohio to consider contingency measures or 

procedures for unexpected or unforeseen circumstances; e.g., 

future emissions are not reduced to the same degree or in the 

same geographic area as projected, or emission inventories 

are incorrect or flawed. Are there adaptive management or 

increased review strategies which could be implemented in 

those situations? (USDA Forest Service) 

The Long Term Strategy and Reasonable Progress section of 

the December 2008 SIP is greatly improved from the previous 

draft. We appreciate the discussion of EPA’s Clean Air 

Interstate Rule (CAIR) and understand that the majority of 

Ohio’s long-term strategy relies on reductions expected from 

implementation of that rule. We note that the recent court 

ruling on CAIR still leaves large uncertainty regarding the 

magnitude and location of emissions reductions to be 

implemented under that program. We request that ODAPC 

acknowledge this uncertainty regarding the emissions 

projections for its sources and that the SIP commit the State to 

re-examine actual and future emissions changes in the midterm review required by the regional haze rule. At that time if 

in-state emissions for 2018 are likely to fall short of 

projections adopted in this plan, the ODAPC must initiate plan 

revisions for the long-term strategy. Ohio could list possible 

measures, such as those found cost-effective under the 

MWRPO reasonable progress assessment, conducted by EC/R 

Incorporated for consideration in future SIP revisions, should 
Page | 31 

anticipated reductions from on-the-books programs fall short 

of established goals. (National Park Service and U.S. Fish and 

Wildlife Service)

Response 22: It is difficult, at this time, to determine how Ohio EPA will respond 

during the interim review and comprehensive review periods. Ohio 

EPA is currently beginning planning processes for exploring 

emission reduction measures to meet the new ozone and PM2.5 

standards. Ohio anticipates that strategies developed for these 

standards will have a positive impact on Regional Haze and allow 

for greater improvements in the future. Ohio also anticipates 

USEPA’s final promulgation of the CAIR replacement, the 

Transport Rule, in 2011 will address the uncertainties in CAIR 

based on the proposed Transport Rule. Ohio EPA believes the 

Transport Rule, when finalized, will be a more aggressive program 

than CAIR, providing substantial NOx and SO2 reductions across 

the east and in Ohio specifically. 

Ohio EPA does not believe it is necessary, nor is it required, for 

contingency measures to be incorporated into the Regional Haze 

SIP. The interim review period was incorporated as part of the 

Regional Haze program precisely to allow for a mid-course review 

to ensure progress has been made and continues as planned for 

during the submittal. The program provides for additional 

measures, such as revising the SIP within 1-year or re-instating the 

regional planning process, if there is a substantial increase in 

emissions or a deficiency in plan implementation. 

Ohio has committed to the interim and comprehensive review 

requirements in our SIP. 

Comment 23: Coordination and Consultation (Ohio SIP for Regional Haze p. 

3-4, 36) 

Also, coordination should occur during SIP revisions 

(including reasonable progress reports) and at steps 

necessary to address adequacy of the SIP. (USDA Forest 

Service) 

The SIP should contain provisions for ongoing coordination 

and consultation with the Federal Land Managers on any 

future SIP revisions and reporting. The Federal Land 

Managers are committed to supporting State progress and will 

inform the State of our ongoing monitoring and assessment 

activities. While much of this coordination has been 
Page | 32 

accomplished through the Regional Planning Organizations 

(RPOs), the future of RPOs is uncertain and a specific 

statement of the tasks to be coordinated on will provide better 

assurance that all States and Federal Land Managers will be 

kept up to date over the long implementation period of these 

rules. (National Park Service and U.S. Fish and Wildlife 

Service) 

Response 23: As stated above, Ohio EPA addressed the FLM coordination 

requirements in Section 3 of Ohio’s SIP: 

“Ohio will continue to coordinate and consult with the FLMs 

during the development of future progress reports and 

revisions of this plan, as well as during the implementation of 

programs having the potential to contribute to visibility 

impairment in the mandatory Class I areas. This includes 

coordination with the FLMs during new source review (NSR) 

of sources that may impact Class I areas.” 

Ohio EPA is committed to continue coordination with the FLMs. 

Comment 24: Best Available Retrofit Technology (BART) (Ohio SIP for 

Regional Haze p. 16-22) 

We have concerns about the initial analysis to determine 

sources subject to BART. The “screen-out” analysis done by 

LADCO specifies that it uses the Q/D metric for its analysis 

(where Q should equal the sum of tons per year of SO2 + NOx + 

PM10 + H2SO4), but in fact a metric of L/D was used (where L = 

tons per year of SO2 + NOx). The change in numerator values 

could result in fewer emission sources being considered as 

subject to BART. Please address whether additional sources 

would have been considered had the Q/D metric been applied 

instead of L/D. (USDA Forest Service) 

Through interaction with the MWRPO and the ODPAC over the 

last year, we have reviewed the air quality modeling performed 

to assess sources subject to BART. We agree with ODAPC’s 

conclusion that only the P. H. Glatfelter facility is subject to 

BART. (National Park Service and U.S. Fish and Wildlife 

Service) 

 

Best Available Retrofit Technology (BART) (Ohio SIP for 

Regional Haze p. 16-22) 
Page | 33 

Our understanding of EPA direction is that particulate matter 

(PM) emissions from EGU sources should be considered in the 

BART analysis for the regional haze SIP. In a September, 2006 

Question and Answer (Q and A) document the EPA wrote: 

“States subject to and participating in the CAIR cap and trade 

program for SO2 and NOx are allowed to treat the CAIR 

requirements for EGUs as a substitute for the application of 

BART controls per 40 CFR 51.308(e)(4). This does not mean 

EGUs are exempt for SO2 and NOx, only that CAIR satisfies 

the BART requirement for those pollutants. The remaining 

visibility pollutants to consider for determining BART-eligible 

sources are PM, and, using judgment, VOCs, and ammonia. 

For PM, the July 6, 2005, final BART rule at 70 FR 39160 notes 

PM10 may be used an indicator for PM in this step of the 

determination and thus, PM10 can be used for the exemption 

modeling.” – Our review indicates the proposed OH Regional 

Haze SIP is counter to EPA direction. (USDA Forest Service) 

With respect to the decision to accept CAIR as Best Available 

Retrofit Technology (BART) for electric utilities, we point out 

that Ohio still needs to address particulate matter (PM) 

emissions from EGU sources in the BART analyses for the 

regional haze SIP. (National Park Service and U.S. Fish and 

Wildlife Service) 

Response 24: PM was not included in the denominator because of the relatively 

small quantities involved and the lack of impact on visibility 

determined through modeling. 

LADCO performed an analysis of 149 BART eligible sources in the 

LADCO states’ area and found that PM emissions were 

insignificant and; therefore, excluded PM from the analysis. 
Page | 34 

 

This determination was made based on the approach provided by 

USEPA in the BART Guidelines. Under a cumulative modeling 

approach, modeling of total visibility impacts from all BART-eligible 

sources in a given state can be used to show that they collectively 

do not cause or contribute to visibility impairment in a Class I area. 

This approach was used to assess the likelihood that VOC and PM 

emissions will not cause or contribute to visibility impairment. 

Specifically, CAMx was run with all point source VOC and PM 

emissions eliminated (“zeroed-out”) to assess the contribution of 

these species to visibility impairment. The model results show that 

these emissions do not contribute to visibility impairment (i.e., less 

than a 0.5 dv impact in any Class I area). Because the VOC and 

PM emissions from just the BART-eligible sources are much less 

than those from all point sources, the visibility impact of these 

emissions from the BART-eligible sources will be much less than 

0.5 dv in any Class I area. Thus, these emissions can be excluded 

from BART review. In addition, ammonia emissions can be 

excluded from BART review, given that these emissions from the 

BART-eligible sources are relatively small (i.e., ammonia emissions 

from all point sources make-up only 1% of the total ammonia 

emissions in the region). 

 Ohio EPA will be revising the SIP document to provide additional 

information regarding the exclusion of PM emissions. 

H2SO4 was not a pollutant identified in the guidelines. Other than 

considering NOx, SO2 and PM, USEPA identified “states may use 

their best judgment to determine whether VOC or ammonia 

emissions are likely to have an impact on visibility.” Ohio EPA and 
Page | 35 

LADCO determined VOC and ammonia emissions did not warrant 

inclusion. 

To further illustrate the lack of need to consider PM emissions from 

EGUs, Ohio EPA performed a series of Calpuff runs for a large 

Ohio power plant (the Stuart Station in Adams County) according to 

the same protocol followed by LADCO. 

The following stack parameters and emission rates (averaged over 

actual hours of operation) were taken from our 2005 emissions 

inventory: 

 Location: 83/41/38 long.; 38/38/10 lat. 

 Height: 800 ft. 

 Temp.: 290 F 

 Velocity: 117.6 ft/sec 

 SO2 3848.65 g/s 

 NOx 889.695 g/s 

 PM10 110.937 g/s 

 PM2.5 85.699 g/s 

First, the model was run with the above –listed quantities of SO2, 

NOx, and PM2.5, and it was discovered that the most-strongly 

impacted Class 1 area (as measured by days above threshold) was 

the Shenandoah National Park in year 2003. Then, a series of runs 

were made zeroing-out each species in turn; then, a series of onepollutant only runs. The results were as follow: 

 Days above 

 Threshold 

 (Shenandoah NP, 2003) 

 Base: 97 

 No PM2.5 95 

 No NOx 86 

 No SO2 20 

 SO2 only 85 

 NOx only 19 

 PM2.5 only 0 

We particularly wish to note that the source, if it emitted PM2.5, 

only, would cause zero days above threshold. Reviewing the 

detailed results, we find zero days for all other Class 1 areas and all 

years (2002, 2003, 2004). Thus, the exclusion of PM from BART 

consideration for the EGU category is a reasonable interpretation of 

the “cause or contribute” language in the Haze Rule defining 

“subject to BART.” 
Page | 36 

Our use of “L/D” instead of “Q/D” to describe the ratio was a 

typographic error. We did not intend to create a new definition for 

the letter “L.” We will correct this in the final document. 

Comment 25: Best Available Retrofit Technology (BART) (Ohio SIP for 

Regional Haze p. 16-22) 

We have concerns about the BART control options and the 

methodology used to reach a conclusion. The standard 

approach to determining BART control options is that it should 

primarily be an engineering determination not an air quality 

modeling exercise. A BART limit is defined as “an emission 

limitation based on the degree of reduction achievable through 

the application of the best system of continuous emission 

reduction...”. With regard to the P.H. Glatfelter facility, please 

clarify why one of two higher performing control options (90% 

removal) should not be considered BART as opposed to the 

60% removal proposed by the company. Our understanding is 

the cost per ton for each of the final three control options are 

essentially equivalent for sulfur dioxide. (USDA Forest 

Service) 

We have serious concerns with the BART determination for 

the Glatfelter facility. The determination that the least total 

cost engineering option as BART does not correctly consider 

the visibility improvement factor. Neither the SIP language on 

pages 21-22 nor Appendix G provides sufficient assessment of 

the trade-off between total cost and degree of visibility 

improvement. On a dollar per ton of emissions reduced basis, 

the three engineering solutions are essentially equal, yet the 

high levels of control eliminate all days of impact greater than 

five percent of extinction change while the minimal control, 

chosen by the ODAPC as BART, still results in multiple days at 

multiple Class I areas of impacts above the contribution 

threshold. Given equal removal efficiency costs, the option 

with the greatest improvement in visibility should be selected. 

Using an air quality model to back-calculate a BART emission 

limit violates the intent of the BART determination, which 

should be primarily an engineering determination. This is 

especially true when all BART control options have equivalent 

cost per ton emission reductions. (National Park Service and 

U.S. Fish and Wildlife Service) 
Page | 37 

And, finally, let me just point out that -- this isn't really my area 

of expertise, but looking at the non-EGU source, this Glatfelter 

facility, Ohio EPA has really failed to justify why they're not 

requiring maximum reduction of SO2 emissions. We have 

these three possibilities of control technologies, and they are 

capable of 90 percent, 90 percent and 60 percent removal of 

SO2 respectively. The company, unsurprisingly, chooses the 

60 percent removal and Ohio EPA concurs. Well, that -- there's 

really no justification of that written in the plan. We believe, 

Sierra Club believes, that ninety percent removal of SO2 is 

best available and should be achieved through that -- either 

one of those two control technologies. (Nachy Kanfer, 

representing Sierra Club) 

Response 25: USEPA recommended in the BART guidelines that states “use 

CALPUFF as a screening application in estimating the degree of 

visibility improvement that may reasonably be expected in order to 

inform the BART determination.” USEPA further clarifies “states 

make a BART determination based on the estimates available for 

each criterion, and as the CAA does not specify how the State 

should take these factors into account, the States are free to 

determine the weight and significance to be assigned to each 

factor. CALPUFF accordingly is an appropriate application for use 

in combination with an analysis of the other statutory factors, to 

inform decisions related to BART.” 

Upon further review, Ohio EPA concurs that 60% control of SO2 

emissions does not adequately address BART for P.H. Glatfelter. 

Therefore, it was decided that 90% control of SO2 is appropriate as 

BART. Ohio EPA and P.H. Glatfelter have worked together 

extensively, in conjunction with consultation between USEPA and 

the FLMs, to develop an appropriate BART strategy that achieves a 

90% reduction in SO2 emissions. P.H. Glatfelter will implement an 

alternative program to BART as allowed under 40 CFR 

51.308(e)(2). An alternative BART measure must achieve greater 

reasonable progress than would be achieved through the installation 

and operation of BART (90 percent SO2 ). This approach includes 

installing control technology sufficient to achieve greater than BART 

SO2 removal on boiler numbers B002 and B003 or permanently 

shutting down the boiler(s). Controlling both boilers at 90 percent 

would have resulted in limiting SO2 emissions to 24,931 pounds 

per day. Under this alternative the boilers will be limited to emitting 

24,930 pounds per day. Ohio EPA has incorporated this 

requirement into a federally enforceable permit as discussed and 

included in the revised Regional Haze SIP. 
Page | 38 

Comment 26: We also caution that the current assessment of visibility 

effects at from the Glatfelter facility with the 60 percent 

reduction scenario did not appear to include impacts from 

condensable particulates that may be substantially greater 

than those from the filterable particulates modeled. For 

several years we have posted recommendations on our 

website for speciating particulates using EPA emission 

factors. In order for ODAPC to exempt the Glatfelter facility 

from BART, it must show that that Glatfelter’s impacts do not 

exceed the visibility exemption thresholds when all visibility 

impairing emissions are modeled appropriately. The 

documentation included with the SIP does not make such a 

showing. Even if such a demonstration is successful, 

establishment of emissions limits needed to remove the 

Glatfelter facility from consideration for BART must address 

these emissions. (National Park Service and U.S. Fish and 

Wildlife Service) 

Response 26: As discussed in the comment and response above, LADCO 

performed an analysis of 149 BART eligible sources in the LADCO 

states’ area and found that PM emissions were insignificant and; 

therefore, excluded PM from the analysis. Specifically, CAMx was 

run with all point source PM emissions eliminated (“zeroed-out”) to 

assess the contribution of these species to visibility impairment. 

The model results show that these emissions do not contribute to 

visibility impairment (i.e., less than a 0.5 dv impact in any Class I 

area). Because the PM emissions from just the BART-eligible 

sources are much less than those from all point sources, the 

visibility impact of these emissions from the BART-eligible sources 

will be much less than 0.5 dv in any Class I area. Thus, these 

emissions can be excluded from BART review. 

We do not believe the lack of condensable particulates in this 

modeling would change the outcome for Glatfelter, especially in 

light of the alternative BART option selected as discussed above. 

Also note, both of the Glatfelter boilers are controlled for particulate 

emissions by an electrostatic precipitator. 

In addition, USEPA guidance does not require PM condensable 

input into modeling: “after the “selected” 2005 emissions inventory 

was compiled, EPA reviewed the PM emissions data for 

completeness. Ideally, five species of PM should be reported: 

PM10-Primary (PM10-PRI), PM2.5-Primary (PM25-PRI), PM10-

Filterable (PM10-FIL), PM2.5-Filterable (PM25-FIL), and PMCondensable (PM-CON). At the very least, PM10-PRI and PM25-
Page | 39 

PRI are required as inputs for emissions modeling.” 

http://www.epa.gov/ttn/chief/net/2005_nei_point.pdf 

Comment 27: The SIP identifies the Overfire Air and Sorbent Injection 

System (OASIS) as BART (page 21 of 37). OASIS is one 

technology that was evaluated in the Engineering Analysis 

process. Glatfelter is prepared to accept that the emission 

levels achieved by OASIS can serve as BART; however, as 

indicated in Appendix D, Glatfelter should be permitted to 

select alternative technologies or strategies that achieve 

emission levels equivalent or better than levels based on the 

control capabilities of OASIS. (P.H. Glatfelter)

Response 27: Ohio EPA agrees and will amend the SIP to clarify that a specific 

technology will not be required but rather a specific reduction. 

Comment 28: The source can take voluntary emissions limits to reduce its 

impact below the threshold that triggers BART assessment. 

However, those emissions limits are not BART. In addition 

those emissions limits should be met more quickly than the 

five year implementation period for a BART-determined limit. 

Such an approach also needs recognize that reasonable 

progress requirements would likely require review additional 

emission reductions at that source, since such emissions 

reductions are likely very cost-effective compared with the 

alternatives. (National Park Service and U.S. Fish and Wildlife 

Service) 

 We request that ODAPC revise the Glatfelter BART 

determination to be 90 percent control. If ODAPC does not 

revise the BART determination, it could establish emissions 

limits that removes the source from BART consideration now, 

but leaves it subject to review for reasonable progress in the 

future. (National Park Service and U.S. Fish and Wildlife 

Service) 

Response 28: A restriction on emissions option was not explored and Ohio EPA 

does not intend to explore this option at this time. 

With respect to the alternative to 90% control, please see the 

previous comment’s response above. 

Comment 29: The SIP identifies (page 22 of 37) the demonstration of 

compliance with the daily emission limitation by December 31, 

2012. On July 6, 2005, US EPA published Appendix Y of 40 

CFR Part 51 “Guidelines for BART Determinations under the 
Page | 40 

Regional Haze Rule”. Section V Enforceable 

Limits/Compliance specifies that compliance limits are 

required no later than five years after EPA approves the 

Regional Haze SIP. The Regional Haze SIP was due by 

December 17, 2007; however, Ohio EPA submitted their 

Regional Haze SIP on December 31, 2008, and US EPA has up 

to one year to approve Ohio’s SIP. This would give Glatfelter 

only up to three years to attain compliance with these new 

limits. This would be less time than the SIP provides for 

electric generating units to meet BART requirements by 

complying with EPA’s Clean Air Interstate Rule (“CAIR”), 

which phases in tighter emission limits for a higher-emitting 

range of sources by the year 2015. 

 

In addition, the US EPA is expected to impose additional 

requirements that may also impact these sources and the 

selection of appropriate control technology. One such 

regulation is the vacated Industrial Boiler MACT (40 CFR Part 

63, Subpart DDDDD). That regulation will likely impose 

emission control requirements for a range of hazardous 

pollutants which could very well affect the cost or 

effectiveness of the BART controls if those controls are not 

designed to reflect the ultimate Boiler MACT requirements as 

well. 

Given the delay in the submittal and approval of the SIP, and 

the uncertainty of US EPA’s response as well as potential 

future upcoming regulations such as the Boiler MACT rule, it 

is impossible to adequately design, order, and install control 

equipment by the date suggested. Glatfelter urges Ohio EPA 

to require compliance no earlier than the full five (5) years after 

US EPA approval, as afforded by Appendix Y. That schedule 

would still be well within the 2018 timeframe set out for SIP 

reassessment. (P.H. Glatfelter) 

Response 29: Ohio EPA has concern with the BART Guidelines and the potential 

for delay in USEPA approving Regional Haze SIPs for the various 

states. However, after consideration of the regulatory requirements 

and this comment Ohio EPA will revise the requirement to provide 

for implementation of the controls by December 31, 2014. This will 

assure reductions are achieved during the first planning period 

regardless of when USEPA reviews and acts on the SIP submittal. 

Comment 30: As mentioned in the Long Term Strategy (page 27 of 37), the 

current bleak economic condition in Ohio precludes justifying 

additional haze reductions covering a range of additional 
Page | 41 

sources. The economic conditions in Ohio and across the 

United States are unprecedented. When Glatfelter submitted 

its BART Engineering Analysis to the Ohio EPA in the fall of 

2007, the economic conditions were quite different. Due to 

these unfortunate and impactful economic times, Glatfelter’s 

Cost Impact Evaluation and Financial Analyses included in the 

Engineering Analysis (Appendix G) must be reconsidered. 

Glatfelter should be given the opportunity to reevaluate the 

cost impact and resubmit the reevaluation for consideration. 

(P.H. Glatfelter) 

Response 30: Ohio EPA recognizes the current economic conditions and how 

fluctuations in economic conditions can occur over time. Ohio EPA 

and P.H. Glatfelter have worked together extensively since this 

comment was submitted. Additional economic analyses have been 

conducted and both parties have agreed on a control option as 

discussed in the previous comments and responses. 

END 
Ross County

PUBLIC NOTICE

ISSUANCE OF DRAFT AIR POLLUTION Permit;;Fo-lnstall

P. H. Glatfelter Company - Chillicothe Facility

Issue Date: 1/5/2011

Permit Number: P0103673

Permit Type: Administrative Modification

Permit Description: P.H. Glatfelter is requesting an Administrative Mnr!ltl"I>t,

regarding Best Available Retrofit Technology (BART) for emissions units

NO.8 Coal Boiler.

Facility Location: P. H. Glatfelter Company - Chillicothe Facility

401 South Paint St., P.O. Box 2500

Chillicothe, OH 45601

Facility Description: Paper (except Newsprint) Mills

to include requirements

- NO.7 Coal Boiler, and B003 c

Chris Korleski, Director of the Ohio Environmental Protection Agency, 50 V\f~SfTown Street, Columbu.s Ohio,

has issued a draft action of an air pollution control permit-to-install (PTI) f0r-?-oair contaminant SOUn::eat the

location identified above on the date indicated. USEPA's 1999 Regional HC\zerule requires Ohio to have

additional controls for certain sources that contribute to visibility impairment in Class I areas. The purpose of

this administrative modification is to fulfill this requirement by incorporating~,l\RT to reduce emissions of sulfur

dioxide from P.H. Glatfelter's two coal-fired boilers. Glatfelter will be implel11Elnting an alternative pr9~ram to

BART as allowed under 40 CFR 51.308(e)(2). An alternative BART measYf~:ll1Ust achieve greaterreasonai:Jle

progress than would be achieved through the installation and operation oftrC\?itional BART. The sulfur dioxige

requirements being incorporated into this permit constitute a reduction in slJlf~r dioxide emissions otrpore than

ninety percent compared to the concentrations emitted for Which P.H. Glatf~lt!:)r was determined to c.8rtribut~

to visibility impairment. Once finalized, the BART requirements will be fed~rC\lly enforceable and incPrPorated

into Ohio's final Regional Haze State Implementation Plan (SIP). Addition~ljnformation regarding Obio's

Regional Haze SIP, and the analysis conducted to determine P.H. Glatfelt",r'§,SART requirements, can be

found on Ohio EPA's Regional Haze website at: http://www.epa.ohio.gov/dagc/SIP/haze.aspx.

Pursuant to Part C, Subpart 2, of Title I of the Clean Air Act, Ohio EPA is reqUired to establish a SIP to address

Ohio's impact on visibility in Class I areas. The above-mentioned BART reqyirements are a part of Ohio's SIP

and the draft administrative modification will be submitted to USEPA as a modification of the SIP. The

abovementioned hearing shall be considered the pUblic hearing for this portion of the SIP submittal.

Comments concerning this draft action, or a request for a public meeting, must be sent in writing no later than

thirty (30) days from the date this notice is published. All comments, questions, requests for permit applications

or other pertinent documentation, and correspondence concerning this action must be directed to Cara Cherry

at Ohio EPA DAPC, Southeast District Office, 2195 Front Street, Logan, OH43138 or (740)385-8501. The

permit can be downloaded from the Web page: www.epa.ohio.gov/dapc
OC:PA

[ ') 0 ;) "-

20/1 FEB -7 PM 3: 22

GLATFELTER

Beyond Poper

February 4, 2011

Andrew Hall

Permit Review/Development Section

Ohio EPA, DAPC

Lazarus Government Center

50 West Town Street, Suite 700

Columbus,OH 43215

Bruce Weinberg

Ohio EPA, DAPC

Southeast District Office

2195 Front Street

Logan, OH 43138

Re: Draft Air Pollution Permit-To-Install; Facility ID 0671010028

Dear Mr. Hall and Mr. Weinberg:

PH. Glatfelter Company - Chillicothe Facility (Glatfelter) is pleased to provide the following

comments to the administrative modification to incorporate the U.S. EPA's Regional Haze

Regulations best available retrofit technology (BART) requirements into the terms and conditions

for emissions units B002 and B003. The Chillicothe Facility and Ohio EPA have worked

cooperatively for a number of years on these requirements and Glatfelter appreciates the efforts

and considerations of your staff.

Draft PTI Reference (citations Comment apply to both B002 and B003)

B. Facility-Wide Terms and It may be appropriate to change all language referencing

Conditions; pg 12; 1.b)(1)f and the NOx BUdget Trading program to reflect OAC 3745-109.

(2)a. rule citation and reference In addition, allowances for B001 should be included as

lanquaqe these are allocated until 2014 (P. 12, 2.b».

2. c)(2) - Reference to B013 as a NO.6 Wood Residue Boiler is the primary incineration point

primary incineration point for for HVLC NCGs; however, at this time, the NCG Incinerator

LVHC NCGs and stripper off- is the primary incineration point for LVHC NCGs and SOGs.

qasses (SOGs)

(2) e)(1), e)(4), e)(5)-"... the The suggested language is "... the permittee shall submit

permittee shall submit reports reports by January 31, April 30, July 31, and October 31...".

within one month following the This language is consistent with the quarterly excess

end of each calendar quarter... "; emission reports in the same section of these draft PTls as

"Each report shall be submitted well as the facility's other Title V Permit requirements.

within 30 days....";" ... shall submit

reoorts within one month... "

As we have previously discussed with the Agency, Glatfelter is concerned with applicable

proposed regulations, specifically Boiler MACT, and how their requirements may impact the

Environmental Department 232 East 8th Street· Chillicothe, OH 45601-0997 U.S.A.· Phone 740.772.3111 • Fax 740.772.0014

www.glatfelter.com
Mr. Hall and Mr. Weinberg

February 4, 2011

Page 2

compliance strategy as well as the implementation schedule of BART. Glatfelter will continue to

work with the Agency as these regulations evolve and the BART strategy is developed.

Glatfelter appreciates your consideration of these comments and looks forward to working with

Ohio EPA on implementation of these requirements. Glatfelter reserves the right to submit future

comments on the regional haze regulations for B002 and B003 as appropriate.

Please also note that we have a new mailing address:

P.H. Glatfelter Company - Chillicothe Facility

232 East 8th Street

Chillicothe, OH 45601

If you have any questions concerning these comments, please contact me at 740.772.3387.

Sincerely,

r,;'tt'1 /.;v, ('ti'Lt.---

Kathy Wiedeman

Director, Environmental, Health and Safety

KAW:tc

File 3.28.1

Hall- UPS 1Z 476 298 03 9517 5253

Weinber9 - UPS lZ 476 298 03 9619 2643

c: Skip Missimer - Global Director, Environmental Affairs
Environmental

Protection Agency

John R. Kasich, Governor

Mary Taylor, Lt. Governor

Scott J. Nally, Director

February 16, 2011

Kathy Wiedeman, Director

Environmental, Health and Safety

P.H. Glatfelter Company

Chillicothe Facility

232 East 8th Street

Chillicothe, OH 45601

Re: Comments on draft Permit-to-Install P0103673; Facility I.D. 0671010028

Dear Ms. Wiedeman:

Your comments on the draft administrative modification of PTI P0103673 were received

by our office on February 7, 2011. The statements below are provided in response to

your comments.

NOx Budget Trading Program Issues:

We cannot remove the OAC Chapter 3745-14 (NOx SIP call) requirements as they are

being maintained as a support/back up to the temporary federal CAIR program,

currently in place, until the final revisions to the temporary CAIR program, or a

permanent replacement are promulgated. At that time, Ohio EPA will rescind those

portions of OAC Chapter 3745-14 dealing with both EGUs and non-EGUs that were

subject to the NOx SIP call.

The NOx Budget Trading Program allowances from OAC Chapter 3745-14 for B001

were not included in this administrative modification of PTI 06-07700 since the

administrative change only affected emissions units B002 and B003. The OAC Chapter

3745-14 allocations for B001 are still in effect and are listed in PTI 06-07700.

We considered adding but did not include the OAC Chapter 3745-109 provisions in the

draft permit due to the current state of the federal CAIR rule. As mentioned above, we

know that the OAC Chapter 3745-109 provisions will replace the OAC Chapter 3745-14

provisions when the federal rules are promulgated. While we hoped to address these

provisions in the renewal Title V permit, we can include a reference to the OAC Chapter

3745-109 provisions after the OAC Chapter 3745-14 provisions in the Facility Terms

and Conditions section of the permit as follows:

Southeast District Office

2195 Front Street

Logan,OH 43138·8637

740 I 385 8501

740 I 385 6490 (fax)

www.epa.ohio.gov
Kathy Wiedeman, Director

P.H. Glatfelter Company

February 16, 2011

Page 2

Note: Ohio EPA DAPC has completed rule amendments for OAC Chapter 3745-14,

specifically OAC rule 3745-14-01 and OAC rule 3745-14-06, to facilitate the

transition of the affected units from OAC Chapter 3745-14 into the federal Clean

Air Interstate Rule (CAIR) program and to begin the process of "sunsetting" the

parts of OAC Chapter 3745-14 which will no longer be needed as a result of

Ohio's CAIR rules (OAC Chapter 3745-109). The revised applicability section of

OAC Chapter 3745-14 allows the rules to remain available as a backup until court

required revisions to the federal CAIR program have been completed. The

revision to OAC rule 3745-14-01 (C)(2)(a) requires all affected units to be subject to

and meet the requirements of Ohio's CAIR program beginning in 2009. Should

U.S. EPA eliminate or suspend the CAIR program, this revision would require

these units to revert back and meet the requirements of OAC Chapter 3745-14,

provided a NOx allowance tracking system is maintained by U.S. EPA.

Clean Air Interstate Rule - OAC Chapter 3745-109

The permittee shall ensure that any CAIR NOx, S02, or NOx ozone season units

complies with the requirements of OAC Chapter 3745-109, which includes

submitting timely permit applications. The requirements of this rule will be

specified in the Title V permit issued to this facility.

Please let me know if the above language is acceptable or if there is alternate language

you would like to propose.

Primary Incineration Point Issues:

The following language was taken directly from PTI 06-07700, issued on July 14, 2005:

"This emissions unit shall not be taken out of service at the same time, as both

emissions units B003 (No.8 Coal Boiler) and B013 (Wood Waste Boiler), except during

emergency outages. B013 shall serve as the primary incineration point for High-Volume

Low Concentration (HVLC) Non-Condensable Gases (NCGs), Low-Volume High

Concentration (LVHC) NCG's and Stripper Off-Gases (SaG's). Either B002 or B003

shall serve as back-up control devices for NCG combustion."

Based upon your comments, the language in term 2c)(2) should indicate the following:

This emissions unit shall not be taken out of service at the same time, as

emissions units B003 (No.8 Coal Boiler), B013 (Wood Waste Boiler), and NC-101

(NCG Incinerator serving emissions units P014 and P016) except during

emergency outages. B013 shall serve as the primary incineration point for highvolume low concentration NCG. NC-101 shall serve as the primary incineration

point for low-volume high concentration NCG and stripper off-gases. Either B002

or B003 shall serve as back-up control devices for NeG combustion.

Please let me know if the above language is correct or if NC-1 01 has a different mode

of operation (I.e., the incinerator has an interlock that shuts down the unit and the NCG

are not vented to the atmosphere or if NC-101 uses B013 as its back-up control device).

In addition, please note that STARS2 does not currently list B003 as a back-up control

device.
Kathy Wiedeman, Director

P.H. Glatfelter Company

February 16, 2011

Page 3

Reporting Issues:

They quarterly reporting dates in 2e)(1) and 2e)(5) are correct; however, we can change

the language in the first paragraph of each term to remove ·the reference to "within one

month following the end of each calendar quarter" if you believe that the language

causes any confusion. It does match with the dates specified at the end of these terms

(i.e., one month following the end of the fourth calendar quarter would be January 31,

one month follOWing the end of the first calendar quarter would be April 30, etc.).

The language in 2e)(4) is different for a reason. We do not expect the facility to have

deviations of .this requirement (except during emergency outages); therefore, we have

only required a report to be submitted 30 days after the deviation occurs. This

requirement is less onerous than the standard quarterly deviation reporting. However,

we can change the reporting time frame for term 2e)(4) if you would prefer to have all of

the reports for these units submitted on a quarterly basis.

MACTlssue:

We certainly understand your concerns with the forthcoming MACT standards and we

will continue to work with you to address any potential conflicts with the proposed BART

compliance strategy for the Chillicothe facility. Fortunately, the final BART strategy to

achieve the required emissions reductions does not have to be formalized until one year

prior to implementation. Hopefully, this will allow us some lime to work out any potential

conflicts.

Once you have had a chance to review our responses, please contact me

(740.380.5257 or bruce.weinberg@epa.state.oh.us ) and let me know if you would like

to arrange a conference call to discuss any outstanding issues. .

Sineere::,:ly!-J..--_.....

BDW/mlm

cc: Dan Canter, DAPC, SEDO

Steve Lowry, Supervisor, DAPC, SEDO

Laurie Stevenson, Director's Office

Jim Sferra, Assistant Chief, SEDO

Jennifer Hunter, Manager, SIP Section, DAPC

Andrew Hall, Manager, Permit Review/Development Section, DAPC

3/7/2

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Response to Comments 

P. H. Glatfelter Company - Chillicothe Facility

Permit Number: P0103673 

Facility ID: 0671010028 

Response to Comments 

Response to comments for: Permit-To-Install 

Facility ID: 0671010028 

Facility Name: P. H. Glatfelter Company - Chillicothe Facility 

Facility Description: Chillicothe Paper Mill. 

Facility Address: 

232 East 8th Street 

Chillicothe, OH 45601 

Ross County 

Permit #: P0103673, Administrative Modification 

A public notice for the draft permit issuance was published in the Ohio EPA Weekly Review and appeared in 

the Chillicothe Gazette on 01/12/2011. The comment period ended on 02/11/2011. 

Hearing date (if 

held) N/A 

Hearing Public 

Notice Date (if 

different from draft 

public notice) 

N/A 

The following comments were received during the comment period specified. Ohio EPA reviewed and 

considered all comments received during the public comment period. By law, Ohio EPA has authority to 

consider specific issues related to protection of the environment and public health. Often, public concerns fall 

outside the scope of that authority. For example, concerns about zoning issues are addressed at the local 

level. Ohio EPA may respond to those concerns in this document by identifying another government agency 

with more direct authority over the issue. 

 

In an effort to help you review this document, the questions are grouped by topic and organized in a consistent 

format. PDF copies of the original comments in the format submitted are available upon request. 

1. Topic: NOx Budget Trading Program

a. Comment: “It may be appropriate to change all language referencing the NOx Budget Trading 

program to reflect OAC 3745-109. In addition, allowances for B001 should be included as these 

are allocated until 2014.”

b. Response: We cannot remove the OAC Chapter 3745-14 (NOx SIP call) requirements as they 

are being maintained as a support/back up to the temporary federal CAIR program, currently in 

place, until the final revisions to the temporary CAIR program, or a permanent replacement are 

promulgated. At that time, Ohio EPA will rescind those portions of OAC Chapter 3745-14 

dealing with both EGUs and non-EGUs that were subject to the NOx SIP call.

The NOx Budget Trading Program allowances from OAC Chapter 3745-14 for B001 were not 

included in this administrative modification of PTI 06-07700 since the administrative change only 

affected emissions units B002 and B003. The OAC Chapter 3745-14 allocations for B001 are 

still in effect and are listed in PTI 06-07700. 
Response to Comments 

P. H. Glatfelter Company - Chillicothe Facility

Permit Number: P0103673 

Facility ID: 0671010028 

We considered adding but did not include the OAC Chapter 3745-109 provisions in the draft 

permit due to the current state of the federal CAIR rule. As mentioned above, we know that the 

OAC Chapter 3745-109 provisions will replace the OAC Chapter 3745-14 provisions when the 

federal rules are promulgated. While we hoped to address these provisions in the renewal Title 

V permit, we can include a reference to the OAC Chapter 3745-109 provisions after the OAC 

Chapter 3745-14 provisions in the Facility Terms and Conditions section of the permit as 

follows: 

Note: Ohio EPA DAPC has completed rule amendments for OAC Chapter 3745-14, specifically 

OAC rule 3745-14-01 and OAC rule 3745-14-06, to facilitate the transition of the affected units 

from OAC Chapter 3745-14 into the federal Clean Air Interstate Rule (CAIR) program and to 

begin the process of “sunsetting” the parts of OAC Chapter 3745-14 which will no longer be 

needed as a result of Ohio’s CAIR rules (OAC Chapter 3745-109). The revised applicability 

section of OAC Chapter 3745-14 allows the rules to remain available as a backup until court 

required revisions to the federal CAIR program have been completed. The revision to OAC rule 

3745-14-01(C)(2)(a) requires all affected units to be subject to and meet the requirements of 

Ohio’s CAIR program beginning in 2009. Should U.S. EPA eliminate or suspend the CAIR 

program, this revision would require these units to revert back and meet the requirements of 

OAC Chapter 3745-14, provided a NOx allowance tracking system is maintained by U.S. EPA. 

Clean Air Interstate Rule - OAC Chapter 3745-109

The permittee shall ensure that any CAIR NOx, SO2, or NOx ozone season units complies with 

the requirements of OAC Chapter 3745-109, which includes submitting timely permit 

applications. The requirements of this rule will be specified in the Title V permit issued to this 

facility. 

The above-referenced language was agreed to in a March 3, 2011 conference call with 

Glatfelter. 

2. Topic: NCG Incineration

a. Comment: “No. 6 Wood Residue Boiler is the primary incineration point for HVLC NCGs; 

however, at this time, the NCG incinerator is the primary incineration point for LVHC NCGs and 

SOGs.” 

b. Response: During a March 3, 2011 conference call with Glatfelter, clarification was provided 

regarding the primary points of incineration for the HVLC and LVHC NCGs and SOGs. 

Emissions unit B013 is the primary point of incineration for HVLC NCG and either B002 or B003 

will serve as the back-up control device. The NCG incinerator is the primary point of incineration 

for the LVHC NCG and SOG. The facility’s lime kiln will serve as the back-up control device for 

the NCG incinerator. P0103673 has been revised to reflect this control strategy. 

3. Topic: Reporting time frame for term 2e)(4)

a. Comment: The reporting time frame for this term is not consistent with the other reporting time 

frames. 

b. Response: The language in 2e)(4) is different for a reason. We do not expect the facility to have 

deviations of this requirement (except during emergency outages); therefore, we have only 
Response to Comments 

P. H. Glatfelter Company - Chillicothe Facility

Permit Number: P0103673 

Facility ID: 0671010028 

required a report to be submitted 30 days after the deviation occurs. This requirement is less 

onerous than the standard quarterly deviation reporting. However, we can change the reporting 

time frame for term 2e)(4) if you would prefer to have all of the reports for these units submitted 

on a quarterly basis. 

During the March 3, 2011 conference call, it was agreed that the reporting time frame for term 

2e)(4) would be made consistent with the other report time frames (i.e., quarterly). 

4. Topic: MACT requirement 

a. Comment: Glatfelter is concerned about how the Boiler MACT requirements may impact the 

compliance strategy as well as the implementation schedule for BART.

b. Response: We certainly understand your concerns with the forthcoming MACT standards and 

we will continue to work with you to address any potential conflicts with the proposed BART 

compliance strategy for the Chillicothe facility.

FINAL 

Division of Air Pollution Control 

Permit-to-Install 

for 

P. H. Glatfelter Company - Chillicothe Facility 

Facility ID: 0671010028 

Permit Number: P0103673 

Permit Type: Administrative Modification 

Issued: 3/7/2011 

Effective: 3/7/2011 

 
 
Division of Air Pollution Control 

Permit-to-Install 

for 

P. H. Glatfelter Company - Chillicothe Facility 

Table of Contents 

Authorization ......................................................................................................................................................... 1

A. Standard Terms and Conditions ..................................................................................................................... 3

1. Federally Enforceable Standard Terms and Conditions ...........................................................................4

2. Severability Clause ................................................................................................................................... 4

3. General Requirements .............................................................................................................................. 4

4. Monitoring and Related Record Keeping and Reporting Requirements ................................................... 5

5. Scheduled Maintenance/Malfunction Reporting ....................................................................................... 6

6. Compliance Requirements ........................................................................................................................ 6

7. Best Available Technology ........................................................................................................................ 7

8. Air Pollution Nuisance ............................................................................................................................... 7

9. Reporting Requirements ........................................................................................................................... 7

10. Applicability ............................................................................................................................................... 8

11. Construction of New Sources(s) and Authorization to Install .................................................................... 8

12. Permit-To-Operate Application ................................................................................................................. 9

13. Construction Compliance Certification ...................................................................................................... 9

14. Public Disclosure ...................................................................................................................................... 9

15. Additional Reporting Requirements When There Are No Deviations of Federally Enforceable Emission 

Limitations, Operational Restrictions, or Control Device Operating Parameter Limitations ...................... 9

16. Fees ........................................................................................................................................................ 10

17. Permit Transfers ..................................................................................................................................... 10

18. Risk Management Plans ......................................................................................................................... 10

19. Title IV Provisions ................................................................................................................................... 10

B. Facility-Wide Terms and Conditions ............................................................................................................. 11

C. Emissions Unit Terms and Conditions .......................................................................................................... 19

1. B002, No.7 Coal Boiler ........................................................................................................................... 20

2. B003, No.8 Coal Boiler ........................................................................................................................... 31

Final Permit-to-Install 

P. H. Glatfelter Company - Chillicothe Facility

Permit Number: P0103673 

Facility ID: 0671010028 

Effective Date: 3/7/2011

Page 1 of 41

Authorization 

Facility ID: 0671010028 

Facility Description: Chillicothe Paper Mill. 

Application Number(s): M0000208 

Permit Number: P0103673 

Permit Description: The permit action is an administrative modification of Permit-to-Install 06-07700 (July 14, 

2005) to incorporate the U.S. EPA¿s Regional Haze Regulations best available retrofit 

technology (BART) requirements into the terms and conditions for emissions units B002 

and B003. This permit-to-install modification supercedes the requirements specified in 

Permit-to-Install 06-07700 for emissions units B002 and B003. 

Permit Type: Administrative Modification 

Permit Fee: $0.00 

Issue Date: 3/7/2011 

Effective Date: 3/7/2011 

This document constitutes issuance to: 

P. H. Glatfelter Company - Chillicothe Facility 

401 South Paint St. 

P.O. Box 2500 

Chillicothe, OH 45601 

of a Permit-to-Install for the emissions unit(s) identified on the following page. 

Ohio EPA District Office or local air agency responsible for processing and administering your permit: 

Ohio EPA DAPC, Southeast District Office 

2195 Front Street 

Logan, OH 43138 

(740)385-8501 

The above named entity is hereby granted a Permit-to-Install for the emissions unit(s) listed in this section 

pursuant to Chapter 3745-31 of the Ohio Administrative Code. Issuance of this permit does not constitute 

expressed or implied approval or agreement that, if constructed or modified in accordance with the plans 

included in the application, the emissions unit(s) of environmental pollutants will operate in compliance with 

applicable State and Federal laws and regulations, and does not constitute expressed or implied assurance 

that if constructed or modified in accordance with those plans and specifications, the above described 

emissions unit(s) of pollutants will be granted the necessary permits to operate (air) or NPDES permits as 

applicable. 

This permit is granted subject to the conditions attached hereto. 

Ohio Environmental Protection Agency 

Scott J. Nally 

Director 
Final Permit-to-Install 

P. H. Glatfelter Company - Chillicothe Facility

Permit Number: P0103673 

Facility ID: 0671010028 

Effective Date: 3/7/2011

Page 2 of 41

Authorization (continued) 

Permit Number: P0103673 

Permit Description: The permit action is an administrative modification of Permit-to-Install 06-07700 (July 14, 

2005) to incorporate the U.S. EPA¿s Regional Haze Regulations best available retrofit 

technology (BART) requirements into the terms and conditions for emissions units B002 

and B003. This permit-to-install modification supercedes the requirements specified in 

Permit-to-Install 06-07700 for emissions units B002 and B003. 

Permits for the following Emissions Unit(s) or groups of Emissions Units are in this document as indicated 

below: 

Emissions Unit ID: B002 

 Company Equipment ID: No.7 Coal Boiler 

 Superseded Permit Number: 06-07700 

 General Permit Category and Type: Not Applicable 

Emissions Unit ID: B003 

 Company Equipment ID: No.8 Coal Boiler 

 Superseded Permit Number: 06-07700 

 General Permit Category and Type: Not Applicable 

 
Final Permit-to-Install 

P. H. Glatfelter Company - Chillicothe Facility

Permit Number: P0103673 

Facility ID: 0671010028 

Effective Date: 3/7/2011

Page 3 of 41

A. Standard Terms and Conditions 
Final Permit-to-Install 

P. H. Glatfelter Company - Chillicothe Facility

Permit Number: P0103673 

Facility ID: 0671010028 

Effective Date: 3/7/2011

Page 4 of 41

1. Federally Enforceable Standard Terms and Conditions 

a) All Standard Terms and Conditions are federally enforceable, with the exception of those listed 

below which are enforceable under State law only: 

(1) Standard Term and Condition A.2.a), Severability Clause 

(2) Standard Term and Condition A.3.c) through A. 3.e) General Requirements 

(3) Standard Term and Condition A.6.c) and A. 6.d), Compliance Requirements 

(4) Standard Term and Condition A.9., Reporting Requirements 

(5) Standard Term and Condition A.10., Applicability 

(6) Standard Term and Condition A.11.b) through A.11.e), Construction of New Source(s) 

and Authorization to Install 

(7) Standard Term and Condition A.14., Public Disclosure 

(8) Standard Term and Condition A.15., Additional Reporting Requirements When There 

Are No Deviations of Federally Enforceable Emission Limitations, Operational 

Restrictions, or Control Device Operating Parameter Limitations 

(9) Standard Term and Condition A.16., Fees 

(10) Standard Term and Condition A.17., Permit Transfers 

2. Severability Clause 

a) A determination that any term or condition of this permit is invalid shall not invalidate the force or 

effect of any other term or condition thereof, except to the extent that any other term or condition 

depends in whole or in part for its operation or implementation upon the term or condition 

declared invalid. 

b) All terms and conditions designated in parts B and C of this permit are federally enforceable as 

a practical matter, if they are required under the Act, or any of its applicable requirements, 

including relevant provisions designed to limit the potential to emit of a source, are enforceable 

by the Administrator of the U.S. EPA and the State and by citizens (to the extent allowed by 

section 304 of the Act) under the Act. Terms and conditions in parts B and C of this permit shall 

not be federally enforceable and shall be enforceable under State law only, only if specifically 

identified in this permit as such. 

3. General Requirements 

a) The permittee must comply with all terms and conditions of this permit. Any noncompliance with 

the federally enforceable terms and conditions of this permit constitutes a violation of the Act, 

and is grounds for enforcement action or for permit revocation, revocation and re-issuance, or 

modification. 
Final Permit-to-Install 

P. H. Glatfelter Company - Chillicothe Facility

Permit Number: P0103673 

Facility ID: 0671010028 

Effective Date: 3/7/2011

Page 5 of 41

b) It shall not be a defense for the permittee in an enforcement action that it would have been 

necessary to halt or reduce the permitted activity in order to maintain compliance with the 

federally enforceable terms and conditions of this permit. 

c) This permit may be modified, revoked, or revoked and reissued, for cause. The filing of a 

request by the permittee for a permit modification, revocation and reissuance, or revocation, or 

of a notification of planned changes or anticipated noncompliance does not stay any term and 

condition of this permit. 

d) This permit does not convey any property rights of any sort, or any exclusive privilege. 

e) The permittee shall furnish to the Director of the Ohio EPA, or an authorized representative of 

the Director, upon receipt of a written request and within a reasonable time, any information that 

may be requested to determine whether cause exists for modifying or revoking this permit or to 

determine compliance with this permit. Upon request, the permittee shall also furnish to the 

Director or an authorized representative of the Director, copies of records required to be kept by 

this permit. For information claimed to be confidential in the submittal to the Director, if the 

Administrator of the U.S. EPA requests such information, the permittee may furnish such 

records directly to the Administrator along with a claim of confidentiality. 

4. Monitoring and Related Record Keeping and Reporting Requirements 

a) Except as may otherwise be provided in the terms and conditions for a specific emissions unit, 

the permittee shall maintain records that include the following, where applicable, for any 

required monitoring under this permit: 

(1) The date, place (as defined in the permit), and time of sampling or measurements. 

(2) The date(s) analyses were performed. 

(3) The company or entity that performed the analyses. 

(4) The analytical techniques or methods used. 

(5) The results of such analyses. 

(6) The operating conditions existing at the time of sampling or measurement. 

b) Each record of any monitoring data, testing data, and support information required pursuant to 

this permit shall be retained for a period of five years from the date the record was created. 

Support information shall include, but not be limited to all calibration and maintenance records 

and all original strip-chart recordings for continuous monitoring instrumentation, and copies of all 

reports required by this permit. Such records may be maintained in computerized form. 

c) Except as may otherwise be provided in the terms and conditions for a specific emissions unit, 

the permittee shall submit required reports in the following manner: 

(1) Reports of any required monitoring and/or recordkeeping of federally enforceable 

information shall be submitted to the Ohio EPA DAPC, Southeast District Office. 

(2) Quarterly written reports of (i) any deviations from federally enforceable emission

limitations, operational restrictions, and control device operating parameter limitations, 
Final Permit-to-Install 

P. H. Glatfelter Company - Chillicothe Facility

Permit Number: P0103673 

Facility ID: 0671010028 

Effective Date: 3/7/2011

Page 6 of 41

excluding deviations resulting from malfunctions reported in accordance with OAC rule 

3745-15-06, that have been detected by the testing, monitoring and recordkeeping 

requirements specified in this permit, (ii) the probable cause of such deviations, and (iii) 

any corrective actions or preventive measures taken, shall be made to the Ohio EPA 

DAPC, Southeast District Office. The written reports shall be submitted (i.e., 

postmarked) quarterly, by January 31, April 30, July 31, and October 31 of each year 

and shall cover the previous calendar quarters. See A.15. below if no deviations 

occurred during the quarter. 

(3) Written reports, which identify any deviations from the federally enforceable monitoring, 

recordkeeping, and reporting requirements contained in this permit shall be submitted 

(i.e., postmarked) to the Ohio EPA DAPC, Southeast District Office every six months, by 

January 31 and July 31 of each year for the previous six calendar months. If no 

deviations occurred during a six-month period, the permittee shall submit a semi-annual 

report, which states that no deviations occurred during that period. 

(4) This permit is for an emissions unit located at a Title V facility. Each written report shall 

be signed by a responsible official certifying that, based on information and belief formed 

after reasonable inquiry, the statements and information in the report are true, accurate, 

and complete. 

d) The permittee shall report actual emissions pursuant to OAC Chapter 3745-78 for the purpose 

of collecting Air Pollution Control Fees. 

5. Scheduled Maintenance/Malfunction Reporting 

Any scheduled maintenance of air pollution control equipment shall be performed in accordance with 

paragraph (A) of OAC rule 3745-15-06. The malfunction, i.e., upset, of any emissions units or any 

associated air pollution control system(s) shall be reported to the Ohio EPA DAPC, Southeast District 

Office in accordance with paragraph (B) of OAC rule 3745-15-06. (The definition of an upset condition 

shall be the same as that used in OAC rule 3745-15-06(B)(1) for a malfunction.) The verbal and written 

reports shall be submitted pursuant to OAC rule 3745-15-06. 

Except as provided in that rule, any scheduled maintenance or malfunction necessitating the shutdown 

or bypassing of any air pollution control system(s) shall be accompanied by the shutdown of the 

emission unit(s) that is (are) served by such control system(s). 

6. Compliance Requirements 

a) The emissions unit(s) identified in this Permit shall remain in full compliance with all applicable 

State laws and regulations and the terms and conditions of this permit. 

b) Any document (including reports) required to be submitted and required by a federally 

applicable requirement in this permit shall include a certification by a responsible official that, 

based on information and belief formed after reasonable inquiry, the statements in the 

document are true, accurate, and complete. 

c) Upon presentation of credentials and other documents as may be required by law, the permittee 

shall allow the Director of the Ohio EPA or an authorized representative of the Director to: 
Final Permit-to-Install 

P. H. Glatfelter Company - Chillicothe Facility

Permit Number: P0103673 

Facility ID: 0671010028 

Effective Date: 3/7/2011

Page 7 of 41

(1) At reasonable times, enter upon the permittee's premises where a source is located or 

the emissions-related activity is conducted, or where records must be kept under the 

conditions of this permit. 

(2) Have access to and copy, at reasonable times, any records that must be kept under the 

conditions of this permit, subject to the protection from disclosure to the public of 

confidential information consistent with ORC section 3704.08. 

(3) Inspect at reasonable times any facilities, equipment (including monitoring and air 

pollution control equipment), practices, or operations regulated or required under this 

permit. 

(4) As authorized by the Act, sample or monitor at reasonable times substances or 

parameters for the purpose of assuring compliance with the permit and applicable 

requirements. 

d) The permittee shall submit progress reports to the Ohio EPA DAPC, Southeast District Office 

concerning any schedule of compliance for meeting an applicable requirement. Progress 

reports shall be submitted semiannually or more frequently if specified in the applicable 

requirement or by the Director of the Ohio EPA. Progress reports shall contain the following: 

(1) Dates for achieving the activities, milestones, or compliance required in any schedule of 

compliance, and dates when such activities, milestones, or compliance were achieved. 

(2) An explanation of why any dates in any schedule of compliance were not or will not be 

met, and any preventive or corrective measures adopted. 

7. Best Available Technology 

As specified in OAC Rule 3745-31-05, new sources that must employ Best Available Technology (BAT) 

shall comply with the Applicable Emission Limitations/Control Measures identified as BAT for each 

subject emissions unit. 

8. Air Pollution Nuisance 

The air contaminants emitted by the emissions units covered by this permit shall not cause a public 

nuisance, in violation of OAC rule 3745-15-07. 

9. Reporting Requirements 

The permittee shall submit required reports in the following manner: 

a) Reports of any required monitoring and/or recordkeeping of state-only enforceable information 

shall be submitted to the Ohio EPA DAPC, Southeast District Office. 

b) Except as otherwise may be provided in the terms and conditions for a specific emissions unit, 

quarterly written reports of (a) any deviations (excursions) from state-only required emission 

limitations, operational restrictions, and control device operating parameter limitations that have 

been detected by the testing, monitoring, and recordkeeping requirements specified in this 

permit, (b) the probable cause of such deviations, and (c) any corrective actions or preventive 

measures which have been or will be taken, shall be submitted to the Ohio EPA DAPC, 

Southeast District Office. If no deviations occurred during a calendar quarter, the permittee 
Final Permit-to-Install 

P. H. Glatfelter Company - Chillicothe Facility

Permit Number: P0103673 

Facility ID: 0671010028 

Effective Date: 3/7/2011

Page 8 of 41

shall submit a quarterly report, which states that no deviations occurred during that quarter. The 

reports shall be submitted (i.e., postmarked) quarterly, by January 31, April 30, July 31, and 

October 31 of each year and shall cover the previous calendar quarters. (These quarterly 

reports shall exclude deviations resulting from malfunctions reported in accordance with OAC 

rule 3745-15-06.) 

10. Applicability 

This Permit-to-Install is applicable only to the emissions unit(s) identified in the Permit-to-Install. 

Separate application must be made to the Director for the installation or modification of any other 

emissions unit(s). 

11. Construction of New Sources(s) and Authorization to Install 

a) This permit does not constitute an assurance that the proposed source will operate in 

compliance with all Ohio laws and regulations. This permit does not constitute expressed or 

implied assurance that the proposed facility has been constructed in accordance with the 

application and terms and conditions of this permit. The action of beginning and/or completing 

construction prior to obtaining the Director's approval constitutes a violation of OAC rule 3745-

31-02. Furthermore, issuance of this permit does not constitute an assurance that the proposed 

source will operate in compliance with all Ohio laws and regulations. Issuance of this permit is 

not to be construed as a waiver of any rights that the Ohio Environmental Protection Agency (or 

other persons) may have against the applicant for starting construction prior to the effective date 

of the permit. Additional facilities shall be installed upon orders of the Ohio Environmental 

Protection Agency if the proposed facilities cannot meet the requirements of this permit or 

cannot meet applicable standards. 

b) If applicable, authorization to install any new emissions unit included in this permit shall 

terminate within eighteen months of the effective date of the permit if the owner or operator has 

not undertaken a continuing program of installation or has not entered into a binding contractual 

obligation to undertake and complete within a reasonable time a continuing program of 

installation. This deadline may be extended by up to 12 months if application is made to the 

Director within a reasonable time before the termination date and the party shows good cause 

for any such extension. 

c) The permittee may notify Ohio EPA of any emissions unit that is permanently shut down (i.e., 

the emissions unit has been physically removed from service or has been altered in such a way 

that it can no longer operate without a subsequent "modification" or "installation" as defined in 

OAC Chapter 3745-31) by submitting a certification from the authorized official that identifies the 

date on which the emissions unit was permanently shut down. Authorization to operate the 

affected emissions unit shall cease upon the date certified by the authorized official that the 

emissions unit was permanently shut down. At a minimum, notification of permanent shut down 

shall be made or confirmed by marking the affected emissions unit(s) as “permanently shut 

down” in Ohio EPA’s “Air Services” along with the date the emissions unit(s) was permanently 

removed and/or disabled. Submitting the facility profile update will constitute notifying of the 

permanent shutdown of the affected emissions unit(s). 

d) The provisions of this permit shall cease to be enforceable for each affected emissions unit after 

the date on which an emissions unit is permanently shut down (i.e., emissions unit has been 

physically removed from service or has been altered in such a way that it can no longer operate 

without a subsequent "modification" or "installation" as defined in OAC Chapter 3745-31). All 
Final Permit-to-Install 

P. H. Glatfelter Company - Chillicothe Facility

Permit Number: P0103673 

Facility ID: 0671010028 

Effective Date: 3/7/2011

Page 9 of 41

records relating to any permanently shutdown emissions unit, generated while the emissions 

unit was in operation, must be maintained in accordance with law. All reports required by this 

permit must be submitted for any period an affected emissions unit operated prior to permanent 

shut down. At a minimum, the permit requirements must be evaluated as part of the reporting 

requirements identified in this permit covering the last period the emissions unit operated. 

No emissions unit certified by the authorized official as being permanently shut down may 

resume operation without first applying for and obtaining a permit pursuant to OAC Chapter 

3745-31. 

e) The permittee shall comply with any residual requirements related to this permit, such as the 

requirement to submit a deviation report, air fee emission report, or other any reporting required 

by this permit for the period the operating provisions of this permit were enforceable, or as 

required by regulation or law. All reports shall be submitted in a form and manner prescribed by 

the Director. All records relating to this permit must be maintained in accordance with law. 

12. Permit-To-Operate Application 

The permittee is required to apply for a Title V permit pursuant to OAC Chapter 3745-77. The 

permittee shall submit a complete Title V permit application or a complete Title V permit modification 

application within twelve (12) months after commencing operation of the emissions units covered by 

this permit. However, if the proposed new or modified source(s) would be prohibited by the terms and 

conditions of an existing Title V permit, a Title V permit modification must be obtained before the 

operation of such new or modified source(s) pursuant to OAC rule 3745-77-04(D) and OAC rule 3745-

77-08(C)(3)(d). 

13. Construction Compliance Certification 

The applicant shall identify the following dates in the online facility profile for each new emissions unit 

identified in this permit. 

a) Completion of initial installation date shall be entered upon completion of construction and prior 

to start-up. 

b) Commence operation after installation or latest modification date shall be entered within 90 days 

after commencing operation of the applicable emissions unit. 

14. Public Disclosure 

The facility is hereby notified that this permit, and all agency records concerning the operation of this 

permitted source, are subject to public disclosure in accordance with OAC rule 3745-49-03. 

15. Additional Reporting Requirements When There Are No Deviations of Federally Enforceable

Emission Limitations, Operational Restrictions, or Control Device Operating Parameter 

Limitations 

If no deviations occurred during a calendar quarter, the permittee shall submit a quarterly report, which 

states that no deviations occurred during that quarter. The reports shall be submitted quarterly (i.e., 

postmarked), by January 31, April 30, July 31, and October 31 of each year and shall cover the 

previous calendar quarters. 
Final Permit-to-Install 

P. H. Glatfelter Company - Chillicothe Facility

Permit Number: P0103673 

Facility ID: 0671010028 

Effective Date: 3/7/2011

Page 10 of 41

16. Fees 

The permittee shall pay fees to the Director of the Ohio EPA in accordance with ORC section 3745.11 

and OAC Chapter 3745-78. The permittee shall pay all applicable permit-to-install fees within 30 days 

after the issuance of any permit-to-install. The permittee shall pay all applicable permit-to-operate fees 

within thirty days of the issuance of the invoice. 

17. Permit Transfers 

Any transferee of this permit shall assume the responsibilities of the prior permit holder. The new 

owner must update and submit the ownership information via the “Owner/Contact Change” functionality 

in Air Services once the transfer is legally completed. The change must be submitted through Air 

Services within thirty days of the ownership transfer date. 

18. Risk Management Plans 

If the permittee is required to develop and register a risk management plan pursuant to section 112(r) of 

the Clean Air Act, as amended, 42 U.S.C. 7401 et seq. ("Act"), the permittee shall comply with the 

requirement to register such a plan. 

19. Title IV Provisions 

If the permittee is subject to the requirements of 40 CFR Part 72 concerning acid rain, the permittee 

shall ensure that any affected emissions unit complies with those requirements. Emissions exceeding 

any allowances that are lawfully held under Title IV of the Act, or any regulations adopted thereunder, 

are prohibited. 
Final Permit-to-Install 

P. H. Glatfelter Company - Chillicothe Facility

Permit Number: P0103673 

Facility ID: 0671010028 

Effective Date: 3/7/2011

Page 11 of 41

B. Facility-Wide Terms and Conditions 

 
Final Permit-to-Install 

P. H. Glatfelter Company - Chillicothe Facility

Permit Number: P0103673 

Facility ID: 0671010028 

Effective Date: 3/7/2011

Page 12 of 41

1. All the following facility-wide terms and conditions are federally enforceable with the exception of those 

listed below which are enforceable under state law only: 

a) None. 

2. Nitrogen Oxides (NOx) Budget Trading Program 

OAC Chapter 3745-14 

a) Office of Regulatory Information System Facility Code - 0671010028 

b) The following regulated non-electrical generating unit is subject to the applicable requirements 

specified in OAC Chapter 3745-14 and the annual NOx allowance allocations listed below: 

. Annual Allowance for 

. Calendar Years 

Emissions Unit 2004 through 2007 

B002 - Boiler #7 205 

B003 – Boiler #8 248 

Each emissions unit identified in Section 2.b) above is a NOx budget unit under OAC rule 3745-

14-01(C)(1). 

[OAC rule 3745-14-01(C)(1)(a)(i)] 

c) The NOx authorized account representative shall submit a complete NOx budget permit 

application in accordance with the deadlines specified in paragraphs (B)(2) and (B)(3) of OAC 

rule 3745-14-03. The NOx authorized account representative shall also submit, in a timely 

manner, any supplemental information that the Director determines is necessary in order to 

review a NOx budget permit application and issue or deny a NOx budget permit. 

[OAC rules 3745-14-01(E)(1)(a)(i), 3745-14-01(E)(1)(a)(ii), and 3745-14-03(B)(1)] 

d) Beginning May 31, 2004, the owners and operators of each NOx budget source and each NOx 

budget unit at the source shall hold NOx allowances available for compliance deductions under 

paragraph (E) of OAC rule 3745-14-06, as of the NOx allowance transfer deadline, in the unit's 

compliance account and the source's overdraft account in an amount not less than the total 

NOx emissions for the control period from the unit, as determined in accordance with OAC rule 

3745-14-08, plus any amount necessary to account for actual utilization under paragraph (C)(5) 

of OAC rule 3745-14-05 for the control period. 

[OAC rules 3745-14-01(E)(3)(a) and 3745-14-01(E)(3)(c)] 

e) NOx allowances shall be held in, deducted from, or transferred among NOx allowance tracking 

system accounts in accordance with OAC rules 3745-14-05, 3745-14-06, 3745-14-07, and 

3745-14-09. 

[OAC rule 3745-14-01(E)(3)(d)] 
Final Permit-to-Install 

P. H. Glatfelter Company - Chillicothe Facility

Permit Number: P0103673 

Facility ID: 0671010028 

Effective Date: 3/7/2011

Page 13 of 41

f) A NOx allowance shall not be deducted, in order to comply with the requirement under 

paragraph (E)(3)(a) of OAC rule 3745-14-01, for a control period in a year prior to the year for 

which the NOx allowance was allocated. 

[OAC rule 3745-14-01(E)(3)(e)] 

g) Each ton of NOx emitted in excess of the NOx budget emission limitation, as defined in OAC 

rule 3745-14-01(B)(2)(yy), shall constitute a separate violation of OAC Chapter 3745-14, the 

Clean Air Act, and applicable Ohio law. The owners and operators of a NOx budget unit that has 

excess emissions in any control period shall surrender the NOx allowances required for 

deduction under paragraph (E)(4)(a) of OAC rule 3745-14-06 and pay any fine, penalty, or 

assessment or comply with any other remedy imposed under paragraph (E)(4)(c) of OAC rule 

3745-14-06. 

[OAC rules 3745-14-01(E)(3)(b), 3745-14-01(E)(4)(a) and 3745-14-01(E)(4)(b)] 

h) When recorded by the Administrator pursuant to OAC rules 3745-14-06 and 3745-14-07, every 

allocation, transfer, or deduction of a NOx allowance to or from a NOx budget unit's compliance 

account or the overdraft account of the source where the unit is located is deemed to amend 

automatically, and become a part of, any NOx budget permit of the NOx budget unit by 

operation of law without any further review. 

[OAC rule 3745-14-01(E)(3)(h)] 

i) Except as provided below, the Director shall revise the NOx budget permit, as necessary, in 

accordance with OAC rule 3745-77-08. Each NOx budget permit is deemed to incorporate 

automatically the definitions of terms under paragraph (B) of OAC rule 3745-14-01 and, when 

recorded by the Administrator, in accordance with OAC rules 3745-14-06 and 3745-14-07, 

every allocation, transfer, or deduction of a NOx allowance to or from the compliance accounts 

of the NOx budget units covered by the permit or the overdraft account of the NOx budget 

source covered by the permit. 

[OAC rules 3745-14-03(D)(2) and 3745-14-03(E)(1)] 

j) The owner or operator of a NOx budget unit shall comply with the prohibitions under OAC rule 

3745-14-08(A)(5). 

[OAC rule 3745-14-08(A)(5)] 

k) The owners and operators of the NOx budget unit shall keep on site at the source each of the 

following documents for a period of five years from the date the document is created: (This 

period may be extended for cause, at any time prior to the end of five years, in writing by the 

Director or Administrator.) 

(1) the account certificate of representation for the NOx authorized account representative 

for the NOx budget unit and all documents that demonstrate the truth of the statements 

in the account certificate of representation, in accordance with paragraph (D) of OAC 

rule 3745-14-02, provided that the certificate and documents shall be retained on site at 

the source beyond such five-year period until such documents are superseded because 

of the submission of a new account certificate or representation changing the NOx 

authorized account representative; 
Final Permit-to-Install 

P. H. Glatfelter Company - Chillicothe Facility

Permit Number: P0103673 

Facility ID: 0671010028 

Effective Date: 3/7/2011

Page 14 of 41

(2) all emission monitoring information, in accordance with OAC rule 3745-14-08; 

(3) copies of all reports, compliance certifications, and other submissions and all records 

made or required under the NOx budget trading program; and 

(4) copies of all documents used to complete a NOx budget permit application and any 

other submission under the NOx budget trading program or to demonstrate compliance 

with the requirements of the NOx budget trading program. 

[OAC rule 3745-14-01(E)(5)(a)(i) through (iv)] 

l) The permittee shall operate and maintain equipment to continuously monitor and record 

nitrogen oxides emissions from these emissions units in units of the applicable standard(s). 

Such continuous monitoring and recording equipment shall comply with the requirements 

specified in 40 CFR Part 75. 

Each continuous monitoring system consists of all the equipment used to acquire data and 

includes the sample extraction and transport hardware, sample conditioning hardware, 

analyzers, and data recording/processing hardware and software. This includes all systems 

required to monitor the NOx emission rate, NOx concentration, heat input rate, and stack flow 

rate, in accordance with 40 CFR Parts 75.71 and 75.72. 

The permittee shall comply with the initial and re-certification procedures of 40 CFR Part 75. 

The permittee shall maintain on-site documentation from the USEPA or the Ohio EPA that the 

continuous nitrogen oxides monitoring system has been certified in accordance with 40 CFR 

Part 75. The letter of certification shall be made available to the Director upon request. 

The permittee shall maintain records of the following data obtained by the continuous nitrogen 

oxides monitoring system: emissions of nitrogen oxides in lb/millionBtu actual heat input on an 

hourly average basis, emissions of nitrogen oxides in lbs/hr, results of daily zero/span 

calibration checks, and magnitude of manual calibration adjustments. 

Whenever the monitoring system fails to meet the quality assurance or data validation 

requirements of 40 CFR Part 75, data shall be substituted using the applicable procedures in 

Subpart D, Appendix D, or Appendix E of 40 CFR Part 75. 

[OAC rules 3745-14-01(E)(2)(a), 3745-14-01(E)(5)(a)(ii), 3745-14-08(A)(2)(a) through (A)(2)(d), 

3745-14-08(B)(1), and 3745-14-08(C)(1)] 

m) The permittee shall comply with the monitoring plan requirements of 40 CFR Part 75.62, except 

that the monitoring plan shall also include all of the information required by Subpart H of 40 CFR 

Part 75. 

[OAC rule 3745-14-08(E)(2)(a)] 

n) The NOx authorized account representative of the NOx budget unit shall submit the reports and 

compliance certifications required under the NOx budget trading program, including those under 

OAC rules 3745-14-04 and 3745-14-08, to the Director and Administrator. 

[OAC rule 3745-14-01(E)(5)(b)] 
Final Permit-to-Install 

P. H. Glatfelter Company - Chillicothe Facility

Permit Number: P0103673 

Facility ID: 0671010028 

Effective Date: 3/7/2011

Page 15 of 41

o) Each submission under the NOx budget trading program shall be submitted, signed, and 

certified by the NOx authorized account representative for each NOx budget source on behalf of 

which the submission is made. Each such submission shall include the following certification 

statement by the NOx authorized account representative: 

"I am authorized to make this submission on behalf of the owners and operators of the NOx 

budget sources or NOx budget units for which the submission is made. I certify under penalty of 

law that I have personally examined, and am familiar with, the statements and information 

submitted in this document and all its attachments. Based on my inquiry of those individuals 

with primary responsibility for obtaining the information, I certify that the statements and 

information are to the best of my knowledge and belief true, accurate, and complete. I am aware 

that there are significant penalties for submitting false statements and information or omitting 

required statements and information, including the possibility of fine or imprisonment." 

If the NOx authorized account representative for a NOx budget unit subject to an acid rain 

emission limitation who signed and certified any submission that is made under Subpart F or G 

of 40 CFR Part 75 and which includes data and information required under OAC rule 3745-14-

08 or Subpart H of 40 CFR Part 75 is not the same person as the designated representative or 

the alternate designated representative for the unit under 40 CFR Part 72, then the submission 

shall also be signed by the designated representative or the alternate designated 

representative. 

[OAC rules 3745-14-02(A)(5) and 3745-14-08(E)(1)(b)] 

p) The NOx authorized account representative shall submit quarterly reports that include all of the 

data and information required in Subpart H of 40 CFR Part 75 for each NOx budget unit (or 

group of units using a common stack) and the data and information in Subpart G of 40 CFR Part 

75. These quarterly excess emission reports shall be submitted by January 30, April 30, July 30 

and October 30 of each year and shall be submitted in the manner specified in Subpart H of 40 

CFR Part 75 and 40 CFR Part 75.64. 

[OAC rules 3745-14-08(E)(4)(a) and 3745-14-08(E)(4)(c)(i)] 

q) The NOx authorized account representative shall submit to the Administrator a compliance 

certification in support of each quarterly report based on a reasonable inquiry of those persons 

with primary responsibility for ensuring that all of the unit's emissions are correctly and fully 

monitored. The compliance certification shall state that: 

(1) the monitoring data submitted were recorded in accordance with the applicable 

requirements of OAC rule 3745-14-08 and 40 CFR Part 75, including the quality 

assurance procedures and specifications; and 

(2) for a unit with add-on NOx emission controls and for all hours where data are substituted 

in accordance with 40 CFR Part 75.34(a)(1), the add-on emission control were operating 

within the range of parameters listed in the quality assurance program under Appendix B 

of 40 CFR Part 75 and the substitute values do not systematically underestimate the 

NOx emissions. 

[OAC rule 3745-14-08(E)(4)(d)(i) and (ii)] 
Final Permit-to-Install 

P. H. Glatfelter Company - Chillicothe Facility

Permit Number: P0103673 

Facility ID: 0671010028 

Effective Date: 3/7/2011

Page 16 of 41

r) The NOx authorized account representative for a NOx budget unit shall submit written notice of 

monitoring system certification and re-certification test dates to the Director and the 

Administrator in accordance with 40 CFR Part 75.61. The NOx authorized account 

representative shall submit a certification application to the Administrator, U.S. EPA, Region V 

Office, and the Director within forty-five days after completing all initial or re-certification tests 

required under paragraph (B) of OAC rule 3745-14-08, including the information required under 

Subpart H of 40 CFR Part 75. 

[OAC rules 3745-14-08(D) and 3745-14-08(E)(3)] 

s) For each control period in which one or more NOx budget units at a source are subject to the 

NOx budget emission limitation, the NOx authorized account representative of the source shall 

submit to the Director and the Administrator, by November 30 of that year, a compliance 

certification report for each source covering all such units. 

The NOx authorized account representative shall include the following elements in the 

compliance certification report, in a format prescribed by the Administrator, concerning each unit 

at the source and subject to the NOx budget emission limitation for the control period covered 

by the report: 

(1) identification of each NOx budget unit; 

(2) at the NOx authorized account representative's option, the serial numbers of the NOx 

allowances that are to be deducted from each unit's compliance account under 

paragraph (E) of OAC rule 3745-14-06 for the control period; 

(3) at the NOx authorized account representative's option, for units sharing a common stack 

and having NOx emissions that are not monitored separately or apportioned in 

accordance with OAC rule 3745-14-08, the percentage of allowances that is to be 

deducted from each unit's compliance account under paragraph (E)(5) of OAC rule 

3745-14-06; and 

(4) the compliance certification under paragraph (A)(3) of OAC rule 3745-14-04. 

[OAC rules 3745-14-04(A)(1) and 3745-14-04(A)(2)] 

t) In the compliance certification report under Section 2.s)(4) above, the NOx authorized account 

representative shall certify, based upon reasonable inquiry of those persons with the primary 

responsibility for operating the source and the NOx budget units at the source in compliance 

with the NOx budget trading program, whether each NOx budget unit for which the compliance 

certification is submitted was operated during the calendar year covered by the report in 

compliance with the requirements of the NOx budget trading program applicable to the unit, 

including all the following: 

(1) whether the unit was operated in compliance with the NOx budget emission limitation; 

(2) whether the monitoring plan that governs the unit has been maintained to reflect the 

actual operation and monitoring of the unit, and contains all information necessary to 

attribute NOx emissions to the unit, in accordance with OAC rule 3745-14-08; 
Final Permit-to-Install 

P. H. Glatfelter Company - Chillicothe Facility

Permit Number: P0103673 

Facility ID: 0671010028 

Effective Date: 3/7/2011

Page 17 of 41

(3) whether all the NOx emissions from the unit, or group of units (including the unit) using a 

common stack, were monitored or accounted for through the missing data procedures 

and reported in the quarterly monitoring reports, including whether conditional data were 

reported in the quarterly reports in accordance with OAC rule 3745-14-08, and if 

conditional data were reported, the permittee shall indicate whether the status of all 

conditional data has been resolved and all necessary quarterly report submissions have 

been made; and 

(4) whether the facts that form the basis for certification under OAC rule 3745-14-08 of each 

monitor at the unit or group of units (including the unit) using a common stack, or for 

using an excepted monitoring method or alternative monitoring method approved under 

OAC rule 3745-14-08, if any, have changed. If a change is required to be reported under 

Section 2.s)(4) above, specify the nature of the change, the reason for the change, when 

the change occurred, and how the unit's compliance status was determined subsequent 

to the change, including what method was used to determine emissions when a change 

mandated the need for monitor re-certification. 

[OAC rule 3745-14-04(A)(3)] 

u) The NOx authorized account representative shall submit a complete NOx budget permit renewal 

application for the NOx budget source covering the NOx budget units at the source in 

accordance with paragraph (E) of OAC rule 3745-77-08. 

[OAC rule 3745-14-03(B)(3)(a)] 

v) The emission measurements recorded and reported in accordance with OAC rule 3745-14-08 

shall be used to determine compliance by the unit with the NOx budget emission limitation 

under paragraph (E)(3) of OAC rule 3745-14-01. 

[OAC rule 3745-14-01(E)(2)(b)] 

w) The permittee shall develop and maintain a written quality assurance/quality control plan for 

each continuous NOx monitoring system designed to ensure continuous valid and 

representative readings of NOx emissions in units of the applicable standard. The plan shall 

follow the requirements of 40 CFR Part 75, Appendix B. The quality assurance/quality control 

plan and a logbook dedicated to the continuous NOx monitoring system must be kept on-site 

and available for inspection during regular office hours. 

[OAC rules 3745-14-08(A)(2)(c) and 3745-14-08(A)(2)(d)] 

Note: Ohio EPA DAPC has completed rule amendments for OAC Chapter 3745-14, specifically OAC rule 

3745-14-01 and OAC rule 3745-14-06, to facilitate the transition of the affected units from OAC Chapter 

3745-14 into the federal Clean Air Interstate Rule (CAIR) program and to begin the process of “sunsetting” 

the parts of OAC Chapter 3745-14 which will no longer be needed as a result of Ohio’s CAIR rules (OAC 

Chapter 3745-109). The revised applicability section of OAC Chapter 3745-14 allows the rules to remain 

available as a backup until court required revisions to the federal CAIR program have been completed. The 

revision to OAC rule 3745-14-01(C)(2)(a) requires all affected units to be subject to and meet the 

requirements of Ohio’s CAIR program beginning in 2009. Should U.S. EPA eliminate or suspend the CAIR 

program, this revision would require these units to revert back and meet the requirements of OAC Chapter 

3745-14, provided a NOx allowance tracking system is maintained by U.S. EPA. 
Final Permit-to-Install 

P. H. Glatfelter Company - Chillicothe Facility

Permit Number: P0103673 

Facility ID: 0671010028 

Effective Date: 3/7/2011

Page 18 of 41

Clean Air Interstate Rule - OAC Chapter 3745-109

The permittee shall ensure that any CAIR NOx, SO2, or NOx ozone season units complies with the 

requirements of OAC Chapter 3745-109, which includes submitting timely permit applications. The 

requirements of this rule will be specified in the Title V permit issued to this facility. 
Final Permit-to-Install 

P. H. Glatfelter Company - Chillicothe Facility

Permit Number: P0103673 

Facility ID: 0671010028 

Effective Date: 3/7/2011

Page 19 of 41

C. Emissions Unit Terms and Conditions 

 
Final Permit-to-Install 

P. H. Glatfelter Company - Chillicothe Facility

Permit Number: P0103673 

Facility ID: 0671010028 

Effective Date: 3/7/2011

Page 20 of 41

1. B002, No.7 Coal Boiler 

Operations, Property and/or Equipment Description: 

Emissions unit B002 (Boiler No. 7) is a wet bottom, pulverized coal-fired boiler (Combustion 

Engineering model VU-405) having a maximum heat input capacity of 422 million Btu per hour, 

capable of firing number 2 fuel oil as backup fuel, and is a backup control device for noncondensable gases (NCG) generated by other facility emissions units. The unit is controlled with 

a cyclone/multi-clone, an electrostatic precipitator (ESP), a low nitrogen oxides concentric firing 

system and a vane close-coupled over fire air compartment (Alstom Power). 

a) The following emissions unit terms and conditions are federally enforceable with the exception 

of those listed below which are enforceable under State law only. 

(1) None. 

b) Applicable Emission Limitations and/or Control Requirements 

(1) The specific operation(s), property, and/or equipment that constitute each emissions unit 

along with the applicable rules and/or requirements and with the applicable emission 

limitations and/or control measures are identified below. Emissions from each unit shall 

not exceed the listed limitations, and the listed control measures shall be specified in 

narrative form following the table. 

 Applicable Rules/Requirements Applicable Emission Limitations/Control 

Measures 

a. OAC rule 3745-31-05(A)(3) See section c)(2) below. 

b. OAC rule 3745-17-07(A) Visible particulate emissions from the 

exhaust stack serving emissions units 

B002 and B003 shall not exceed 20% 

opacity as a 6-minute average, except as 

provided by the rule. 

c. OAC rule 3745-17-10(C)(1) Particulate emissions shall not exceed 

0.10 pound per million Btu of actual heat 

input, when firing coal. The particulate 

emission limitation specified in 40 CFR 

Part 63, Subpart DDDDD for this 

emissions unit, when firing coal, is 

currently more stringent than this 

particulate emission limitation. Unless the 

applicable 40 CFR Part 63, Subpart 

DDDDD emission limitation is revised 

under “reconsideration”, after the 

specified compliance date for this 

emissions unit, this particulate emission 

limitation will be less stringent than the 

particulate emission limitation established 

pursuant to Subpart DDDDD. 

d. OAC rule 3745-17-10(B)(1) Particulate emissions shall not exceed 

0.020 pound per million Btu of actual heat 

input, when firing only number 2 fuel oil. 
Final Permit-to-Install 

P. H. Glatfelter Company - Chillicothe Facility

Permit Number: P0103673 

Facility ID: 0671010028 

Effective Date: 3/7/2011

Page 21 of 41

 Applicable Rules/Requirements Applicable Emission Limitations/Control 

Measures 

The particulate emission limitation 

specified in 40 CFR Part 63, Subpart 

DDDDD for this emissions unit, when 

firing only number 2 fuel oil, is currently 

more stringent than this particulate 

emission limitation. Unless the applicable 

40 CFR Part 63, Subpart DDDDD 

emission limitation is revised under 

“reconsideration”, after the specified 

compliance date for this emissions unit, 

this particulate emission limitation will be 

less stringent than the particulate 

emission limitation established pursuant 

to Subpart DDDDD. 

e. OAC rule 3745-18-77(B)(1) Sulfur dioxide emissions shall not exceed 

9.9 pounds per million Btu actual heat 

input. After the compliance date listed 

under b)(2)b. below, this emission 

limitation will be less stringent than the 

emission limitation established pursuant 

to 40 CFR Part 51.308(e) (see b)(1)g. 

below). 

f. OAC Chapters 3745-14 and 3745-

109 

See section b)(2)a. below. 

g. 40 CFR Part 51.308(e) 

Federally enforceable limitation to 

comply with the BART requirements 

of U.S. EPA’s Regional Haze 

Regulations. 

After the compliance date listed under 

b)(2)b. below, sulfur dioxide emissions 

from emissions units B002 and B003, 

combined, shall not exceed 24,930 

pounds per calendar day. 

h. 40 CFR Part 63, Subpart DDDDD See b)(2)c. below. 

Also see 40 CFR Part 63.7500 and Table 

2 to Subpart DDDDD. 

i 40 CFR Part 63, Subpart A See 40 CFR Part 63.7565 and Table 10 

to Subpart DDDDD for the Applicability of 

General Provisions to this Subpart. 

(2) Additional Terms and Conditions 

a. Refer to Part B. – Facility-Wide Terms and Conditions of the permit for the 

requirements of OAC Chapter 3745-14 "NOx Budget Trading Program in Ohio" 

and OAC Chapter 3745-109 “Clean Air Interstate Rule.” 

b. Emissions units B002 and B003 (Boilers No. 7 and No. 8, respectively) are 

subject to the Best Available Retrofit Technology (BART) requirements of the 

U.S. EPA’s Regional Haze Regulations (40 CFR Part 51, Subpart P). The 

permittee shall operate and maintain control measures constituting an 
Final Permit-to-Install 

P. H. Glatfelter Company - Chillicothe Facility

Permit Number: P0103673 

Facility ID: 0671010028 

Effective Date: 3/7/2011

Page 22 of 41

“alternative to BART” that will achieve greater reasonable progress than would 

be achieved through installation and operation of BART, as allowed under 40 

CFR Part 51.308(e)(2). 

 In addition to using a cyclone/multi-clone and an ESP to control the particulate 

emissions, emissions unit B002 (Boiler No. 7) is equipped with an Alstom Power 

low nitrogen oxides (low-NOx) concentric firing system and a vane close-coupled 

over fire air compartment, which, based upon Ohio EPA’s analysis, satisfy the 

BART nitrogen oxides technology requirement. 

The permittee shall achieve the required nitrogen oxides emission reduction by 

not later than December 31, 2014 by routinely employing the Alstom Power lowNOx concentric firing system and vane close-coupled over fire air compartment, 

on a year-round basis, rather than limiting low-NOx operation to the control 

period (May 1 through September 30) specified in OAC Chapter 3745-14. 

The permittee shall achieve the required sulfur dioxide emission reduction, on a 

year-round basis, by not later than December 31, 2014. As part of this 

“alternative to BART,” the permittee shall install, operate, and maintain control 

technology sufficient to meet the emissions limitation in section b)(1)g. This may 

include an add-on control device, use of an alternative fuel, use of low sulfur fuel, 

permanent shutdown of emissions unit B002, or a combination of these 

measures. By no later than December 31, 2013, the permittee shall submit to 

Ohio EPA an application for modification of this federally enforceable permit. 

The application shall include a compliance plan outlining, at a minimum, the 

specific, selected control technologies and methods of compliance; and these 

requirements, along with any appropriate monitoring, recordkeeping, and 

reporting requirements, shall be incorporated into the federally enforceable 

permit by no later than December 31, 2014. A continuous emission monitoring 

system (CEMS) shall be installed for this emissions unit by no later than 

December 31, 2014 to measure and record the daily sulfur dioxide emissions. 

c. This emissions unit will be subject to the applicable requirements specified in 40 

CFR Part 63, Subpart DDDDD when the regulations become effective. 

c) Operational Restrictions 

(1) The quality of the oil burned in this emissions unit shall meet a sulfur content that is 

sufficient to comply with the allowable sulfur dioxide emission limitation specified in 

section b)(1)e. above. 

(2) This emissions unit shall not be taken out of service at the same time as both emissions 

units B003 (Boiler No. 8) and B013 (Wood Waste Boiler), except during emergency 

outages. Emissions unit B013 shall serve as the primary incineration point for highvolume low concentration NCG. Either emissions unit B002 or B003 shall serve as a 

backup control device for high-volume low concentration NCG combustion. If emissions 

unit B002 is permanently shutdown, emissions unit B003 shall serve as the backup 

control device for high-volume low concentration NCG combustion and shall not be 

taken out of service at the same time as emissions unit B013, except during emergency 

outages. 
Final Permit-to-Install 

P. H. Glatfelter Company - Chillicothe Facility

Permit Number: P0103673 

Facility ID: 0671010028 

Effective Date: 3/7/2011

Page 23 of 41

d) Monitoring and/or Recordkeeping Requirements 

(1) The permittee shall operate and maintain equipment to continuously monitor and record 

the opacity of the visible particulate emissions of the combined emissions from 

emissions units B002 and B003. Such continuous monitoring and recording equipment 

shall comply with the requirements specified in 40 CFR Part 60.13. 

The continuous monitoring system consists of all the equipment used to acquire data 

and includes the data recording/processing hardware and software. 

The permittee shall maintain a letter of certification from the Ohio EPA, Central Office 

documenting that the continuous opacity monitoring system has been certified in 

accordance with the requirements of 40 CFR Part 60, Appendix B, Performance 

Specification 1. The letter of certification shall be made available to the Ohio EPA, 

Southeast District Office upon request. 

The permittee shall maintain records of the following data obtained by the continuous 

opacity monitoring system: percent opacity on a 6-minute block average basis, results of 

daily zero/span calibration checks, and magnitudes of manual calibration adjustments. 

(2) The permittee shall maintain a written quality assurance/quality control plan for the 

continuous opacity monitoring system designed to ensure continuous valid and 

representative readings of opacity. The plan shall include, as a minimum, conducting 

and recording daily automatic zero/span checks, provisions for conducting a quarterly 

audit of the continuous opacity monitoring system, and a description of preventive 

maintenance activities. The quality assurance/quality control plan must be kept on site 

and available for inspection during regular office hours. 

(3) To obtain an exemption pursuant to OAC rule 3745-17-07(A)(3)(a)(i) or (A)(3)(b)(i), the 

permittee shall operate and maintain a temperature monitor and recorder that measures 

and records the temperature of the boiler exhaust gases entering the ESP during (a) all 

periods of start-up until the ESP is operational or until the inlet temperature of the ESP 

achieves the temperature level specified in OAC rule 3745-17-07(A)(3)(a)(i) and (b) all 

periods of shutdown until the inlet temperature of the ESP drops below the temperature 

level specified in OAC rule 3745-17-07(A)(3)(b)(i). An electronic or hardcopy record of 

the temperatures during periods of start-up and shutdown shall be maintained. 

The temperature monitor and recorder shall be installed, calibrated, operated, and 

maintained in accordance with manufacturer's recommendations, with any modifications 

deemed necessary by the permittee, and shall be capable of accurately measuring the 

temperature of the boiler exhaust gases in units of degrees Fahrenheit. 

(4) The permittee shall maintain monthly records of the total quantity of coal burned, and the 

results of the analyses for ash content, sulfur content, heat content, and the average 

sulfur dioxide emission rate (in lbs/million Btu). The coal collection and sampling 

procedures and analyses for ash content, sulfur content, and heat content shall be 

performed in accordance with the following: 

The permittee shall collect monthly composite samples of the coal burned in this 

emissions unit. A sufficient number of individual samples shall be collected so that each 

composite sample is representative of the average quality of coal burned in this 
Final Permit-to-Install 

P. H. Glatfelter Company - Chillicothe Facility

Permit Number: P0103673 

Facility ID: 0671010028 

Effective Date: 3/7/2011

Page 24 of 41

emissions unit during each calendar month. The coal sampling shall be performed in 

accordance with the most recent version of ASTM method D2234, Collection of a Gross 

Sample of Coal. 

Each monthly composite sample of coal shall be analyzed for ash content (in percent), 

sulfur content (in percent), and heat content (in Btu/pound). The analytical methods for 

ash content, sulfur content, and heat content shall be the most recent version of: ASTM 

method D3174, Ash in the Analysis of Coal and Coke; ASTM method D3177, Total 

Sulfur in the Analysis Sample of Coal and Coke or ASTM method D4239, Sulfur in the 

Analysis Sample of Coal and Coke Using High Temperature Tube Furnace Combustion 

Methods; and ASTM method D5865, Gross Calorific Value of Coal and Coke, 

respectively. Alternative, equivalent methods may be used upon written approval from 

the Ohio EPA, Southeast District Office. 

The requirements to analyze the sulfur content of the composite coal sample and to 

calculate the pounds per million Btu sulfur dioxide emission rate pursuant to this term 

and condition shall terminate on December 31, 2014 because the sulfur dioxide 

continuous monitoring system required under section d)(6) and the monitoring and 

recordkeeping provisions for the pounds per million Btu and pounds per calendar day 

emission limitations under section d)(8) become effective on that date. 

(5) The permittee shall comply with the requirements of one of the following alternatives 

pertaining to the use of number 2 fuel oil: 

a. Alternative 1: 

For each shipment of oil received for burning in this emissions unit, the permittee 

shall collect or require the oil supplier to collect a representative grab sample of 

oil and maintain records of the total quantity of oil received, the permittee's or oil 

supplier's analyses for sulfur content and heat content, and the calculated sulfur 

dioxide emission rate (in lbs/million Btu). The sulfur dioxide emission rate shall be 

calculated in accordance with the formula specified in OAC rule 3745-18-04(F). A 

shipment may be comprised of multiple tank truck loads from the same supplier's 

batch, and the quality of the oil for those loads may be represented by a single 

batch analysis from the supplier. 

b. Alternative 2: 

The permittee shall collect a representative grab sample of oil that is burned in 

this emissions unit for each day when the emissions unit is in operation. If 

additional fuel oil is added to the tank serving this emissions unit on a day when 

the emissions unit is in operation, the permittee shall collect a sufficient number 

of grab samples to develop a composite sample representative of the fuel oil 

burned in this emissions unit. A representative grab sample of oil does not need 

to be collected on days when this emissions unit is only operated for the purpose 

of "test-firing." The permittee shall maintain records of the total quantity of oil 

burned each day, except for the purpose of test-firing, the permittee's analyses 

for sulfur content and heat content, and the calculated sulfur dioxide emission 

rate (in lbs/million Btu). The sulfur dioxide emission rate shall be calculated in 

accordance with the formula specified in OAC rule 3745-18-04(F). 
Final Permit-to-Install 

P. H. Glatfelter Company - Chillicothe Facility

Permit Number: P0103673 

Facility ID: 0671010028 

Effective Date: 3/7/2011

Page 25 of 41

c. The permittee shall perform or require the supplier to perform the analyses for 

sulfur content and heat content in accordance with 40 CFR Part 60, Appendix A, 

Method 19, or the appropriate ASTM methods (such as, ASTM methods D240 

and D4294), or equivalent methods as approved by the Director. 

The requirements to analyze the sulfur content of the number 2 fuel oil and to 

calculate the pounds per million Btu sulfur dioxide emission rate pursuant to this 

term and condition shall terminate on December 31, 2014 because the sulfur 

dioxide continuous monitoring system required under section d)(6) and the 

monitoring and recordkeeping provisions for the pounds per million Btu and 

pounds per calendar day emission limitations under section d)(8) become 

effective on that date. 

(6) By not later than December 31, 2014, the permittee shall install, operate, and maintain 

equipment to continuously monitor and record sulfur dioxide and exhaust gas flow data 

for this emissions unit in units of the applicable standards (pounds per million Btu and 

pounds per calendar day). Such continuous monitoring and recording equipment shall 

comply with the requirements specified in 40 CFR Part 60, Appendix B, Performance 

Specification 6, and be operated in accordance with 40 CFR Part 60.13 unless otherwise 

specified in d)(7) below. 

The permittee shall maintain records of all data obtained by the continuous sulfur dioxide 

and exhaust gas flow monitoring system including, but not limited to, minute-by-minute 

concentration data for sulfur dioxide; minute-by-minute flow data in ACFM; sulfur dioxide 

data in pounds per day; the results of all daily, weekly, and quarterly calibration checks; 

and the magnitude of any calibration adjustments. 

Each continuous emissions monitoring system (CEMS) consists of all the equipment 

used to acquire and record data and includes any sample extraction and transport 

hardware, sample conditioning hardware, analyzers, and data recording/processing 

hardware and software. 

The data recorded by the CEMS shall be used to determine compliance with the 

applicable emission limitations on an ongoing basis. 

(7) By not later than March 31, 2014, the permittee shall develop a written quality 

assurance/quality control plan for the continuous sulfur dioxide and exhaust gas flow 

monitoring system designed to meet all requirements as listed in 40 CFR Part 60, 

Appendix F and ensure continuous valid and representative readings of sulfur dioxide 

and flow. The plan shall describe in detail, complete, step-by-step procedures and 

operations for each of the following activities: 

a. calibration of CEMS; 

b. calibration drift determination and adjustment of CEMS; 

c. preventive maintenance of CEMS (including spare parts inventory); 

d. data recording, calculations, and reporting; 

e. accuracy audit procedures including sampling and analysis methods; and 
Final Permit-to-Install 

P. H. Glatfelter Company - Chillicothe Facility

Permit Number: P0103673 

Facility ID: 0671010028 

Effective Date: 3/7/2011

Page 26 of 41

f. program of corrective action for malfunctioning CEMS. 

The permittee shall be required to complete a CEMS certification relative accuracy test 

audit (RATA), in accordance with the procedures specified in 40 CFR Part 60, Appendix 

F, by not later than December 31, 2014. From the date of CEMS certification forward, 

the permittee may forego annual RATA requirements as listed in 40 CFR Part 60, 

Appendix F, by completing a quarterly cylinder gas or relative accuracy audit, in 

accordance with 40 CFR Part 60, Appendix F, for each quarter of the year. Should any 

CEMS not pass a cylinder gas or relative accuracy audit on the first attempt for two 

consecutive quarters (even though a recalibration or repair allows the second attempted 

cylinder gas or relative accuracy audit to pass), the permittee shall complete a RATA 

within 60 days of the second quarter's failed cylinder gas or relative accuracy audit. The 

permittee shall also complete a RATA for the CEMS within six months prior to the 

expiration of this permit. RATA testing may also be required if the CEMS as listed on 

the CEMS certification letter from the Ohio EPA, Central Office, or any CEMS associated 

equipment, is changed or modified. 

Beginning on December 31, 2014, the permittee shall perform daily zero/span calibration 

drift checks on each sulfur dioxide and flow CEMS for 60 consecutive operating days in 

accordance with the requirements specified in 40 CFR Part 60, Appendix F, section 4. 

If, on the first attempt, the results of each daily zero/span calibration drift check are less 

than the criteria for excessive calibration drift specified in 40 CFR Part 60, Appendix F, 

section 4.3 (as determined by the Ohio EPA, Southeast District Office), the permittee 

shall begin performing zero/span calibration drift checks on a weekly basis. If any 

CEMS should fail a weekly zero/span calibration drift check for two consecutive weeks 

(based on the criteria of being two times over the limit as stated in Appendix F, section 

4.3), the permittee shall perform daily zero/span calibration drift checks until such time 

as 60 consecutive daily zero/span calibration drift checks have been successfully 

completed within the criteria specified in Appendix F, section 4.3. 

The quality assurance/quality control plan and a logbook dedicated to the sulfur dioxide 

and flow CEMS must be kept on site and available for inspection during regular office 

hours. 

(8) By not later than December 31, 2014, the permittee shall maintain daily records of the 

following information: 

a. the total sulfur dioxide emissions from this emissions unit based upon the data 

collected in section d)(6), in pounds per million Btu and pounds per calendar day; 

b. the total sulfur dioxide emissions from this emissions unit and emissions unit 

B003, combined, based upon the data collected in section d)(6) for each unit, in 

pounds per calendar day; and 

c. the identification of any days (excluding any days within the “control period” 

specified in OAC Chapter 3745-14) when this emissions unit was in service and 

the unit’s low-NOx concentric firing system and vane close-coupled over fire air 

compartment were not operating. 

(9) The permittee shall maintain records for each day when emissions units B002, B003, 

and B013 were all off line and the venting of high-volume low concentration NCG was 
Final Permit-to-Install 

P. H. Glatfelter Company - Chillicothe Facility

Permit Number: P0103673 

Facility ID: 0671010028 

Effective Date: 3/7/2011

Page 27 of 41

uncontrolled. If emissions unit B002 is permanently shut down after December 31, 2014, 

the permittee shall maintain records for each day when emissions units B003 and B013 

were off line and the venting of high-volume low concentration NCG was uncontrolled. 

e) Reporting Requirements 

(1) The permittee shall submit reports (hardcopy or electronic format) within one month 

following the end of each calendar quarter to the Ohio EPA, Southeast District Office 

documenting all instances of opacity values in excess of the limitation specified in 

section b)(1)b. of these terms and conditions, detailing the date, commencement and 

completion times, duration, magnitude (percent opacity), reason (if known), and 

corrective actions taken (if any) of each 6-minute block average above the applicable 

opacity limitations. 

The reports shall also identify any excursions of the start-up and shutdown provisions 

specified in OAC rule 3745-17-07(A)(3) and document any continuous opacity 

monitoring system downtime while the emissions unit was on line (date, time, duration 

and reason) along with any corrective action taken. The permittee shall provide the 

emissions unit operating time during the reporting period and the date, time, reason, and 

corrective action taken for each time period of emissions unit and control equipment 

malfunctions. The total operating time of the emissions unit and the total operating time 

of the analyzer while the emissions unit was on line shall be included in the quarterly 

report. 

If there are no excess emissions during the calendar quarter, the permittee shall submit 

a statement to that effect along with the date, time, reason, and corrective action taken 

for each time period of monitoring system malfunction. The total operating time of the 

emissions unit and the total operating time of the analyzer while the emissions unit was 

on line also shall be included in the quarterly report. 

These quarterly excess emission reports shall be submitted by January 31, April 30, July 

31, and October 31 of each year, and each report shall address the data obtained during 

the previous calendar quarter. 

(2) The permittee shall submit quarterly deviation (excursion) reports that identify whenever 

a monthly composite sample collected pursuant to section d)(4) above indicates a 

deviation from the allowable sulfur dioxide emission rate. These reports shall be 

submitted in accordance with the reporting requirements specified in the Standard 

Terms and Conditions of this permit. 

The requirements to submit quarterly deviation (excursion) reports pursuant to this term 

and condition shall terminate on December 31, 2014 because the sulfur dioxide 

continuous monitoring system required under section d)(6) and the monitoring and 

recordkeeping provisions for the pounds per million Btu and pounds per calendar day 

emission limitations under section d)(8) become effective on that date. 

(3) The permittee shall notify the Ohio EPA, Southeast District Office in writing of any record 

that shows a deviation of the allowable sulfur dioxide emission limitation based upon the 

calculated sulfur dioxide emission rates from section d)(5) above when firing number 2 

fuel oil. The notification shall include a copy of such record and shall be sent to the Ohio 
Final Permit-to-Install 

P. H. Glatfelter Company - Chillicothe Facility

Permit Number: P0103673 

Facility ID: 0671010028 

Effective Date: 3/7/2011

Page 28 of 41

EPA, Southeast District Office. These reports shall be submitted in accordance with the 

reporting requirements specified in the Standard Terms and Conditions of this permit. 

The requirements to submit quarterly deviation (excursion) reports pursuant to this term 

and condition shall terminate on December 31, 2014 because the sulfur dioxide 

continuous monitoring system required under section d)(6) and the monitoring and 

recordkeeping provisions for the pounds per million Btu and pounds per calendar day 

emission limitations under section d)(8) become effective on that date. 

(4) The permittee shall submit quarterly deviation (excursion) reports that identify any period 

of time when emissions units B002, B003, and B013 were all off line and the venting of 

high-volume low concentration NCG was uncontrolled. If emissions unit B002 is 

permanently shut down after December 31, 2014, the permittee shall submit deviation 

(excursion) reports that identify any period of time when emissions units B003 and B013 

were off line and the venting of high-volume low concentration NCG was uncontrolled. 

These reports shall be submitted in accordance with the reporting requirements 

specified in the Standard Terms and Conditions of this permit. 

(5) Beginning in calendar year 2015, the permittee shall submit reports within one month 

following the end of each calendar quarter to the Ohio EPA, Southeast District Office 

documenting the date, commencement and completion times, duration, magnitude, 

reason (if known), and corrective actions taken (if any), of all instances of sulfur dioxide 

values in excess of the applicable limitations (pounds per million Btu and pounds per 

calendar day) specified in this permit. 

The reports shall document any continuous sulfur dioxide and exhaust gas flow 

monitoring system downtime while the emissions unit was on line (date, time, duration 

and reason) along with any corrective action(s) taken. The permittee shall provide the 

emissions unit operating time during the reporting period and the date, time, reason and 

corrective action(s) taken for each time period of emissions unit and control equipment 

malfunctions. The total operating time of the emissions unit and the total operating time 

of the analyzer while the emissions unit was on line shall also be included in the 

quarterly report. 

If there are no excess emissions during the calendar quarter, the permittee shall submit 

a statement to that effect along with the emissions unit operating time during the 

reporting period and the date, time, reason, and corrective action(s) taken for each time 

period of emissions unit, control equipment, and/or monitoring system malfunctions. The 

total operating time of the emissions unit and the total operating time of the analyzer 

while the emissions unit was on line also shall be included in the quarterly report. These 

quarterly excess emission reports shall be submitted by January 31, April 30, July 31, 

and October 31 of each year and shall address the data obtained during the previous 

calendar quarter. 

(6) Beginning in calendar year 2015, the permittee shall submit quarterly deviation 

(excursion) reports that identify any days (excluding any days within the “control period” 

specified in OAC Chapter 3745-14) when this emissions unit was in service and the 

unit’s low-NOx concentric firing system and vane close-coupled over fire air 

compartment were not operating. 
Final Permit-to-Install 

P. H. Glatfelter Company - Chillicothe Facility

Permit Number: P0103673 

Facility ID: 0671010028 

Effective Date: 3/7/2011

Page 29 of 41

These reports shall be submitted in accordance with the reporting requirements 

specified in the Standard Terms and Conditions of this permit. 

f) Testing Requirements 

(1) Compliance with the emission limitations in section b)(1) of these terms and conditions 

shall be determined in accordance with the following methods: 

a. Emission Limitation: 

Visible particulate emissions from the exhaust stack serving emissions units 

B002 and B003 shall not exceed 20% opacity as a 6-minute average, except as 

provided by the rule. 

Applicable Compliance Methods: 

If required, compliance with this emission limitation shall be demonstrated 

through visible emission observations performed in accordance with 40 CFR Part 

60, Appendix A, Method 9 and the procedures specified in OAC rule 3745-17-

03(B)(1). 

Ongoing compliance with this emission limitation may be demonstrated based 

upon the records required pursuant to section d)(1). 

b. Emission Limitation: 

Particulate emissions shall not exceed 0.10 pound per million Btu of actual heat 

input, when firing coal. 

Applicable Compliance Method: 

If required, compliance with this emission limitation shall be demonstrated 

through emission tests performed in accordance with 40 CFR Part 60, Appendix 

A, Methods 1 through 5 and the procedures specified in OAC rule 3745-17-

03(B)(9). 

c. Emission Limitation: 

Particulate emissions shall not exceed 0.020 pound per million Btu of actual heat 

input, when firing only number 2 fuel oil. 

Applicable Compliance Method: 

Compliance with this emission limitation may be determined by multiplying an 

emission factor of 2.0 pounds of particulates per 1000 gallons of fuel oil fired by 

the emissions unit's maximum hourly fuel oil firing capacity (1584 gallons/hr), 

dividing by the emissions unit's rated heat input capacity (422 million Btu/hr), and 

dividing by 1000. This emission factor is specified in U.S. EPA reference 

document AP-42, Fifth Edition, Compilation of Air Pollution Emission Factors, 

Section 1.3, Table 1.3-1 (5/10). 
Final Permit-to-Install 

P. H. Glatfelter Company - Chillicothe Facility

Permit Number: P0103673 

Facility ID: 0671010028 

Effective Date: 3/7/2011

Page 30 of 41

If required, the permittee shall demonstrate compliance with this emission 

limitation through emission tests performed in accordance with 40 CFR Part 60, 

Appendix A, Methods 1 through 5 and the procedures specified in OAC rule 

3745-17-03(B)(9).

d. Emission Limitation: 

Sulfur dioxide emissions shall not exceed 9.9 pounds per million Btu actual heat 

input. 

Applicable Compliance Methods: 

When firing fuel oil, compliance with this sulfur dioxide emission limitation may be 

demonstrated based upon the records required pursuant to section d)(5). 

When firing coal, compliance with this sulfur dioxide emission limitation may be 

demonstrated based upon the records required pursuant to section d)(4). 

On and after installation and operation of the control technology required under 

section b)(2)b. above is complete, compliance with this sulfur dioxide emission 

limitations shall be demonstrated based upon the records required pursuant to 

sections d)(6) and d)(8). 

Also, if required, the permittee shall demonstrate compliance with the allowable 

sulfur dioxide emission limitation through emission tests performed in accordance 

with 40 CFR Part 60, Appendix A, Methods 1 through 4 and 6 or 6A. 

e. Emission Limitation: 

By not later than December 31, 2014, sulfur dioxide emissions from emissions 

units B002 and B003, combined, shall not exceed 24,930 pounds per calendar 

day. 

Applicable Compliance Method: 

Compliance with this sulfur dioxide emission limitation shall be demonstrated 

based upon the records required pursuant to sections d)(6) and d)(8). 

Also, if required, the permittee shall demonstrate compliance with the allowable 

sulfur dioxide emission limitation through emission tests performed in accordance 

with 40 CFR Part 60, Appendix A, Methods 1 through 4 and 6 or 6A. 

g) Miscellaneous Requirements 

(1) None. 

 
Final Permit-to-Install 

P. H. Glatfelter Company - Chillicothe Facility

Permit Number: P0103673 

Facility ID: 0671010028 

Effective Date: 3/7/2011

Page 31 of 41

2. B003, No.8 Coal Boiler 

Operations, Property and/or Equipment Description: 

Emissions unit B003 (Boiler No. 8) is a wall-fired, pulverized coal-fired boiler 

(Alstom/Combustion Engineering) having a maximum heat input capacity of 505 million Btu per 

hour, capable of firing number 2 fuel oil as backup fuel, and is a backup control device for noncondensable gases (NCG) generated by other facility emissions units. The emissions unit is 

controlled with a cyclone/multi-clone, four low-NOx staged-combustion burners (Advanced 

Combustion Technology), and an electrostatic precipitator (Environmental Elements Dry 

Precipitator). 

a) The following emissions unit terms and conditions are federally enforceable with the exception 

of those listed below which are enforceable under State law only. 

(1) None. 

b) Applicable Emission Limitations and/or Control Requirements 

(1) The specific operation(s), property, and/or equipment that constitute each emissions unit 

along with the applicable rules and/or requirements and with the applicable emission 

limitations and/or control measures are identified below. Emissions from each unit shall 

not exceed the listed limitations, and the listed control measures shall be specified in 

narrative form following the table. 

 Applicable Rules/Requirements Applicable Emission Limitations/Control 

Measures 

a. OAC rule 3745-31-05(A)(3) See section c)(2) below. 

b. OAC rule 3745-17-07(A) Visible particulate emissions from the 

exhaust stack serving emissions units 

B002 and B003 shall not exceed 20% 

opacity as a 6-minute average, except as 

provided by the rule. 

c. OAC rule 3745-17-10(C)(1) Particulate emissions shall not exceed 

0.10 pound per million Btu of actual heat 

input, when firing coal. The particulate 

emission limitation specified in 40 CFR 

Part 63, Subpart DDDDD for this 

emissions unit, when firing coal, is 

currently more stringent than this 

particulate emission limitation. Unless the 

applicable 40 CFR Part 63, Subpart 

DDDDD emission limitation is revised 

under “reconsideration”, after the 

specified compliance date for this 

emissions unit, this particulate emission 

limitation will be less stringent than the 

particulate emission limitation established 

pursuant to Subpart DDDDD. 

d. OAC rule 3745-17-10(B)(1) Particulate emissions shall not exceed 

0.020 pound per million Btu of actual heat 
Final Permit-to-Install 

P. H. Glatfelter Company - Chillicothe Facility

Permit Number: P0103673 

Facility ID: 0671010028 

Effective Date: 3/7/2011

Page 32 of 41

 Applicable Rules/Requirements Applicable Emission Limitations/Control 

Measures 

input, when firing only number 2 fuel oil. 

The particulate emission limitation 

specified in 40 CFR Part 63, Subpart 

DDDDD for this emissions unit, when 

firing only number 2 fuel oil, is currently 

more stringent than this particulate 

emission limitation. Unless the applicable 

40 CFR Part 63, Subpart DDDDD 

emission limitation is revised under 

“reconsideration”, after the specified 

compliance date for this emissions unit, 

this particulate emission limitation will be 

less stringent than the particulate 

emission limitation established pursuant 

to Subpart DDDDD. 

e. OAC rule 3745-18-77(B)(1) Sulfur dioxide emissions shall not exceed 

9.9 pounds per million Btu actual heat 

input. After the compliance date listed 

under b)(2)b. below, this emission 

limitation will be less stringent than the 

emission limitation established pursuant 

to 40 CFR Part 51.308(e) (see b)(1)g. 

below). 

f. OAC Chapters 3745-14 and 3745-

109 

See section b)(2)a. below. 

g. 40 CFR Part 51.308(e) 

Federally enforceable limitation to 

comply with the BART requirements 

of U.S. EPA’s Regional Haze 

Regulations. 

After the compliance date listed under 

b)(2)b. below, sulfur dioxide emissions 

from emissions units B002 and B003, 

combined, shall not exceed 24,930 

pounds per calendar day. 

h. 40 CFR Part 63, Subpart DDDDD See b)(2)c. below. 

Also see 40 CFR Part 63.7500 and Table 

2 to Subpart DDDDD. 

i 40 CFR Part 63, Subpart A See 40 CFR Part 63.7565 and Table 10 

to Subpart DDDDD for the Applicability of 

General Provisions to this Subpart. 

(2) Additional Terms and Conditions 

a. Refer to Part B. – Facility-Wide Terms and Conditions of the permit for the 

requirements of OAC Chapter 3745-14 "NOx Budget Trading Program in Ohio" 

and OAC Chapter 3745-109 “Clean Air Interstate Rule.” 

b. Emissions units B002 and B003 (Boilers No. 7 and No. 8, respectively) are 

subject to the Best Available Retrofit Technology (BART) requirements of the 

U.S. EPA’s Regional Haze Regulations (40 CFR Part 51, Subpart P). The 
Final Permit-to-Install 

P. H. Glatfelter Company - Chillicothe Facility

Permit Number: P0103673 

Facility ID: 0671010028 

Effective Date: 3/7/2011

Page 33 of 41

permittee shall operate and maintain control measures constituting an 

“alternative to BART” that will achieve greater reasonable progress than would 

be achieved through installation and operation of BART, as allowed under 40 

CFR Part 51.308(e)(2). 

 In addition to using a cyclone/multi-clone and an ESP to control the particulate 

emissions, emissions unit B003 (Boiler No. 8) is equipped with four Advanced 

Combustion Technology low-NOx staged-combustion burners, which, based 

upon Ohio EPA’s analysis, satisfy the BART nitrogen oxides technology 

requirement. 

The permittee shall achieve the required nitrogen oxides emission reduction by 

not later than December 31, 2014 by routinely employing the four Advanced 

Combustion Technology staged-combustion burners in their lowest-NOx mode 

on a year-round basis, rather than limiting low-NOx operation to the control 

period (May 1 through September 30) specified in OAC Chapter 3745-14. 

The permittee shall achieve the required sulfur dioxide emission reduction, on a 

year-round basis, by not later than December 31, 2014. As part of this 

“alternative to BART,” the permittee shall install, operate, and maintain control 

technology sufficient to meet the emissions limitation in section b)(1)g. This may 

include an add-on control device, use of an alternative fuel, use of low sulfur fuel, 

permanent shutdown of emissions unit B002, or a combination of these 

measures. By no later than December 31, 2013, the permittee shall submit to 

Ohio EPA an application for modification of this federally enforceable permit. 

The application shall include a compliance plan outlining, at a minimum, the 

specific, selected control technologies and methods of compliance; and these 

requirements, along with any appropriate monitoring, recordkeeping, and 

reporting requirements, shall be incorporated into the federally enforceable 

permit by no later than December 31, 2014. A continuous emission monitoring 

system (CEMS) shall be installed for this emissions unit by no later than 

December 31, 2014 to measure and record the daily sulfur dioxide emissions. 

c. This emissions unit will be subject to the applicable requirements specified in 40 

CFR Part 63, Subpart DDDDD when the regulations become effective. 

c) Operational Restrictions 

(1) The quality of the oil burned in this emissions unit shall meet a sulfur content that is 

sufficient to comply with the allowable sulfur dioxide emission limitation specified in 

section b)(1)e. above. 

(2) This emissions unit shall not be taken out of service at the same time as both emissions 

units B003 (Boiler No. 8) and B013 (Wood Waste Boiler), except during emergency 

outages. Emissions unit B013 shall serve as the primary incineration point for highvolume low concentration NCG. Either emissions unit B002 or B003 shall serve as a 

backup control device for high-volume low concentration NCG combustion. If emissions 

unit B002 is permanently shutdown, emissions unit B003 shall serve as the backup 

control device for high-volume low concentration NCG combustion and shall not be 

taken out of service at the same time as emissions unit B013, except during emergency 

outages. 
Final Permit-to-Install 

P. H. Glatfelter Company - Chillicothe Facility

Permit Number: P0103673 

Facility ID: 0671010028 

Effective Date: 3/7/2011

Page 34 of 41

d) Monitoring and/or Recordkeeping Requirements 

(1) The permittee shall operate and maintain equipment to continuously monitor and record 

the opacity of the visible particulate emissions of the combined emissions from 

emissions units B002 and B003. Such continuous monitoring and recording equipment 

shall comply with the requirements specified in 40 CFR Part 60.13. 

The continuous monitoring system consists of all the equipment used to acquire data 

and includes the data recording/processing hardware and software. 

The permittee shall maintain a letter of certification from the Ohio EPA, Central Office 

documenting that the continuous opacity monitoring system has been certified in 

accordance with the requirements of 40 CFR Part 60, Appendix B, Performance 

Specification 1. The letter of certification shall be made available to the Ohio EPA, 

Southeast District Office upon request. 

The permittee shall maintain records of the following data obtained by the continuous 

opacity monitoring system: percent opacity on a 6-minute block average basis, results of 

daily zero/span calibration checks, and magnitudes of manual calibration adjustments. 

(2) The permittee shall maintain a written quality assurance/quality control plan for the 

continuous opacity monitoring system designed to ensure continuous valid and 

representative readings of opacity. The plan shall include, as a minimum, conducting 

and recording daily automatic zero/span checks, provisions for conducting a quarterly 

audit of the continuous opacity monitoring system, and a description of preventive 

maintenance activities. The quality assurance/quality control plan must be kept on site 

and available for inspection during regular office hours. 

(3) To obtain an exemption pursuant to OAC rule 3745-17-07(A)(3)(a)(i) or (A)(3)(b)(i), the 

permittee shall operate and maintain a temperature monitor and recorder that measures 

and records the temperature of the boiler exhaust gases entering the ESP during (a) all 

periods of start-up until the ESP is operational or until the inlet temperature of the ESP 

achieves the temperature level specified in OAC rule 3745-17-07(A)(3)(a)(i) and (b) all 

periods of shutdown until the inlet temperature of the ESP drops below the temperature 

level specified in OAC rule 3745-17-07(A)(3)(b)(i). An electronic or hardcopy record of 

the temperatures during periods of start-up and shutdown shall be maintained. 

The temperature monitor and recorder shall be installed, calibrated, operated, and 

maintained in accordance with manufacturer's recommendations, with any modifications 

deemed necessary by the permittee, and shall be capable of accurately measuring the 

temperature of the boiler exhaust gases in units of degrees Fahrenheit. 

(4) The permittee shall maintain monthly records of the total quantity of coal burned, and the 

results of the analyses for ash content, sulfur content, heat content, and the average 

sulfur dioxide emission rate (in lbs/million Btu). The coal collection and sampling 

procedures and analyses for ash content, sulfur content, and heat content shall be 

performed in accordance with the following: 

The permittee shall collect monthly composite samples of the coal burned in this 

emissions unit. A sufficient number of individual samples shall be collected so that each 

composite sample is representative of the average quality of coal burned in this 
Final Permit-to-Install 

P. H. Glatfelter Company - Chillicothe Facility

Permit Number: P0103673 

Facility ID: 0671010028 

Effective Date: 3/7/2011

Page 35 of 41

emissions unit during each calendar month. The coal sampling shall be performed in 

accordance with the most recent version of ASTM method D2234, Collection of a Gross 

Sample of Coal. 

Each monthly composite sample of coal shall be analyzed for ash content (in percent), 

sulfur content (in percent), and heat content (in Btu/pound). The analytical methods for 

ash content, sulfur content, and heat content shall be the most recent version of: ASTM 

method D3174, Ash in the Analysis of Coal and Coke; ASTM method D3177, Total 

Sulfur in the Analysis Sample of Coal and Coke or ASTM method D4239, Sulfur in the 

Analysis Sample of Coal and Coke Using High Temperature Tube Furnace Combustion 

Methods; and ASTM method D5865, Gross Calorific Value of Coal and Coke, 

respectively. Alternative, equivalent methods may be used upon written approval from 

the Ohio EPA, Southeast District Office. 

The requirements to analyze the sulfur content of the composite coal sample and to 

calculate the pounds per million Btu sulfur dioxide emission rate pursuant to this term 

and condition shall terminate on December 31, 2014 because the sulfur dioxide 

continuous monitoring system required under section d)(6) and the monitoring and 

recordkeeping provisions for the pounds per million Btu and pounds per calendar day 

emission limitations under section d)(8) become effective on that date. 

(5) The permittee shall comply with the requirements of one of the following alternatives 

pertaining to the use of number 2 fuel oil: 

a. Alternative 1: 

For each shipment of oil received for burning in this emissions unit, the permittee 

shall collect or require the oil supplier to collect a representative grab sample of 

oil and maintain records of the total quantity of oil received, the permittee's or oil 

supplier's analyses for sulfur content and heat content, and the calculated sulfur 

dioxide emission rate (in lbs/million Btu). The sulfur dioxide emission rate shall be 

calculated in accordance with the formula specified in OAC rule 3745-18-04(F). A 

shipment may be comprised of multiple tank truck loads from the same supplier's 

batch, and the quality of the oil for those loads may be represented by a single 

batch analysis from the supplier. 

b. Alternative 2: 

The permittee shall collect a representative grab sample of oil that is burned in 

this emissions unit for each day when the emissions unit is in operation. If 

additional fuel oil is added to the tank serving this emissions unit on a day when 

the emissions unit is in operation, the permittee shall collect a sufficient number 

of grab samples to develop a composite sample representative of the fuel oil 

burned in this emissions unit. A representative grab sample of oil does not need 

to be collected on days when this emissions unit is only operated for the purpose 

of "test-firing." The permittee shall maintain records of the total quantity of oil 

burned each day, except for the purpose of test-firing, the permittee's analyses 

for sulfur content and heat content, and the calculated sulfur dioxide emission 

rate (in lbs/million Btu). The sulfur dioxide emission rate shall be calculated in 

accordance with the formula specified in OAC rule 3745-18-04(F). 
Final Permit-to-Install 

P. H. Glatfelter Company - Chillicothe Facility

Permit Number: P0103673 

Facility ID: 0671010028 

Effective Date: 3/7/2011

Page 36 of 41

The permittee shall perform or require the supplier to perform the analyses for sulfur 

content and heat content in accordance with 40 CFR Part 60, Appendix A, Method 19, or 

the appropriate ASTM methods (such as, ASTM methods D240 and D4294), or 

equivalent methods as approved by the Director. 

The requirements to analyze the sulfur content of the number 2 fuel oil and to calculate 

the pounds per million Btu sulfur dioxide emission rate pursuant to this term and 

condition shall terminate on December 31, 2014 because the sulfur dioxide continuous 

monitoring system required under section d)(6) and the monitoring and recordkeeping 

provisions for the pounds per million Btu and pounds per calendar day emission 

limitations under section d)(8) become effective on that date. 

(6) By not later than December 31, 2014, the permittee shall install, operate, and maintain 

equipment to continuously monitor and record sulfur dioxide and exhaust gas flow data 

for this emissions unit in units of the applicable standards (pounds per million Btu and 

pounds per day). Such continuous monitoring and recording equipment shall comply 

with the requirements specified in 40 CFR Part 60, Appendix B, Performance 

Specification 6, and be operated in accordance with 40 CFR Part 60.13 unless otherwise 

specified in d)(7) below. 

The permittee shall maintain records of all data obtained by the continuous sulfur dioxide 

and exhaust gas flow monitoring system including, but not limited to, minute-by-minute 

concentration data for sulfur dioxide; minute-by-minute flow data in ACFM; sulfur dioxide 

data in pounds per day; the results of all daily, weekly, and quarterly calibration checks; 

and the magnitude of any calibration adjustments. 

Each continuous emissions monitoring system (CEMS) consists of all the equipment 

used to acquire and record data and includes any sample extraction and transport 

hardware, sample conditioning hardware, analyzers, and data recording/processing 

hardware and software. 

The data recorded by the CEMS shall be used to determine compliance with the 

applicable emission limitations on an ongoing basis. 

(7) By not later than March 31, 2014, the permittee shall develop a written quality 

assurance/quality control plan for the continuous sulfur dioxide and exhaust gas flow 

monitoring system designed to meet all requirements as listed in 40 CFR Part 60, 

Appendix F and ensure continuous valid and representative readings of sulfur dioxide 

and flow. The plan shall describe in detail, complete, step-by-step procedures and 

operations for each of the following activities: 

a. calibration of CEMS; 

b. calibration drift determination and adjustment of CEMS; 

c. preventive maintenance of CEMS (including spare parts inventory); 

d. data recording, calculations, and reporting; 

e. accuracy audit procedures including sampling and analysis methods; and 
Final Permit-to-Install 

P. H. Glatfelter Company - Chillicothe Facility

Permit Number: P0103673 

Facility ID: 0671010028 

Effective Date: 3/7/2011

Page 37 of 41

f. program of corrective action for malfunctioning CEMS. 

The permittee shall be required to complete a CEMS certification relative accuracy test 

audit (RATA), in accordance with the procedures specified in 40 CFR Part 60, Appendix 

F, by not later than December 31, 2014. From the date of CEMS certification forward, 

the permittee may forego annual RATA requirements as listed in 40 CFR Part 60, 

Appendix F, by completing a quarterly cylinder gas or relative accuracy audit, in 

accordance with 40 CFR Part 60, Appendix F, for each quarter of the year. Should any 

CEMS not pass a cylinder gas or relative accuracy audit on the first attempt for two 

consecutive quarters (even though a recalibration or repair allows the second attempted 

cylinder gas or relative accuracy audit to pass), the permittee shall complete a RATA 

within 60 days of the second quarter's failed cylinder gas or relative accuracy audit. The 

permittee shall also complete a RATA for the CEMS within six months prior to the 

expiration of this permit. RATA testing may also be required if the CEMS as listed on 

the CEMS certification letter from the Ohio EPA, Central Office, or any CEMS associated 

equipment, is changed or modified. 

Beginning on December 31, 2014, the permittee shall perform daily zero/span calibration 

drift checks on each sulfur dioxide and flow CEMS for 60 consecutive operating days in 

accordance with the requirements specified in 40 CFR Part 60, Appendix F, section 4. 

If, on the first attempt, the results of each daily zero/span calibration drift check are less 

than the criteria for excessive calibration drift specified in 40 CFR Part 60, Appendix F, 

section 4.3 (as determined by the Ohio EPA, Southeast District Office), the permittee 

shall begin performing zero/span calibration drift checks on a weekly basis. If any 

CEMS should fail a weekly zero/span calibration drift check for two consecutive weeks 

(based on the criteria of being two times over the limit as stated in Appendix F, section 

4.3), the permittee shall perform daily zero/span calibration drift checks until such time 

as 60 consecutive daily zero/span calibration drift checks have been successfully 

completed within the criteria specified in Appendix F, section 4.3. 

The quality assurance/quality control plan and a logbook dedicated to the sulfur dioxide 

and flow CEMS must be kept on site and available for inspection during regular office 

hours. 

(8) By not later than December 31, 2014, the permittee shall maintain daily records of the 

following information: 

a. the total sulfur dioxide emissions from this emissions unit based upon the data 

collected in section d)(6), in pounds per million Btu and pounds per calendar day; 

b. the total sulfur dioxide emissions from this emissions unit and emissions unit 

B002, combined, based upon the data collected in section d)(6)for each unit, in 

pounds per calendar day; and 

c. the identification of any days (excluding any days within the “control period” 

specified in OAC Chapter 3745-14) when this emissions unit was in service and 

the unit’s low-NOx staged-combustion burners were not operating at their lowestNOx mode.

(9) The permittee shall maintain records for each day when emissions units B002, B003, 

and B013 were all off line and the venting of high-volume low concentration NCG was 
Final Permit-to-Install 

P. H. Glatfelter Company - Chillicothe Facility

Permit Number: P0103673 

Facility ID: 0671010028 

Effective Date: 3/7/2011

Page 38 of 41

uncontrolled. If emissions unit B002 is permanently shut down after December 31, 2014, 

the permittee shall maintain records for each day when emissions units B003 and B013 

were off line and the venting of high-volume low concentration NCG was uncontrolled. 

e) Reporting Requirements 

(1) The permittee shall submit reports (hardcopy or electronic format) within one month 

following the end of each calendar quarter to the Ohio EPA, Southeast District Office 

documenting all instances of opacity values in excess of the limitation specified in 

section b)(1)b. of these terms and conditions, detailing the date, commencement and 

completion times, duration, magnitude (percent opacity), reason (if known), and 

corrective actions taken (if any) of each 6-minute block average above the applicable 

opacity limitations. 

The reports shall also identify any excursions of the start-up and shutdown provisions 

specified in OAC rule 3745-17-07(A)(3) and document any continuous opacity 

monitoring system downtime while the emissions unit was on line (date, time, duration 

and reason) along with any corrective action taken. The permittee shall provide the 

emissions unit operating time during the reporting period and the date, time, reason, and 

corrective action taken for each time period of emissions unit and control equipment 

malfunctions. The total operating time of the emissions unit and the total operating time 

of the analyzer while the emissions unit was on line shall be included in the quarterly 

report. 

If there are no excess emissions during the calendar quarter, the permittee shall submit 

a statement to that effect along with the date, time, reason, and corrective action taken 

for each time period of monitoring system malfunction. The total operating time of the 

emissions unit and the total operating time of the analyzer while the emissions unit was 

on line also shall be included in the quarterly report. 

These quarterly excess emission reports shall be submitted by January 31, April 30, July 

31, and October 31 of each year, and each report shall address the data obtained during 

the previous calendar quarter. 

(2) The permittee shall submit quarterly deviation (excursion) reports that identify whenever 

a monthly composite sample collected pursuant to section d)(4) above indicates a 

deviation from the allowable sulfur dioxide emission rate. These reports shall be 

submitted in accordance with the reporting requirements specified in the Standard 

Terms and Conditions of this permit. 

The requirements to submit quarterly deviation (excursion) reports pursuant to this term 

and condition shall terminate on December 31, 2014 because the sulfur dioxide 

continuous monitoring system required under section d)(6) and the monitoring and 

recordkeeping provisions for the pounds per million Btu and pounds per calendar day 

emission limitations under section d)(8) become effective on that date. 

(3) The permittee shall notify the Ohio EPA, Southeast District Office in writing of any record 

that shows a deviation of the allowable sulfur dioxide emission limitation based upon the 

calculated sulfur dioxide emission rates from section d)(5) above when firing number 2 

fuel oil. The notification shall include a copy of such record and shall be sent to the Ohio 
Final Permit-to-Install 

P. H. Glatfelter Company - Chillicothe Facility

Permit Number: P0103673 

Facility ID: 0671010028 

Effective Date: 3/7/2011

Page 39 of 41

EPA, Southeast District Office. These reports shall be submitted in accordance with the 

reporting requirements specified in the Standard Terms and Conditions of this permit. 

The requirements to submit quarterly deviation (excursion) reports pursuant to this term 

and condition shall terminate on December 31, 2014 because the sulfur dioxide 

continuous monitoring system required under section d)(6) and the monitoring and 

recordkeeping provisions for the pounds per million Btu and pounds per calendar day 

emission limitations under section d)(8) become effective on that date. 

(4) The permittee shall submit quarterly deviation (excursion) reports that identify any period 

of time when emissions units B002, B003, and B013 were all off line and the venting of 

high-volume low concentration NCG was uncontrolled. If emissions unit B002 is 

permanently shut down after December 31, 2014, the permittee shall submit deviation 

(excursion) reports that identify any period of time when emissions units B003 and B013 

were off line and the venting of high-volume low concentration NCG was uncontrolled. 

These reports shall be submitted in accordance with the reporting requirements 

specified in the Standard Terms and Conditions of this permit. 

(5) Beginning in calendar year 2015, the permittee shall submit reports within one month 

following the end of each calendar quarter to the Ohio EPA, Southeast District Office 

documenting the date, commencement and completion times, duration, magnitude, 

reason (if known), and corrective actions taken (if any), of all instances of sulfur dioxide 

values in excess of the applicable limitations (pounds per million Btu and pounds per 

day) specified in this permit. 

The reports shall document any continuous sulfur dioxide and exhaust gas flow 

monitoring system downtime while the emissions unit was on line (date, time, duration 

and reason) along with any corrective action(s) taken. The permittee shall provide the 

emissions unit operating time during the reporting period and the date, time, reason and 

corrective action(s) taken for each time period of emissions unit and control equipment 

malfunctions. The total operating time of the emissions unit and the total operating time 

of the analyzer while the emissions unit was on line shall also be included in the 

quarterly report. 

If there are no excess emissions during the calendar quarter, the permittee shall submit 

a statement to that effect along with the emissions unit operating time during the 

reporting period and the date, time, reason, and corrective action(s) taken for each time 

period of emissions unit, control equipment, and/or monitoring system malfunctions. The 

total operating time of the emissions unit and the total operating time of the analyzer 

while the emissions unit was on line also shall be included in the quarterly report. These 

quarterly excess emission reports shall be submitted by January 31, April 30, July 31, 

and October 31 of each year and shall address the data obtained during the previous 

calendar quarter.

(6) Beginning in calendar year 2015, the permittee shall submit quarterly deviation 

(excursion) reports that identify any days (excluding any days within the “control period” 

specified in OAC Chapter 3745-14) when this emissions unit was in service and the 

unit’s low-NOx staged-combustion burners were not operating at their lowest-NOx mode. 

These reports shall be submitted in accordance with the reporting requirements 

specified in the Standard Terms and Conditions of this permit. 
Final Permit-to-Install 

P. H. Glatfelter Company - Chillicothe Facility

Permit Number: P0103673 

Facility ID: 0671010028 

Effective Date: 3/7/2011

Page 40 of 41

f) Testing Requirements 

(1) Compliance with the emission limitations in section b)(1) of these terms and conditions 

shall be determined in accordance with the following methods: 

a. Emission Limitation: 

Visible particulate emissions from the exhaust stack serving emissions units 

B002 and B003 shall not exceed 20% opacity as a 6-minute average, except as 

provided by the rule. 

Applicable Compliance Methods: 

If required, compliance with this emission limitation shall be demonstrated 

through visible emission observations performed in accordance with 40 CFR Part 

60, Appendix A, Method 9 and the procedures specified in OAC rule 3745-17-

03(B)(1). 

Ongoing compliance with this emission limitation may be demonstrated based 

upon the records required pursuant to section d)(1). 

b. Emission Limitation: 

Particulate emissions shall not exceed 0.10 pound per million Btu of actual heat 

input, when firing coal. 

Applicable Compliance Method: 

If required, compliance with this emission limitation also shall be demonstrated 

through emission tests performed in accordance with 40 CFR Part 60, Appendix 

A, Methods 1 through 5 and the procedures specified in OAC rule 3745-17-

03(B)(9). 

c. Emission Limitation: 

Particulate emissions shall not exceed 0.020 pound per million Btu of actual heat 

input, when firing only number 2 fuel oil. 

Applicable Compliance Method: 

Compliance with this emission limitation may be determined by multiplying an 

emission factor of 2.0 pounds of particulates per 1000 gallons of fuel oil fired by 

the emissions unit's maximum hourly fuel oil firing capacity (3504 gallons/hr), 

dividing by the emissions unit's rated heat input capacity (505 million Btu/hr), and 

dividing by 1000. This emission factor is specified in U.S. EPA reference 

document AP-42, Fifth Edition, Compilation of Air Pollution Emission Factors, 

Section 1.3, Table 1.3-1 (5/10). 

If required, the permittee shall demonstrate compliance with this emission 

limitation through emission tests performed in accordance with 40 CFR Part 60, 

Appendix A, Methods 1 through 5 and the procedures specified in OAC rule 

3745-17-03(B)(9).
Final Permit-to-Install 

P. H. Glatfelter Company - Chillicothe Facility

Permit Number: P0103673 

Facility ID: 0671010028 

Effective Date: 3/7/2011

Page 41 of 41

d. Emission Limitation: 

Sulfur dioxide emissions shall not exceed 9.9 pounds per million Btu actual heat 

input. 

Applicable Compliance Methods: 

When firing fuel oil, compliance with this sulfur dioxide emission limitation may be 

demonstrated based upon the records required pursuant to section d)(5). 

When firing coal, compliance with this sulfur dioxide emission limitation may be 

demonstrated based upon the records required pursuant to section d)(4). 

On and after installation and operation of the control technology required under 

section b)(2)b. above is complete, compliance with this sulfur dioxide emission 

limitation shall be demonstrated based upon the records required pursuant to 

sections d)(6) and d)(8). 

Also, if required, the permittee shall demonstrate compliance with the allowable 

sulfur dioxide emission limitation through emission tests performed in accordance 

with 40 CFR Part 60, Appendix A, Methods 1 through 4 and 6 or 6A. 

e. Emission Limitation: 

By not later than December 31, 2014, sulfur dioxide emissions from emissions 

units B002 and B003, combined, shall not exceed 24,930 pounds per calendar 

day. 

Applicable Compliance Method: 

Compliance with this sulfur dioxide emission limitation shall be demonstrated 

based upon the records required pursuant to sections d)(6) and d)(8). 

Also, if required, the permittee shall demonstrate compliance with the allowable 

sulfur dioxide emission limitation through emission tests performed in accordance 

with 40 CFR Part 60, Appendix A, Methods 1 through 4 and 6 or 6A. 

g) Miscellaneous Requirements 

(1) None.