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

Page 1 of 11 

## 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 MRPOstates 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)

Page 2 of 11 

## 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)

Page 3 of 11 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)

Page 4 of 11 - 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)

Page 5 of 11 - 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 30 th 

### 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)

Page 6 of 11 • 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)

Page 7 of 11 • 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)

Page 8 of 11 - 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 RACTproposal 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)

Page 9 of 11 • 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 dieselMichigan 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 16 th 

### . 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 ControlSeptember 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 asEGUs 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 of6B. 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 6Again, 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
LAD CO 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

2 X 

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

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

2X 3 

### 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, 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

2X 3 

### Table 2-2. CAMx Model Sensitivity Analysis of the Impacts of SO , NO , and NH Emission 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 . . . . . . . . . . . . . . . . 18Table 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

2 

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

X 

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

2 

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

X 

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

X 2 

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

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

X 

### Table 5.6-4. NO Control Technologies Available for Melting Furnaces at the Cardinal FG Facility . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 82

X 

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

X 

### Table 5.6-13. Cost Effectiveness of NO Control Technologies at Model Oil Refinery . . . . . . 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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 110ACT Alternative Control Techniques

ALAPCO Association of Local Air Pollution Control Officials

ANPRM Advance Notices of Proposed Rulemaking

APU Auxiliary Power Unit

ASO A 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

CAI R Clean Air Interstate Rule

CAM x Comprehensive Air Modeling with extensions

CARB California Air Resources Board

CUECos t 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

Re p ort 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

Strate gy 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

LRAP A 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

mmBt u Million British Thermal Units

MN Minnesota

MO Missouri

MRPO Midwest Regional Planning Organization

MW Megawatt

N AAQS National Ambient Air Quality Standards

N ACA A National Association of Clean Air Agencies

N D North Dakota

N EEDS National Electric Energy System Database

N EI National Emission Inventory

N ESCAUM Northeast States for Coordinated Air Use Management

OF A Overfire Air

OH Ohio

OTC Ozone Transport Comission

POC Primary Organic Carbon (particulate)

PSAT Particle Source Apportionment Tool

RI A Regulatory Impact Assessment

RICE Reciprocating Internal Combustion Engines

SCR Selective Catalytic Reduction

SD South Dakota

SD A 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 generalmethodology 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.

2 

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

2 

### 2018. As can be seen, sulfates are the dominant species indicating the importance of SO
emissions.

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

2 X 

### Figure 2-3 and Table 2-1 summarize the major contributors to the SO , NO , and ammonia emissions inventories in 2002 and 2018 for Michigan, Minnesota, and Wisconsin – the three

2X 3 

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

Michigan, Minnesota, and Wisconsin.2002 2018 2002 2018 2002 2018 2002 2018Point sourcesElectric generating units2,023 1,755 1,013 514 7,489 4,952 3,507 1,564Industrial, commercial and institutional boilers227 215 136 132 674 641 413 400Reciprocating engines71 66264 254Turbines19 2042 45Other point sources156 196 257 287 815 948 616 669Area sources113 112 208 225 594 588 462 515Mobile sourcesOnroad1,862 7084,5291,250Nonroad514 557 338 123 19 1,437 1,288Marine, aircraft, railroad21 11 294 22244 20 969 666Total2,592 2,294 4,417 2,512 9,739 7,168 12,239 6,650Table 2-1. Regional Emissions SummaryEstimated emissions in the 3-state regionsurrounding the northern Midwest Class I areas(tons/day)Estimated emissions in a larger 9-state region(tons/day)SO2 NOX SO2 NOX5The 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

2 EGU projections reflect lower 2018 SO 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 futureyear 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 Kemissions 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

2 

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

2 X 

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

X 

### emissions in 2002, followed by EGUs. NO emissions from both EGU and mobile sources are projected to decline between 2002 and 2018, but they are still projected to be the largest sources

X 

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

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

2X 3 

### potential impacts of SO , NO , and NH emission reductions on light extinction in the northern 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.

2 

### A 10% reduction in SO emissions is predicted to reduce light extinction from sulfate particulate matter by 7.7 to 8.9%, and overall particulate light extinction by 1.3 to 3.5% in the northern

2 

### Midwest Class I areas. The SO emission reduction is predicted to increase extinction of nitrate 2X 3 

### Figure 2-4. Summary of SO , NO , and NH emissions in Michigan, Minnesota, Wisconsin, Illinois, Indiana, Iowa, Missouri, North Dakota, and South Dakota.

### 7 3



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

42 4 4 4 3 

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

4 3 X 

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

4 3 

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

3 

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

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.

2 X 

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

3 

### and NH Emission Reductions on Visibility

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

X 2 

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

2 

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

2.5 

### environmental impacts was provided in Factor 3 (e.g., improvement in ambient PM and ozone

X 2 

### concentrations due to reductions in regional NO and SO emissions).

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

2 

### Additional CO produced

Reduced acid deposition

Reduced nitrogen deposition

2.5 

### Benefits from reductions in PM and ozone, where available

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

2 

### CO ) produced



## 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 ), =

3 4 

### nitrate (NO ), and ammonium (NH ) fractions of particulate matter, as well as other particulate

– + 

### 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

2 X 

### emission control strategies for SO and NO emissions from different source categories. In this 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:

i,j,k 2 X 3 

### RX = estimated reduction in extinction coefficient for pollutant i (SO , NO , or NH ), category j, and source region k (Mm ) –1

i,j,k 

### Rdn = estimated emission reduction resulting from a control strategy for pollutant i,

emission source category j and source region k (tons/year)

### 13 i,j,k 

### PSAT = estimated contribution of emissions for the particulate species corresponding to

4 23 X 4 3 

### pollutant i (SO for SO , NO for NO , and NH for NH ), for category j, and =– + 

### source region k to the extinction coefficient, based on PSAT modeling for 2018 (Mm ) –1

i,tot 

### PSAT = total contribution pollutant i from PSAT modeling (Mm ) –1

i,j,k 

### Emis = projected emission rate in 2018 for pollutant i, source category j, and source

region k, with on-the-books controls but before the application of any additional control strategy (tons/year)

i 

### SensXChg = Predicted change in extinction based on the results of CAMx sensitivity analysis

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 theuncertainties 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

2 

### SO –1.7 –1.0 –2.0 –3.4

X 

### NO –1.7 –2.0 –1.9 –1.9

3 

### NH –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)

n 

### 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)

### 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 thisanalysis 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 RIA 8, 9

BART Company BART analyses, where available 10, 11

Maximum Available Control Technology (MACT)

standards • Reciprocating Internal Combustion Engines (RICE) MACT Federal Register Notice 12

• Industrial Boilers and Process Heaters MACT Federal Register Notice 13

On-road mobile source programs • 2007 Highway Diesel Rule RIA 14

• Tier II Emissions Standards RIA 15

• Low Sulfur Gasoline RIA 15

Non-road mobile source programs • Non-road Diesel Rule RIA 16
• Control of Emissions from Unregulated Non-road Engines RIA 17

• Locomotive/Marine ANPRM 18



## 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

2 X 

### and-trade programs to reduce SO and NO emissions from EGUs in the eastern U.S. Other cap-

2 X X 

### and-trade programs for SO and NO include the Acid Rain Program and the NO SIP call for the ozone National Ambient Air Quality Standards (NAAQS).Factor 1Factor 4Control StrategyCost effectiveness ($/ton)EnergySolid wasteproduced(1000tons/year) Remaining Useful Life3-State SO2: 13% 3-State SO2: 47% 4.5% of total 2,383NOX: 75%NOX: 75%9-State SO2: 34% 9-State SO2: 48%NOX: 79%NOX: 80%BART: Based on company BARTanalyses from MN and ND$248 - $1,770Combustion 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 gallonsof fuel savedThe IPM model projects that53 units will retire by 2018.Table 4-2. Summary of Five-Factor Analysis of On-The-Books ControlsFactor 2Factor 3CAIR and other cap-and-tradeprograms (e.g., Acid Rain, NOXSIP Call)$720 - $2,600Percent EmissionReductions from 2002baseline in 2018Percent EmissionReductions from 2002baseline at fullimplementation16The 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 futureyear 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 controltechnologies 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.

X 

### 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

2 

### institutional boilers and process heaters are expected to reduce HAP emissions as well as SO

2 

### emissions through sorbent injection controls. The cost per ton of SO removed is estimated at 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

X 

### Appendix A show, most of the CAIR NO emission reductions in the Midwest are expected to be

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 O p eratin g Com p an y) 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

X 2 

### expected that any reduction in NO or SO emissions will decrease nitrate and sulfate deposition. 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 controls b 

### 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 areasa These facilities were selected based on a review of SO 2 and NO X 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, th e 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:

• SO 2 

### and NO X 

### emissions from electric generating units (EGUs)
• SO 2 

### and NO X 

### emissions from Industrial, commercial and institutional (ICI) boilers • Ammonia from agricultural operations
• NO X 

### emissions from onroad and nonroad mobile sources
• NO X 

### 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 SO 2 

### , NO X 

### and NH 3 

### 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 SO 2 

### and NO X 

### emissions from EGUs. These strategies would establishState County Unit ID Facility NameUnit DescriptionsMI Marquette B4261 Wisconsin Electric/Presque IsleMI Ottawa B2835 JH CampbellMI St_Clair B2796 St. Clair/BelleRiverMN Itasca 2706100004 Clay BoswellUnits 1,2,4 – NOx, SO2MN St. Louis 2713700013 Syl LaskinUnits 1,2 – SO2MN St. Louis 2713700028 VA PUCWI Buffalo 606034110 Dairyland Power Coop/AlmaWI Grant 122014530 Alliant Energy/Nelson DeweyWI Sheboygan 460033090 Alliant Energy/EdgewaterWI Ashland 802033320 Xcel Energy/BayfrontMI Alger B1470 Kimberly ClarkICI boilerMI Schoolcraft A6475 Manistique PapersICI boilerMI Monroe B1743 HolcimCementplantMN Lake 2707500003 Northshore Mining Company/Silver Bay EU001(EGU)MN Koochiching 2707100002 Boise Cascade CorpICI boilerWI Douglas 816009950 Murphy OilRefinery(FCCU, Heater)WI Lincoln 735008010 PCA - TomahawkICI boilers(B28, B27)WI Dunn 617049840 Cardinal FGGlass Furnace(P01)WI Douglas 816036430 CLM CorporationLime manuf.(Kilns 2,3,4)WI Manitowoc 436034390 Rockwell LimeLime manuf.(Kilns 1, 2)Non-EGUEGUTable 5-1. Individual Sources Selected for Analysis23The 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

2 EGU projections reflect lower 2018 SO emissions for the 3-state region (about 500 tons/day less). The MRPO is currently updating its regional modeling inventory to reflect a more current base year (2005) and improved futureyear 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

2 X 

### manner. Potential SO and NO regional control strategies and unit-level control technologies for EGUs are presented in Appendix B.

Two sets of possible caps have been evaluated, which are termed EGU1 and EGU2: 19

2 X 

### ! EGU1 would establish a regional emissions cap for SO and NO based on projected fuel consumption:

2 

### " SO limited to 0.15 pounds per million British thermal units (lb/million-BTU) of fossil fuel consumption in the region

X 

### " NO limited to 0.10 lb/million-BTU

2 X 

### ! EGU2 would establish regional emission caps for SO and NO based on projected fuel consumption:

2 

### " SO limited to 0.10 lb/million-BTU

X 

### " NO limited to 0.07 lb/million-BTU

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

2.5 

### PM , as well as regional haze. The timeframe considered in these previous analyses was 2009 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

X 

### Rain program, the NO SIP call, and other on-the-books controls affecting EGUs. Table 5.1-2 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-stateregion9-stateregion2,338 6,955SO2641 1,808NOX188 571SO2175 522NOX117 348SO2117 348NOX82 243SO2 NOX SO2 NOXMichigan403 164 399 100Minnesota116 99 86 42Wisconsin220 107 155 463-State Subtotal739 370 641 188Illinois478 260 241 73Indiana912 303 377 95Iowa150 93 147 51Missouri305 167 281 78North Dakota137 72 109 72South Dakota13 16 12 159-State Total2,734 1,280 1,808 571Table 5.1-2. Estimated Baseline Emissions from EGUsEmissions in 2002(1000 tons/year)Projected emissions in2018 (1000 tons/year)Table 5.1-1. Estimated Allowable Emissions Under theEGU1 and EGU2 Control StrategiesProjected 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:

2 

### ! For SO :

" Limestone forced oxidation (LSFO) scrubbers

" Lime spray dryer (LSD) scrubbers

X 

### ! For NO :

" Selective catalytic reduction (SCR)

" Selective non-catalytic reduction (SNCR)

X 

### " Low-NO burners (LNB) with and without overfire air (OFA) for dry-bottom wall-
fired boilers

X 

### " Low-NO nozzles with close-coupled and separated overfire air for tangentially-
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.

2 

### Table 5.1-3 details the estimated costs of achieving the EGU1 SO emission cap in the 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

2 

### achieving the EGU1 SO emission cap the three-state and nine-state regions, Table 5.1-3 also estimates the breakdown of costs among individual states. Table 5.1-4 provides similar cost

X 

### estimates for achieving the EGU1 NO emission cap in the three-state and nine-state regions.

2 X 

### Tables 5.1-5 and 5.1-6 estimate the costs of achieving the EGU2 caps for SO and NO , 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 LSDAverage Range3-State RegionMichigan2 37 10,441 335 1,764,626 478,652 1,428 1,000 - 2,700Minnesota0 10 593 22 140,119 39,074 1,759 1,400 - 2,600Wisconsin0 25 3,762 108 727,136 199,563 1,840 830 - 2,600Total2 72 14,796 466 2,631,881 717,289 1,540 830 - 2,7009-State RegionIllinois1 21 5,831 122 1,012,296 271,060 2,220 660 - 2,800Indiana6 31 7,737 226 1,468,135 393,705 1,744 600 - 2,900Iowa2 13 4,693 108 767,809 204,844 1,893 630 - 2,600Michigan2 40 10,599 341 1,816,190 494,297 1,451 1,000 - 2,800Minnesota1 15 1,357 42 327,549 94,410 2,254 1,400 - 2,900Missouri2 29 9,243 229 1,469,386 399,666 1,744 610 - 2,800North Dakota5 4 2,910 90 580,261 145,701 1,617 560 - 2,700South Dakota0 2 477 11 77,464 20,801 1,913 1880 - 1,900Wisconsin0 26 3,811 110 743,632 204,501 1,856 830 - 2,900Total19 181 46,658 1,279 8,262,722 2,228,985 1,743 560 - 2,900SCR LNBAverage Range3-State RegionMichigan7 4 5,675 42 315,643 75,466 1,785 1,100 - 2,700Minnesota5 4 3,175 16 115,282 36,673 2,236 520 - 3,400Wisconsin8 8 1,763 12 148,964 32,799 2,626 1,700 - 3,400Total20 16 10,613 71 579,889 144,938 2,037 520 - 3,4009-State RegionIllinois3 6 3,046 8 83,671 17,512 2,167 1,000 - 2,600Indiana9 1 5,531 32 196,829 72,760 2,304 820 - 3,000Iowa6 8 4,164 20 120,473 47,061 2,359 1,100 - 3,300Michigan7 4 5,675 42 315,643 75,466 1,785 1,100 - 2,700Minnesota1 4 3,171 15 62,982 31,038 2,103 520 - 3,200Missouri13 2 3,475 25 165,185 46,975 1,904 690 - 3,000North Dakota7 0 4,122 59 331,283 70,345 1,198 760 - 3,300South Dakota1 0 477 13 53,045 10,038 775 760 - 2,300Wisconsin7 8 1,577 11 128,463 28,068 2,536 1,700 - 3,300Total54 33 31,238 224 1,457,574 399,263 1,782 520 - 3,300Estimated numbers ofboilers needingcontrolTotalcapacitycontrolled(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*Emissionreduction(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 forinstalling various control technologies at specific facilities. Additionally, the EGU1 strategy, as analyzed here, would allowtrading of emission credits across state boundaries within the three-state or the nine-state region. Thus, the results reflect only anestimate of the costs which would be incurred to attain the EGU1 or EGU2 emission reduction targets.Total annualcost ($1000)Total annualcost ($1000)Cost effectiveness ($/ton)Totalcapacitycontrolled(MW)Emissionreduction(1000 tons/year)Capital cost($1000)Estimated numbers ofboilers needingcontrol28LSFO LSDAverage Range3-State RegionMichigan5 49 11,021 357 2,018,086 553,751 1,552 1,100 - 4,200Minnesota2 19 2,620 57 543,859 155,016 2,743 1,400 - 4,400Wisconsin0 32 4,245 119 842,255 235,523 1,981 830 - 4,200Total7 100 17,886 532 3,404,200 944,290 1,775 830 - 4,4009-State RegionIllinois2 37 9,659 183 1,796,774 466,945 2,557 660 - 4,200Indiana13 37 11,545 282 2,223,006 594,395 2,108 600 - 4,300Iowa2 25 5,229 122 940,070 253,579 2,074 630 - 4,100Michigan5 49 11,021 357 2,018,086 553,751 1,552 1,100 - 4,200Minnesota1 19 1,684 48 417,317 118,964 2,466 1,400 - 4,300Missouri2 34 9,942 240 1,637,082 441,007 1,835 610 - 4,100North Dakota5 6 2,998 93 610,686 154,657 1,668 560 - 3,600South Dakota0 2 477 11 77,464 20,801 1,913 1,900 - 1,900Wisconsin0 32 4,245 119 842,255 235,523 1,981 830 - 4,200Total30 241 56,800 1,455 10,562,740 2,839,622 1,952 560 - 4,300SCR LNBAverage Range3-State RegionMichigan38 0 8,012 60 898,882 164,478 2,734 1,100 - 7,000Minnesota25 2 4,045 26 467,345 86,734 3,298 1,700 - 7,000Wisconsin30 0 2,642 20 384,069 69,821 3,495 1,800 - 5,900Total93 2 14,699 106 1,750,296 321,033 3,016 1,100 - 7,0009-State RegionIllinois21 0 7,779 22 671,404 124,833 5,605 1,500 - 9,700Indiana38 0 5,821 46 753,961 138,817 3,036 820 - 8,600Iowa37 3 6,043 35 686,966 125,254 3,580 1,100 - 9,100Michigan39 0 8,036 60 911,972 166,300 2,754 1,100 - 7,300Minnesota29 0 4,045 27 514,675 94,752 3,456 1,700 - 8,200Missouri33 0 5,007 37 636,464 117,302 3,162 1,000 - 9,800North Dakota15 0 4,129 62 494,697 90,497 1,459 760 - 5,500South Dakota2 0 477 13 56,906 10,554 807 760 - 3,000Wisconsin40 0 4,173 25 610,076 110,532 4,418 1,800 - 8,600Total254 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 forinstalling various control technologies at specific facilities. Thus, they reflect only an estimate of the costs which would beincurred to attain the EGU1 or EGU2 emission reduction targets.Cost effectiveness ($/ton)Cost effectiveness ($/ton)Total annualcost ($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 ofboilers needingcontrolTotalcapacitycontrolled(MW)Emissionreduction(1000 tons/year)Capital cost($1000)Total annualcost ($1000)Estimated numbers ofboilers needingcontrolTotalcapacitycontrolled(MW)Emissionreduction(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

2 

### SO scrubbing technology for a single EGU boiler. The analysis also estimated that up to an 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

X 

### with one of the NO caps would be about 51⁄2 years.

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

2 

### 0.272 boilermaker-year/MW is required to fabricate and install scrubbers for SO , and 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

2 2 

### dioxide (CO ) emissions. CO is also released in the production of lime for LSD control systems

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.

2 

### As Table 5.1-8 shows, the electricity and steam required by controls installed to meet SO

X 

### and NO emission caps 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.

2 X 

### The SO and NO controls would have beneficial environmental impacts by reducing acid 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

X 

### health benefits. In addition, broad regional reductions in NO would result in reductions in

2.5 

### background levels of ambient ozone. These reductions in PM and ozone will reduce levels of 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

2 X 

### ozone as a result of SO and NO emission reductions. The EPA Environmental Benefits 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 andimpact producedMagnitude ofimpactUnitsLSDSludge3.7 ton sludge / ton of SO2 reducedElectricity7.0 kW / MW generating capacityCO2 for electricity1.0 ton CO2 / MW-hr additional electricity neededCO2 to produce lime0.69 ton CO2 / ton of SO2 reducedLSFOSludge 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 reducedSCRSludge 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 neededTable 5.1-7. Factors Used to Calculate Energy and Non-AirEnvironmental Impacts of EGU Control Measures32Emissionreduction (1000tons/year)Additionalelectricityrequirements(GW-hrs /year)Steamrequirements(1000 tons/yr)Solid wasteproduced(1000tons/year)Wastewaterproduced(milliongallons/year)AdditionalCO2 emitted(1000tons/year)EGU1 Emission Caps3-State RegionSO2466706 510 1,323 192 1,059NOX7140171.7042Total 537 746 526 1,324 192 1,1019-State RegionSO2 1,279 2,649 3,462 3,632 1,128 3,651NOX 224 110 46 4.6 0 115Total 1,503 2,759 3,508 3,637 1,128 3,766EGU2 Emission Caps3-State RegionSO2 532 1,106 1,722 1,511 237 1,523NOX 106 174 73 7.3 0 181Total 639 1,279 1,795 1,519 237 1,3379-State RegionSO2 1,455 3,504 5,439 4,132 1,919 4,666NOX 328 608 255 25.4 0 636Total 1,783 4,113 5,695 4,157 1,919 5,301Table 5.1-8. Estimated Energy and Non-Air Environmental Impacts of EGU ControlStrategies33Health effectNumber ofcases avoidedValue ofbenefit($1000)Number ofcases avoidedValue ofbenefit($1000)Number ofcases avoidedValue ofbenefit($1000)Number ofcases avoidedValue ofbenefit ($1000)Acute bronchitis2,700 1,100 5,000 2,100 3,200 1,300 5,900 2,500Acute myocardial infarction3,400 270,000 6,100 480,000 3,900 310,000 7,200 560,000Acute respiratory symptoms1,223,000 140,000 2,168,000 250,000 1,473,000 170,000 2,589,000 300,000Asthma exacerbation73,300 3,700 131,400 6,700 86,200 4,400 154,200 7,900Chronic bronchitis1,000 410,000 1,900 770,000 1,200 480,000 2,200 900,000Emergency room visits for respiratory symptoms 2,100 790 3,400 1,200 2,500 930 4,000 1,400Hospital admissions for cardiovascular symptoms 600 15,000 1,200 29,000700 18,000 1,400 34,000Hospital admissions for respiratory symptoms 1,100 19,000 1,900 32,000 1,400 23,000 2,400 39,000Lower respiratory symptoms29,000 540 52,100 960 34,000 630 61,100 1,200Premature mortality1,570 10,000,000 3,010 20,000,000 1,860 12,000,000 3,540 23,000,000School loss days27,600 2,500 33,500 3,000 45,600 4,100 55,700 5,000Work loss days192,600 31,000 348,300 55,000 226,200 36,000 408,600 63,000Worker productivity loss9601,3001,7002,300Total11,000,00022,000,00013,000,00025,000,000Source: 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, Indiana, Michigan, Ohio, andWisconsinTable 5.1-9. Estimated Annual Health Benefits of EGU Control Strategies Applied to the 5-State MRPO RegionEGU1 Control StrategyEGU2 Control StrategyBenefits in the MRPO regionTotal benefits in the MRPOregion and downwindregionsBenefits in the MRPO regionTotal benefits in the MRPOregion and downwind regions34Predicted 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

X 

### estimated NO emission reductions for the 5 region were midway between the emission 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

X 

### LSFO and LSD, and 20 years for SCR, SNCR, and low-NO combustion modifications. The 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-MidwestClass 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 overX 2 

### estimate or under-estimate the 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.Strategy and regionBoundaryWatersVoyageursIsleRoyale Seney AverageBoundaryWatersVoya-geursIsleRoyale Seney AverageEGU1 Emission Caps3-State RegionSO20.30 0.12 0.44 0.41 0.32 1,383 1,135 1,476 1,755 1,437NOX0.07 0.05 0.06 0.04 0.06 302 244 287 309 285Total0.38 0.17 0.50 0.45 0.37 1,685 1,378 1,762 2,064 1,7239-State RegionSO20.77 0.35 0.84 1.01 0.74 2,961 2,661 3,036 3,391 3,012NOX0.18 0.24 0.15 0.12 0.17 604 555 565 573 574Total0.95 0.59 1.00 1.13 0.92 3,565 3,216 3,601 3,964 3,586EGU2 Emission Caps3-State RegionSO20.46 0.21 0.52 0.46 0.41 1,647 1,385 1,760 2,035 1,707NOX0.12 0.08 0.09 0.07 0.09 467 365 431 453 429Total0.58 0.29 0.61 0.53 0.50 2,114 1,750 2,191 2,489 2,1369-State RegionSO20.87 0.40 0.96 1.18 0.85 3,274 2,948 3,432 3,826 3,370NOX0.26 0.30 0.23 0.19 0.24 918 819 858 875 867Total1.13 0.69 1.18 1.37 1.09 4,192 3,767 4,291 4,701 4,238Table 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 emission-todistance ratios (Q/d; tons/yr-mi)*37Strategy 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

2 X 

### Source apportionment analyses identify SO and NO emissions from non-EGU point 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

2 X 

### 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 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

X 2 

### capacity at least 100 Mmbtu/hr, or emitting at least 100 tons/year of either NO or SO ). Coal- fired boilers were examined in particular, as they are estimated to contribute the largest fraction

2 X 

### of SO and NO boiler state-wide emissions in 2018.

The first strategy was adopted from Candidate Measure ID ICI1 in the ICI boiler white

2 X 

### paper, and requires a 40% SO reduction and a 60% NO reduction from 2018 baseline

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

2 X 

### MRPO’s Strategy Workgroup and identifies specific SO and NO emissions limitations as a function of boiler type and size, and fuel type (see Table 5.2-3). This strategy provides

2 X 

### approximately a 77% reduction in SO emissions and a 70% reduction in NO emissions.

To achieve these reductions, the following control technologies were analyzed:

2 

### ! For SO :

" Spray-dry absorbers (SDA) (90% control)

" Fuel switching for oil-fired boilers

X 

### ! For NO :

" 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

2 

### Table 5.2-1 provides a comparison of 2002 and 2018 SO baseline emissions for ICI 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

X 

### proposed emission reduction strategies. Table 5.2-2 gives a similar summary for NO . ICI

2 X 

### emissions from point sources contribute 63% of total SO ICI emissions, and 57% of total NO 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

40Projected 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 RegionEmissions (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/hr50-100 million-btu/hr100 - 250million-btu/hr>250 million-btu/hrNatural Gas and other gaseousfuelsCombustiontuning0.060.06Fuel Oil(#2 – distillate)"0.100.10Fuel Oil(#6 – residual)"0.200.20Coal-Wall"0.140.14Coal-Tangential"0.120.12Coal-Stoker"0.220.22Coal-FBC"0.080.08Wood/Non-Fossil solid Fuel"0.220.22Distillate 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 FactorGas-fired1.02Oil-fired1.01Solid fuel1.01Coal0.93Gas-fired1.02Oil-fired0.97Solid fuel0.89Coal0.93Table 5.2-3. ICI Workgroup Proposed Emission CapsBoiler and Fuel TypeSuggested Limit (lb/MMBTU)Proposed NOx Emission TargetsSO2Proposed SO2 Emission Targets0.05% sulfur by weight0.5% sulfur by weightTable 5.2-4. AverageGrowth Factors for theMRPO RegionNOX43

### 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

2 X 

### developed cost curves using the SO and NO control cost methodology developed by EPA for 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

2 

### 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 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

X 

### and NO , respectively.

2 

### The ICI1 Strategy for SO emissions can be achieved in the 3-State and 9-State region by 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

2 

### The ICI Workgroup Strategy for SO emissions can be achieved by controlling coal-fired boilers with SDA and oil-fired boilers with fuel switching to a lower sulfur fuel. The strategy for

X 

### 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 ranges between

2 X 

### $1,944 - $6,584 per ton of SO reduced, and $1,149 - $9,250 per ton of NO reduced. In the

2 

### 9-State region, cost effectiveness ranges between $1,194 - $9,403 per ton of SO reduced and

X 

### $699 - $5,488 per ton of NO reduced. These values are above the ranges given in the NACAA 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 TypeControlTechnologyPotentialEmissionReduction (1000Tons/yr)Average CapitalCosts ($1000)Average O&MCost ($1000)AverageAnnualized Cost($1000)Average CostEffectiveness($/ton)Cost Effectiveness Range($/ton)CoalSDA32 360,313 42,93196,904 2,998OilFuel Switching 1---- 1,459 2,643Grand Total33 360,313 42,931 98,363 2,992 1,944 - 3,021CoalSDA93 749,979 98,544210,887 2,258OilFuel Switching12---- 27,800 2,414Grand Total105 749,979 98,544 238,687 2,275 1,194 - 2,696Fuel TypeControlTechnologyPotentialEmissionReduction (1000Tons/yr)Average CapitalCosts ($1000)Average O&MCost ($1000)AverageAnnualized Cost($1000)Average CostEffectiveness($/ton)CostEffectivenessRange ($/ton)CoalSCR19 181,776 21,04345,472 2,410GasLNB/OFA/GR348,497 2,4088,925 2,909OilSCR111,9059472,547 4,992Grand Total22 242,178 24,39756,944 2,537 1,149 - 5,478CoalSCR35 326,145 38,65082,482 2,358Gas-fired LNB/OFA/GR27 263,852 12,52947,989 1,757Oil-fired SCR1136,835 3,6478,598 785Grand Total73 626,833 54,827139,068 1,899 699 - 3,911Table 5.2-5. Estimated Costs of ICI1 SO2 Controls for the 3-State and 9-State Regions3-State Region9-State Region9-State RegionTable 5.2-6. Estimated Costs of ICI1 NOX Controls for the 3-State and 9-State Regions3-State Region46Fuel TypeControlTechnologyPotentialEmissionReduction (1000Tons/yr)Average CapitalCosts ($1000)Average O&MCost ($1000)AverageAnnualized Cost($1000)Average CostEffectiveness($/ton)CostEffectivenessRange ($/ton)CoalSDA50 489,325 61,616134,915 2,683OilFuel Switching2----8,579 3,779Grand Total53 489,325 61,616143,493 2,7311,944 - 6,584CoalSDA145 1,549,160 194,981427,037 2,953OilFuel Switching24----35,739 1,482Grand Total169 1,549,160 194,981462,776 2,7431,194 - 9,403Fuel TypeControlTechnologyPotentialEmissionReduction (1000Tons/yr)Average CapitalCosts ($1000)Average O&MCost ($1000)AverageAnnualized Cost($1000)Average CostEffectiveness($/ton)CostEffectivenessRange ($/ton)CoalSCR23 352,042 38,18385,495 3,682GasLNB/OFA/GR5 108,523 4,98419,569 4,103OilSCR120,180 1,7664,479 6,144Grand Total29 480,745 44,933109,543 3,814 1,149 - 9,250CoalSCR45 508,902 60,083128,476 2,879GasLNB/OFA/GR29 315,868 14,96657,417 1,970OilSCR1148,741 4,59411,145 972Grand Total85 873,511 79,643197,038 2,311699 - 5,4889-State Region3-State Region9-State RegionTable 5.2-7. Estimated Costs of ICI Workgroup SO2 Controls for the 3-State and 9-State RegionsTable 5.2-8. Estimated Costs of ICI Workgroup NOX Controls for the 3-State and 9-State Regions3-State Region47

### 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

2 

### and the ICI Workgroup SO strategies in six and a half 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

X 

### one of the NO strategies would be about five and a half years. This estimate is based on the following information:

! Two years for rule development and implementation

! Up to a year for industry to procure the necessary capital to purchase control equipment.

X 

### ! Eighteen months to design, fabricate, and install SCR or SNCR technology for NO

2 

### control, and approximately 30 months to design, build, and install SO scrubbing 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

2 X 

### SO and NO emission caps would be less than 1% of the total electricity and steam production 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

49Emission reduction (1000 tons/year) Additional electricityrequirements (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-MidwestClass 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 amechanism for evaluating the relative impacts of different strategies. However, they may overX 2 

### estimate or under-estimate the 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.Strategy Region PollutantBoundaryWaters Voyageurs Isle Royale Seney AverageICI1 3-State SO20.07 0.03 0.07 0.05 0.06NOX0.07 0.05 0.03 0.02 0.049-State SO20.09 0.05 0.09 0.11 0.08NOX0.10 0.07 0.05 0.06 0.073-State SO20.10 0.06 0.11 0.09 0.09NOX0.10 0.06 0.03 0.03 0.059-State SO20.15 0.08 0.15 0.18 0.14NOX0.11 0.08 0.06 0.07 0.08per emissionreduction($/ton)per visibilityimprovement($million /dv)ICI13-State RegionSO2 2,992 1,776NOX 2,537 1,3279-State RegionSO2 2,275 2,825NOX 1,899 2,034ICI Workgroup3-State RegionSO2 2,731 1,618NOX 3,814 1,9939-State RegionSO2 2,743 3,397NOX 2,311 2,473Strategy/RegionAverage cost effectivenessvaluesTable 5.2-11. Estimated Visibility Impacts of ICI Control StrategiesEstimated visibility improvement in 2018 (deciviews)Table 5.2-12. Cost Effectiveness of ICIControl Strategies in Terms of VisibilityImprovementICI Workgroup52

### 53



## 5.3 Reciprocating Engines and Turbines

Internal combustion engines at industrial, commercial, and institutional facilities are

X 

### projected to account for about 22% of NO emissions from non-EGU stationary sources in 2018. 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

X 

### emissions from turbines by 68 to 80%, and low-NO burners can reduce turbine emissions 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% forturbines. 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.)Reciprocatingengines Turbines TotalReciprocatingengines Turbines TotalMichigan 44.1 11.4 55.5 41.4 11.5 52.9 229.3 23.1Minnesota 18.3 5.9 24.3 17.6 6.3 23.9 182.6 13.1Wisconsin 8.1 1.9 10.0 7.2 1.9 9.2 93.8 9.83-State Subtotal70.5 19.2 89.8 66.2 19.7 85.9 505.7 17.0Illinois 112.5 14.3 126.8 110.6 15.9 126.4 342.7 36.9Indiana 25.1 1.7 26.8 23.0 1.8 24.7 225.4 11.0Iowa 26.3 1.6 27.9 25.2 1.7 26.9 121.7 22.1Missouri 21.0 3.2 24.3 20.2 3.4 23.6 111.2 21.2North Dakota 8.7 1.3 10.0 8.3 1.4 9.7 36.1 26.9South Dakota 0.0 1.0 1.0 0.0 1.1 1.1 24.0 4.69-State Total264.1 42.5 306.6 253.6 44.9 298.4 1,366.921.8*Excludes reciprocating engines and turbines classified as EGUs.Table 5.3-1. Estimated Emissions from Reciprocating Engines and Turbines in Relation to TotalNon-EGU Emissions in 2018NOX emissions from stationaryinternal combustion sources in 2002(tons/day)*Projected NOX emissions fromstationary internal combustionsources in 2018 (tons/day)*Projected NOXemissions from allnon-EGU pointsources (tons/day)Stationary internalcombustion as afraction of all nonEGU point sourcesin 2018 (%)54Size 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

re g ion 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

re g ion 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

X 

### would be about $980/ton of NO emission reduction (in 2005 dollars). The cost-effectiveness at the 10 ton/year emission cutoff level (about 80 brake-horsepower) is estimated to be about $8,200/ton.

X 

### AirControlNET estimates that low-NO burner technology can be installed on emission

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 werecalculated using emission engine and turbine size distributions from the NEI. These costX 

### effectiveness values are based on the modification of engines and turbines to use low-NO 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

X 

### Low-NO combustion technologies are expected to be the most cost-effective methods 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 coveredAverage RangeControl of sources emitting over100 tons/year3-State regionReciprocating engines538 310 - 980Turbines754 750 - 750Total614 310 - 9809-State regionReciprocating engines506 240 - 980Turbines754 750 - 750Total535 240 - 980Control of sources emitting over10 tons/year3-State regionReciprocating engines 1,286 310 - 8,200Turbines800 750 - 1,600Total1,172 310 - 8,2009-State regionReciprocating engines 1,023 240 - 8,200Turbines819 750 - 1,600Total995 240 - 8,200Table 5.3-3. Estimated Cost Effectiveness ofControls for Internal Combustion SourcesCost effectiveness ($/ton ofNOX emission reduction)57

### 58 X 

### NO emission reductions from reciprocating engines and turbines would have beneficial environmental impacts by reducing acid deposition and nitrogen deposition to water bodies and

X 

### natural landscapes. Regional haze control strategies for NO 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

X 

### NO would result in reductions in background levels of ambient ozone. These reductions in

2.5 

### PM and ozone could improve the potential for urban areas in the Midwest to attain the NAAQS 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

X 

### Midwest region. Older equipment may not be amenable to low-NO combustion modifications. For these sources, the candidate emission reduction targets could be achieved with SCR;

X 

### however, costs would be up to 3.5 times the estimated cost of low-NO combustion 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)

59Strategy 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. 36DescriptionFraction of the overallNH3 emissionsinventory that can becontrolled using thisoptionEstimatedreduction efficiencyfor the affectedcategory (%)Potentialreduction inoverall inventory(%)Cost effectiveness($/ton)Vegetative buffers for houses and storage facilities5715 - 779 - 4431 - 160Vegetative buffers for entire farms1009 - 219 - 21naFeed adjustments for swine204 - 161 - 30 - 21000Reduce usage of nitrogen fertilizer5502potential savingsIncorporation of pig slurry by disc436 - 702 - 3600 - 1200Replace urea with lower emission fertilizer275 - 952400 - 500Incorporation of poultry manure by disc436 - 802 - 3600 - 1500Incorporation of beef cattle manure by disc436 - 701 - 32500 - 4000Incorporation of dairy slurry by disc127092700Incorporation of dry dairy manure by disc736 - 703 - 52700 - 5200Table 5.4-1. Estimated Cost Effectiveness of Control Measures for Agricultural Ammonia Emissions63

### 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

2 

### diesel fuel that would be required. We have also estimated the amount of additional CO which would be produced in the burning of this fuel (Table 5.4-2).DescriptionAdditional dieselrequirements (gal/MgNH3 reduced)Carbon dioxidegenerated (tons/ton NH3reduced)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 - 1000Table 5.4-2. Estimated Energy and Non-Air Environmental Impacts ofAgricultural Ammonia Emission Control Measures65

### 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

2.5 

### ambient levels of PM , with corresponding health benefits.

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 regionBoundaryWaters Voya-geurs Isle Royale Seney Average10% 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 0.1615% Ammonia reduction in the 3-State region 0.14 0.17 0.15 0.14 0.1515% Ammonia reduction in the 9-State region 0.23 0.27 0.23 0.26 0.25Strategy and region10% 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 - 2,700Average costeffectiveness peremission reduction($/ton)8 - 75018 - 1,5008 - 75018 - 1,500Average costeffectiveness pervisibility improvement($million/dV)31 - 2,70031 - 2,70031 - 2,700Table 5.4-3. Estimated Visibility Impacts of Agricultural Ammonia EmissionControl MeasuresTable 5.4-4. Cost Effectiveness of Agricultural Ammonia Emission ControlMeasures in Terms of Visibility ImprovementEstimated visibility improvement in 2018 (deciviews)67

### 68



## 5.5 Mobile Sources

X 

### Despite projected NO reductions from on-the-books Federal and state-wide programs 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:

X 

### " Low-NO Reflash

" 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

X 

### an alternative fuel (see Section 5.5.6). Studies have shown that biodiesel does not reduce NO 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

X 

### This report provides example reduction strategies and discussion for Low-NO Reflash, MCDI 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

X 

### Low-NO Reflash affects 1993-1999 model year Class 7 and 8 heavy-duty diesel vehicles (HDDV) with model year 1993-1998 engines manufactured by Caterpillar, Cummins, Detroit Diesel, Mack/Renault, Volvo, and International. These seven corporations implemented

X 

### 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-NO 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.

X 

### NO emissions were obtained from the 2012 and 2018 Base K Strategy 1 inventory for the 3-state and 9-state regions. Emissions data for 2018 were not available for Missouri, Iowa, a 

### North Dakota, or South Dakota.

X 

### Cost-effectiveness and emission reductions for low-NO reflash, MCDI, and anti-idling 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

X 

### 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 the amount of funding for MCDI projects would be distributed in a similar fashion to current

X 

### projects. This assumption resulted in a high cost-effectiveness for NO reductions, especially for the 3-state region, because MCDI projects focused primarily on PM emissions. Specifically, the

X 

### ENVIRON report did not identify any NO reductions for programs in Wisconsin or Minnesota, 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

X 

### achieved by anti-idling policies were NO reductions, resulting in a cost-effectiveness of $1,400- $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 Potentialof Mobile Source Controls for the 3-State and 9-State Regions2012 2018NoteLow-NOX Reflash On-Road All MDDV and HDDVClass 8 Vehicles23%25% 5.8% 5.8%$241MCDIOn-Road Class 8 Vehicles 2% in 2012, 5% in 201836% 0.7% 1.8% $10,697 aNon-Road Diesels2% in 2012, 5% in 201871% 1.4% 3.6% $10,697M/A/R Switching and Line-HaulLocomotives2% in 2012, 5% in 201842% 0.8% 2.1% $10,697Anti-IdlingM/A/RSwitchingLocomotives 9% in 2012, 18% in 20185% 0.4% 0.9% $1,400 aLine-Haul Locomotives 2% in 2012, 4% in 201837% 0.7% 1.5% $1,400On-Road All MDDV and HDDVClass 8 Vehicles2.6%36% 0.9% 0.9% (430) - 1,700Non-road Non-road diesel engines1.5%71% 1.1% 1.1% $3,577 bCetane Additive ProgramNon-road All diesel engines1.0%2.9% 2.9% $4,119 cOn-Road MY2002 and earlierMDDV and HDDV2.9%1.6% 1.5% $4,119 cLow-NOX Reflash On-Road All MDDV and HDDVClass 8 Vehicles23%25% 5.8% 5.8%$241MCDIOn-Road Class 8 Vehicles 2% in 2012, 5% in 201836% 0.7% 1.8% $2,408Non-Road Diesels2% in 2012, 5% in 201875% 1.5% 3.7% $2,408M/A/R Switching and Line-HaulLocomotives2% in 2012, 5% in 2018 56% 1.1% 2.8% $2,408Anti-IdlingM/A/RSwitchingLocomotives 9% in 2012, 18% in 20182% 0.2% 0.4% $1,400 aLine-Haul Locomotives 2% in 2012, 4% in 201824% 0.5% 1.0% $1,400bOn-Road All MDDV and HDDVClass 8 Vehicles2.6% 36% 0.9% 0.9% (430) - 1,700Non-road Non-road diesel engines 1.5% 75% 1.1% 1.1% $3,577Cetane Additive ProgramNon-road All diesel engines1.0%2.9% 2.9% $4,119 cOn-Road MY2002 and earlierMDDV and HDDV2.9%1.6% 1.4% $4,119 c[b] Assumes equipment life of 20 years at an interest rate of 7%Potential fractionof overallinventory affected(%)Potential reduction forinventory (%)Cost effectiveness($/ton)Strategy Inventory Affected CategoryEstimated reductionefficiency for the affectedcategory (%)3-State Region9-State Region[c] Cost-effectiveness taken from Davis, W. T., and T. L. Miller. “Estimates of potential emissions reductions for the Nashville ozone early action compact area, FinalReport,” 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 measures71

### 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

X 

### programs, while a negligible disbenefit can be seen from installation of the low-NO reflash 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

X 

### PM, but may have some negative impacts on NO . Although several studies have shown an

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

X 

### Approaches have been studied that would mitigate NO emissions from biodiesel. These approaches include lowering the base fuel aromatic content from 31.9% to 7.5%, using kerosene

X 

### as a base fuel in a B40 blend, and using cetane enhancers. All approaches result in a “NO - neutral” biofuel, with cetane enhancers proving the most cost-effective at an incremental cost of

X 

### $0.05 - $0.16 per gallon for a 4% reduction in NO . 40

X 

### 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 NO 43

X 

### disbenefit in vehicles model year 1988-1995. However, the effect of ethanol blends on NO emissions in vehicles newer than 1996 is uncertain, as the EPA Complex Model shows a slight

X 

### decrease in NO emissions in those vehicles.Strategy Affected Category Fuel ImpactsOther Air Quality ImpactsEnvironmental ImpactsLow-NOX ReflashOn-Road<1% fuel economypenalty7% increase in PM emissionsper vehicle.NoneMCDIOn-Road Anti-idling strategies fundedby MCDI result in a fuelsavings. (HDDV Idlinggenerally uses 1 gallon/hr offuel.)Reductions in GHG, PM, VOC, and CO.Biodiesel strategies have a NOX emission penaltyof up to 2% and a GHG reduction of 78% overpetroleum diesel.Anti-idling strategies have no quantifiableenvironmental impacts. Biodieselproductions results in a 79% reduction inwastewater and a 96% reduction in solidwaste overpetroleum dieselproduction.Anti-IdlingM/A/ROn-RoadNon-roadCetane AdditiveProgramNon-roadOn-RoadTable 5.5-2. Estimated Energy and Non-Air Environmental Impacts of Mobile Source Control StrategiesFuel savingsReductions in GHG, PM, VOC, and CO. EPAcites a reduction of 22 pounds of GHG for everygallon of diesel fuel saved byanti-idlingpolicies.Improved fuel economy PM2.5 emissions benefit74BoundaryWatersVoyageursIsleRoyale Seney AverageLow-NOX Reflash All MDDV and HDDV Class8 VehiclesOn-Road 5.8 0.006 0.007 0.009 0.006 0.007MCDI Class 8 Diesel Vehicles On-Road1.8 0.002 0.002 0.003 0.002 0.002Diesel EnginesNon-road 3.6 0.009 0.012 0.008 0.008 0.009Switching and Line-HaulLocomotivesM/A/R2.1 0.004 0.005 0.003 0.003 0.004Anti-IdlingSwitchingLocomotivesM/A/R1.0 0.002 0.002 0.002 0.001 0.002Line-Haul Locomotives1.7 0.003 0.004 0.003 0.002 0.003All MDDV and HDDV Class8 VehiclesOn-Road 0.9 0.001 0.001 0.001 0.001 0.001Non-road diesel enginesNon-road 1.1 0.003 0.004 0.003 0.003 0.003Cetane AdditiveProgramAll diesel engines Non-road 2.9 0.007 0.010 0.007 0.007 0.008MY2002 and earlier MDDVand HDDVOn-Road 1.4 0.002 0.002 0.002 0.001 0.002Low-NOX Reflash All MDDV and HDDV Class8 VehiclesOn-Road 5.8 0.008 0.009 0.012 0.012 0.010MCDIClass 8 VehiclesOn-Road0.7 0.001 0.001 0.001 0.002 0.001Diesel EnginesNon-road 3.6 0.010 0.013 0.009 0.009 0.010Switching and Line-HaulLocomotivesM/A/R2.1 0.003 0.004 0.003 0.003 0.003Anti-IdlingSwitchingLocomotivesM/A/R0.2 0.000 0.000 0.000 0.000 0.000Line-Haul Locomotives0.5 0.001 0.001 0.001 0.001 0.001All MDDV and HDDV Class8 VehiclesOn-Road 0.9 0.001 0.001 0.002 0.002 0.002Non-road diesel enginesNon-road 1.1 0.003 0.004 0.003 0.003 0.003Cetane AdditiveProgramAll diesel engines Non-road 2.9 0.004 0.005 0.006 0.006 0.005MY2002 and earlier MDDVand HDDVOn-Road 1.6 0.002 0.003 0.003 0.003 0.0033-State Region9-State RegionTable 5.5-3. Estimated Visibility Impacts of Mobile Sources Control StrategiesEstimated visibility improvements (deciviews)Emissionreduction ininventorysector (%)InventorysectorEquipment coveredControl strategy75StrategyMobile Sources AffectedInventoryCost effectivenessper visibilityimprovement($million/deciview)Low-NOX ReflashAll MDDV and HDDV Class 8 Vehicles On-Road516MCDI Class 8 Diesel Vehicles On-Road22,947Diesel EnginesNon-Road5,032Switching and Line-Haul LocomotivesM/A/R5,033Anti-Idling SwitchingLocomotivesM/A/R659Line-Haul Locomotives659All MDDV and HDDV Class 8 Vehicles On-Road(920) - 3,600Non-road diesel enginesNon-Road1,683Cetane Additive Program All diesel enginesNon-Road1,938MY2002 and earlier MDDV and HDDV On-Road8,836Low-NOX ReflashAll MDDV and HDDV Class 8 Vehicles On-Road616MCDI Class 8 Vehicles On-Road6,171Diesel EnginesNon-Road3,952Switching and Line-Haul LocomotivesM/A/R3,954Anti-Idling SwitchingLocomotivesM/A/R2,299Line-Haul LocomotivesM/A/R2,299All MDDV and HDDV Class 8 Vehicles On-Road(1,100) - 4,400Non-road diesel enginesNon-Road5,872Cetane Additive Program All diesel enginesNon-Road10,552MY2002 and earlier MDDV and HDDV On-Road10,5543-State Region9-State RegionTable 5.5-4. Cost Effectiveness of Mobile Source Control Strategies in Termsof Visibility Improvement76

### 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

X 

### as fuel. Table 5.6-1 lists the various control options for NO , and whether those options can be 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

2 

### had yet been reported. There was limited information on SO controls for cement kilns, particularly long wet kilns. Process modification and replacement of the kiln with a dry process

2 

### kiln are the most feasible options for SO control. SNCR is another control technology available 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. 50,52CemSTAR is a process that introduces steel slag into the rotary kiln, lowering the temperature necessary to a

X 2 produce clinker, thus reducing both NO and SO emissions.



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

Control Technology Percent Efficiency Applicable at Holcim

plant

X NO

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

2 SO

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

X 

### per hour). Table 5.6-2 shows the cost effectiveness figures for NO control at the Holcim facility

2 

### using the Ash Grove cost figures. Due to the limited amount of information available for SO 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

X clinker process (such as shale or clay). The greatest amount of NO reductions for wet kilns can be achieved by
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 X 2



### Table 5.6-2. Cost Effectiveness of NO and SO Control

Technologies for Holcim, Inc. Facility

Control Technology Percent Efficiency Emissions

Reduction (tons/year) Cost

Effectiveness ($/ton reduced)

X NO

Conversion to Dry Process

Kiln 65 946 9848

LoTOx 85 1237 1399

TM

Process Modification 9-70 131-1019 NA a

2 SO

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 LoTOx TM 

### 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

X 2 

### or EGU2 NO and SO costs for the 3- and 9-state regions (Table 5.1-11). LoTox, on the other 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.StrategyBoundaryWaters Voyageurs Isle Royale Seney AverageBoundaryWaters Voyageurs Isle Royale Seney AverageCostEffectiveness($1000-mi/ton)Conversion to DryProcess Kiln (NOx)2.56 2.28 3.01 4.62 3.12 1.67 1.48 1.96 3.00 2.03 4594LoTOx2.56 2.28 3.01 4.623.12 2.18 1.94 2.56 3.93 2.65653Process Modification2.56 2.28 3.01 4.62 3.12 1.01 0.901 1.19 1.82 1.23NAConversion to DryProcess Kiln (SO2)13 11 15 23 15 8 7 10 15 9.93938Reductions in the summations of emission-to-distanceratios (Q/d; tons/yr-mi)*Table 5.6-3. Estimated Visibility Impacts of Control Strategies for Holcim Cement KilnsBaseline summations of emission-to-distance ratios (Q/d;tons/yr-mi)81World Bank Group. 1998. “Glass Manufacturing.” Pollution Prevention and Abatement Handbook



### . a



### 82 5.6.2 Glass manufacturing plant

X 2 

### The majority of NO and SO emissions come from the melting furnace in glass plants 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.

X 

### The available NO control technologies available at glass manufacturing plants are listed
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

2 

### already installed a scrubber system so SO is not analyzed. Thus to bring the one furnace at the plant into compliance it will take a maximum of 3 years.

X 

### Table 5.6-4. NO Control Technologies 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 X



### Table 5.6-5. Costs and Cost Effectiveness for NO Control Technologies

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.StrategyBoundaryWaters Voyageurs Isle Royale Seney AverageBoundaryWaters Voyageurs Isle Royale Seney AverageCostEffectiveness($1000-mi/ton)LNB6.44 5.51 5.33 4.45 5.43 2.58 2.20 2.13 1.78 2.17 486Oxy-firing 6.44 5.51 5.33 4.45 5.43 5.48 4.68 4.53 3.78 4.62 1,401Electric Boost 6.44 5.51 5.33 4.45 5.43 0.644 0.551 0.533 0.445 0.543 1,274SCR6.44 5.51 5.33 4.45 5.43 4.83 4.13 3.99 3.33 4.07 505SNCR6.44 5.51 5.33 4.45 5.43 2.58 2.20 2.13 1.78 2.17 528Reductions in the summations of emission-to-distanceratios (Q/d; tons/yr-mi)*Table 5.6-7. Estimated Visibility Impacts of Control Strategies for Cardinal FG Glass FurnacesBaseline 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.

2 

### These kilns are fueled by coal, oil, and/or natural gas. The primary source of SO emissions is the 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

X NO

Mid-kiln

firing 30 Yes Yes

LNB 30 Yes Yes

SNCR 50 Yes Yes

SCR 80 Yes Yes

2 SO

FGD 90 Yes Yes

2 

### The only SO control technology for which information was available for lime manufacturing plants is flue gas desulfurization (FGD).

5.6.3.1 Factor 1 - Costs

AirControlNET documentation provided cost equations for the capital, and operations

2 X 

### and maintenance costs for SO controls. Cost equations were not available for NO controls, 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.FacilityControlTechnologyPercentEfficiencyEmissionsReduction(tons)Total AnnualizedCosts ($M2005)Cost Effectiveness($2005/ton)CLM Corp.Mid-kilnfiring30 84.458688LNB30 84.471837SCR50 1417105,037SNCR80 2252721,211FGD90 1276414,828RockwellMid-kilnfiring30 4.142.85688LNB30 4.143.47837SCR50 6.9034.85,037SNCR80 11.0313.41,211FGD90 15219.4128Table 5.6-9. Costs and Cost Effectiveness for NOx and SO2Control Technologies at Rockwell and CLM Corporation LimeManufacturing Facilities** Cost effectiveness numbers were taken from AirControlNET documentation and may notreflect 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).FacilityStrategyBoundaryWaters Voyageurs Isle Royale Seney AverageBoundaryWaters Voyageurs Isle Royale Seney AverageCostEffectiveness($1000-mi/ton)CLM Corporation Mid-kiln firing 3.21 2.34 1.65 0.98 2.04 0.964 0.702 0.494 0.293 0.61394.6LNB3.21 2.34 1.65 0.98 2.04 0.964 0.702 0.494 0.293 0.613116SCR3.22 2.34 1.65 0.98 2.04 2.57 1.87 1.32 0.781 1.64434SNCR3.21 2.34 1.65 0.98 2.05 1.61 1.17 0.824 0.488 1.021,185FGD1.10 0.800 0.563 0.333 0.698 0.988 0.720 0.507 0.300 0.6291,020Rockwell Mid-kiln firing 0.189 0.157 0.229 0.356 0.233 0.0566 0.047 0.069 0.107 0.07040.9LNB0.189 0.157 0.229 0.356 0.233 0.0944 0.078 0.114 0.178 0.11629.8SCR0.189 0.157 0.229 0.356 0.233 1.69 1.40 2.05 3.19 2.0816.7SNCR0.189 0.157 0.229 0.356 0.233 0.151 0.125 0.183 0.285 0.18672.0FGD1.81 1.50 2.19 3.41 2.23 0.0566 0.047 0.069 0.107 0.070278Reductions in the summations of emission-to-distanceratios (Q/d; tons/yr-mi)Table 5.6-11. Estimated Visibility Impacts of Control Strategies for Rockwell and CLM Corporation Lime KilnsBaseline 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

X NO

LNB 50 Yes

SNCR 60 Yes

SCR 75 Yes

LNB+FGR 55 Yes

a

ULNB 75 Yes

2 SO

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

2 X 

### and maintenance costs for SO controls. Cost equations were not available for NO controls, although AirControlNET did provide default cost effectiveness values. Tables 5.6-13 and 5.6-14 present the results.

### 92 X 

### Table 5.6-13. Cost Effectiveness of NO Control 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).StrategyBoundaryWaters Voyageurs Isle Royale Seney AverageBoundaryWaters Voyageurs Isle Royale Seney AverageCostEffectiveness($1000-mi/ton)LNB3.51 2.59 1.84 1.10 2.26 1.75 1.30 0.921 0.552 1.13243SCR3.51 2.59 1.84 1.10 2.26 2.10 1.56 1.10 0.662 1.36 1,661SNCR 3.51 2.59 1.84 1.10 2.26 2.63 1.95 1.38 0.828 1.70252LNB+FGR 3.51 2.59 1.84 1.10 2.26 1.93 1.43 1.01 0.607 1.24352ULNB 3.51 2.59 1.84 1.10 2.26 2.63 1.95 1.38 0.828 1.70166FGD6.57 4.86 3.45 2.07 4.24 5.92 4.38 3.11 1.86 3.82152Reductions in the summations of emission-to-distanceratios (Q/d; tons/yr-mi)*Table 5.6-16. Estimated Visibility Impacts of Control Strategies for Murphy Oil RefineriesBaseline 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 ne w EGU projections (i.e., 3.0 version of IPM). The new EGU projections reflect lower 2018 SO 2 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 proj ections. 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 subsectionanalyzes 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 individualfacilities 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 categoryControl strategyDescriptionEGUEGU1SO2 limited to 0.15 lb/MM-BTUNOX limited to 0.10 lb/MM-BTUEGU2SO2 limited to 0.10 lb/MM-BTUNOX limited to 0.07 lb/MM-BTUICI boilers ICI1 40% SO2 reduction from 2018 baseline emissions60% NOX reduction from 2018 baseline emissionsICI Workgroup77% SO2 reduction from 2018 baseline emissions70% NOX reduction from 2018 baseline emissionsReciprocating engines andturbinesReciprocating engines emitting100 tons/year or more89% NOX reduction from 2018 baseline emissionsTurbines emitting 100 tons/year ormore84% NOX reduction from 2018 baseline emissionsReciprocating engines emitting 10tons/year or more89% NOX reduction from 2018 baseline emissionsTurbines emitting 10 tons/year ormore84% NOX reduction from 2018 baseline emissionsAgricultural sourcesMobile sources Low-NOX Reflash Install low-NOX software to counteract advancedcomputer controls installed on MY 1993-1998 HDDVthat increase NOX emissionsMidwest Clean Diesel Initiative(MCDI)A collaborative organization between federal, state,and local agencies funding projects that will reducediesel emissions through operational changes,technological improvements, and cleaner fuelsAnti-Idling Strategies to reduce NOX emissions that take the formof enforced shutdown policies, auxiliary power units(APUs), automatic engine shut-off technology, andtruck stopelectrification(TSE).Cetane Additive Program Introduces additives to diesel fuel at the distributionsource to increase the cetane number to approximately50.Cement Plants Process Modification Fuel switching, CEMStar (a process that introducessteel slag into the rotary kiln, lowering thetemperature necessarytoproduce clinker)Conversion to drykilnLoToxTMLower temperature oxidation technologyTable 6-1. Summary of Candidate Future Control Measures Evaluated for RegionalHazeAchieve a 10-15% NH3 reduction through the use of a variety of best management98Glass Manufacturing LNBLow-NOX BurnerOxy-firingProcess that uses oxygen and CO2 to combust withfuel instead of airElectric boostElectricity currents are added to the gas to aid incombustion in the furnaceSCRSelective catalytic reductionSNCRSelective non-catalytic reductionLime Manufacturing Mid-kiln firingA form of staged combustion of fuels in which aspecially designed fuel injection system introduces asecond fuel source at a midpoint in the kiln.LNB Low-NOX BurnerSNCRSelective non-catalytic reductionSCRSelective catalytic reductionFGDFlue Gas DesulfurizationOil RefineryLNBLow-NOX BurnerSNCRSelective non-catalytic reductionSCRSelective catalytic reductionLNB+FGRLow-NOX Burner with Flue Gas RecirculationULNBUltra Low-NOX BurnerFGDFlue Gas DesulfurizationTable 6-1. Summary of Candidate Future Control Measures Evaluated for RegionalHaze (continued)99Emission categor y 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 thos e 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 SO 2 

### NO X


### 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 NO X 

### . 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 onthe specific program. Some programs, such as anti-idling measures, programs are very costeffective for reducing NO X 

### 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 NO X 

### . In fact, the cetane additive program and the Midwest Control Diesel Initiative are focused on reducing primary emissions of diesel particulate matter, and reduce NO X 

### emissions as a collateral benefit. Therefore, the costs of these programs should not be judged on the basis of
cost-effectiveness values for NO X 

### alone.

Analyses of selected individual analyses in the lime manufacturing facilities, cement, petroleum refining, and glass manufacturing industr ies 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

2.5 

### benefits stem from the reduced ambient levels of PM and ozone which would result from the

2 X 

### control of SO and NO .



## 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.

2 

### 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 2 

### most SO control systems, either in the reaction of SO with limestone or in the production of

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.

2 X 

### The SO , NO , and ammonia controls would have beneficial environmental impacts by 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

X 

### NO would result in reductions in background levels of ambient ozone. These reductions in

2.5 

### PM and ozone will reduce levels of 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).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 strate g ies 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

103EmissioncategoryControl strategyRegion PollutantEmissionreduction(1000tons/year)Additionalelectricityrequirements(GW-hrs /year)Additionaldiesel fuelrequirements(1000 gal/year)Steamrequirements (1000tons/yr)Solid wasteproduced(1000tons/year)Wastewaterproduced(1000gallons/year)AdditionalCO2 emitted(1000tons/year)EGUEGU13-State SO2466 706- 510- 192 1,059NOX71 40- 17-0 429-State SO2 1,279 2,649 - 3,462 - 1,128 3,651NOX 224 110 - 46 - 0 115EGU2 3-State SO2 532 1,106 - 1,722 - 237 1,523NOX 106 174 - 73 - 0 1819-State SO2 1,455 3,504 - 5,439 - 1,919 4,666NOX 328 608 - 255 - 0 636ICI boilers ICI1 3-State SO2 33 13 - - 120 - 35NOX 22 37 - 5 0 - 389-State SO2 105 37 - - 346 - 102NOX 73 214 - 12 1 - 217ICI Workgroup 3-State SO2 53 20 - - 186 - 55NOX 29 53 - 6 1 - 559-State SO2 169 58 - - 537 - 158NOX 85 235 - 14 1 - 239Reciprocatingengines andturbinesReciprocating engines emitting100 tons/year or more3-State NOX -9-State NOX -Turbines emitting 100tons/year or more3-State NOX -9-State NOX -Reciprocating engines emitting10 tons/year or more3-State NOX -9-State NOX -Turbines emitting 10 tons/yearor more3-State NOX -9-State NOX -Not significant, the most cost effective control technology consists of low-NOxcombustion technologies.Not significant, the most cost effective control technology consists of low-NOxcombustion technologies.Not significant, the most cost effective control technology consists of low-NOxcombustion technologies.Not significant, the most cost effective control technology consists of low-NOxcombustion technologies.Not significant, the most cost effective control technology consists of low-NOxcombustion technologies.Table 6-3.1. Estimated Energy and Non-Air Environmental Impacts of Potential Control MeasuresNot significant, the most cost effective control technology consists of low-NOxcombustion technologies.Not significant, the most cost effective control technology consists of low-NOxcombustion technologies.Not significant, the most cost effective control technology consists of low-NOxcombustion technologies.104Agriculturalsources10% reduction 3-State NH3 27 - 6 - 13 - - - 55 - 1189-State NH391 - 19 - 42 - - - 183 - 39215% reduction 3-StateNH341- 9 - 19 --- 82 - 1779-State NH3137- 29 - 63 --- 274 - 589Mobile sources Low-NOX Reflash3-StateNOX-9-State NOX-MCDI 3-StateNOX-9-State NOX-Anti-Idling3-StateNOX-9-State NOX-Cetane Additive Program 3-StateNOX-9-State NOX-No other environmental impacts.No other environmental impactsAnti-idling strategies have no quantifiable environmental impacts. Biodieselproductions results in a 79% reduction in wastewater and a 96% reduction in solid wasteNo 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 Measures (continued)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

2 X 

### a result of SO and NO emission reductions. The EPA Environmental Benefits 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.

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 illustratesthe 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

X 

### measure in terms of cost unit of per visibility improvement is the control of NO emissions from

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

X 

### of potential cost effectiveness values for NO reductions. The visibility improvements calculated 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

2 

### benefits analysis). The EGU1 limits for SO in the 3-state region could be sufficient to reach the 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 measuresalso 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 Sene y Averag e 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

109Emission categor y Control strategy Region Pollutant Average estimatedvisibility 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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# 7. References

### 113

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### 114

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27. ICI Boiler Summary Spreadsheet.xls. Personal communication with Mike Koerber. Information obtained from: IL ICI SO2 NOx 2002.xls, January 29, 2007 e-mail from Andrew Russo (Illinois); MediumBLRSO2.xls and LargeBLRSO2.xls, January 18, 2007 e-mail from Ken Ritter (Indiana); ICI Boiler Summary ladco so2. xls, January 23, 2007 e-mail from Teresa Walker (Michigan); ICI Boiler Summary (2)-region.xls, February 5, 2007 e-mail from Farrokh Ghorreshi (Wisconsin)

28. Emissions by State and SCC with Growth and Control Information, Non-EGU Point Sources, 2018. Available: http://www.ladco.org/tech/emis/basek/BaseK_Reports.htm

2 

### 29. Khan, S. Methodology, Assumptions, and References - Preliminary SO Controls Cost Estimates for Industrial Boilers. EPA-HQ-OAR-2003-0053-166, U.S. Environmental Protection Agency. 2003.

X 

### 30. Khan, S. Methodology, Assumptions, and References - Preliminary NO Controls Cost Estimates for Industrial Boilers. EPA-HQ-OAR-2003-0053-170, U.S. Environmental Protection Agency. 2003.

31. Database of ICI Boilers in the Midwest RPO. Compiled for Interim White Paper -
Midwest RPO Candidate Control Measures . Source Category: Industrial/ Commercial/ Institutional Boilers. Developed for the Lake Michigan Air Directors Consortium, March 6, 2006. Database dated 10/18/2005.

32. Edgerton, Stephen, Judy Lee-Greco, and Stephanie Walsh. Stationary Reciprocating

X 

### Internal Combustion Engines – Updated Information on NO Emissions and Control Techniques. Prepared for the U.S. Environmental Protection Agency, Research Triangle Park, NC, by EC/R Incorporated, Chapel Hill, NC. 2002.

33. AirControlNET.

34. Iowa State University – University Extension. 2004. Practices to Reduce Ammonia Emissions from Livestock Operations , PM 1971a.

35. Malone, George, Gary VanWicklen, Stephen Collier and David Hansen. 2006. “Efficacy of Vegetative Environmental Buffers to Capture Emissions from Tunnel Ventilated Poultry Houses.” Workshop on Agricultural Air Quality: State of the Science , Potomac, Maryland, June 5–8. http://esa.org/AirWorkshop/postworkshopActivities.php

36. Colletti, Joe, Steven Hoff, Janette Thompson and John Tyndall. 2006. “Vegetative Environmental Buffers to Mitigate Odor and Aerosol Pollutants Emitted from Poultry
Production Sites.” Workshop on Agricultural Air Quality: State of the Science , Potomac,

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37. Powers, W., S. Bastyr, R. Angel, T. Applegate, and B. Kerr. 2006. “Effects of Reduced
Crude Protein on Gaseous Emissions and Swine Performance.” Workshop on Agricultural Air Quality: State of the Science , Potomac, Maryland, June 5–8. http://esa.org/AirWorkshop/postworkshopActivities.php

38. Webb, J, M.Ryan, S.G.Anthony,A.Brewer, J.Lawsc,M.F.Aller,T.H.Misselbrook. 2006. “Cost-effective means of reducing ammonia emissions from UK agriculture using the
NARSES model.” Atmospheric Environment 40: 7222–7233.

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X 

### 40. McCormick R.L. et al. NO Solutions for Biodiesel. Prepared by the Colorado Institute for Fuels and Engine Research for the National Renewable Energy Laboratory. NREL/SR-510-31465, February 2003.

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Area. Prepared for the Southeast Michigan Council of Governments, the Alliance of Automobile Manufacturers, and the American Petroleum Institute. February 23, 2005.

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# 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-3EGU 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-1State 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-22002 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 SO 2 

# and NO X 

# 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-19Appendix B-1. Control Strategies for Mobile SourcesTechnologyProcesses CoveredEstimated NOX ControlEfficiency Notes Reference1993 to 1998 MHDDV24% reduction in tailpipeemissionsa1, 21993 to 1998 HHDDV24% reduction in tailpipeemissionsa1, 21995 and older enhanced IM tailpipetest8-9% annual inventoryreductionb, c31996 and newer OBDII equippedgasoline vehicles0.1 gram/mile reduction forpost-repair vehiclesb 41997 and newer OBDII equipped lightdutydiesel vehicles0.6% reduction in tailpipeemissionsb 52007 and newer heavy-duty dieseltrucks(on the books)6Smoking vehicles (identification,repair, and/or replace)up to 53% decrease in NOXemissions for all vehiclesparticipatingin theprogramaa 1, 21Use 7.0 RVP fuel in urban areas; e.g., Detroit area LDGV26Fuel Switching: Biodiesel B100 HDDV +10% pre-1998, +30% 98-04increase in tailpipe emissionsd 7Fuel Switching: Biodiesel B20 HDDV +2% pre-1998, +4% 98-04increase in tailpipe emissionse 7Low NOX Calibration/Reflashing. Adopt regulations similar to the CARBLow NOx Software Upgrade program with a set phase in schedule that wouldrequire all low NOx rebuild engines to have low NOx rebuild kit installed by2009.Emissions Inspections Program. Implement a State emissions inspectionprogram 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 natural gas.(*Recommendation may be restricted to fuels already available in the Petroleum Administration for Defense District.)B-1Appendix B-1. Control Strategies for Mobile SourcesTechnologyProcesses CoveredEstimated NOX ControlEfficiency Notes ReferenceFuel Switching: Biodiesel B20Bulldozer, Motor Graderunknownf8Fuel Switching: Biodiesel B30Bulldozer, Motor Graderunknowng8Fuel Switching: Biodiesel B20Locomotive (line haul or switching) +5-6% increase in tailpipeemissionsh 9Fuel Switching: Biodiesel B20Marine Port applicationsunknowni10Locomotive (line haul or switching) 1-2% reduction in tailpipeemissionsh, j 9Harbor craft15% inventoryreductionk18Large deepdraft marine vessels15% inventoryreductionk18Harbor craft(ferries, tugs)15% inventoryreductionk18Large deepdraft marine vessels15% inventoryreductionk18Increase use of E10LDGV+5% increase in tailpipeemissionsl 11, 12Fuel Switching: Convert public fleets to Flex Fuel Vehicles fueled with E85. LDGVtailpipe control efficiencyunavailablel 12Fuel Switching: LNG or CNGLDGV60% reduction in tailpipeemissions13Fuel Switching: LNGLocomotive (line haul or switching) tailpipe control efficiencyunavailable14Fuel Switching: LNG or CNGMDGV, HDGV50% reduction in tailpipeemissions131993 to 1998 MHDDVunknownm,n1Switching locomotives50% reduction in tailpipeemissionso 1Line-haul locomotives 75% reduction in tailpipeemissionso 1[continued]Use lower sulfur fuel: CARB Diesel*Use lower sulfur fuel: Highway or ULSD*Anti-Idling. Reduce idling emissions from heavy-duty diesel trucks andlocomotives using truck stop electrification and locomotive anti-idlingtechnology.B-2Appendix B-1. Control Strategies for Mobile SourcesTechnologyProcesses CoveredEstimated NOX ControlEfficiency Notes ReferenceUpgrade to 1990 EngineMY 1989 and earlier HDDV 43% reductionp1MY 1989 and earlier HDDV 63% reductionp1MY 1990 HDDV33% reductionp1MY 1991-1997 HDDV20% reductionp1MY 1989 and earlier HDDV 78% reductionp1MY 1990 HDDV66% reductionp1MY 1991-1997 HDDV52% reductionp1MY 1998-2001 HDDV95% reductionp1MY 2002-2006 HDDV92% reductionp1Upgrade construction and agricultural equipment to Tier 2, 3, or 4Excavators, Rubber Tire Loaders,Crawler Tractors/Dozers,Tractors/Loaders/Backhoes, OffHighway Trucks, Agricultural Tractors,CombinesDependent on model year andhorsepower. See Reference11 for engine standardschematic.1, 15Fleet turnover to 2007 and newer engines(On the books)HDDVunknown[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 EngineB-3Appendix B-1. Control Strategies for Mobile SourcesTechnologyProcesses CoveredEstimated NOX ControlEfficiency Notes ReferenceMYpre-1989 through 2006 HDDV upto 80% reduction1, 16Excavators, Rubber Tire Loaders,Crawler Tractors/Dozers,Tractors/Loaders/Backhoes, OffHighwayTrucksup to 80% reduction1, 16Locomotive(line haul or switching)90% reduction16Agricultural Tractors, Combines upto 80% reductionq1, 16Lean NOX Catalyst(LNC)combined with Diesel Particulate Filter(DPF)MYpre-1989 through 2006 HDDV 15-25% reductionr1, 16Excavators, Rubber Tire Loaders,Crawler Tractors/Dozers,Tractors/Loaders/Backhoes, OffHighwayTrucks15-25% reduction1, 17Agricultural Tractors, Combines 15-25% reduction1, 16Excavators, Rubber Tire Loaders,Crawler Tractors/Dozers,Tractors/Loaders/Backhoes, OffHighwayTrucksup to 50% reductions 1, 16Agricultural Tractors, Combines upto 50% reductions 1, 16Excavators, Rubber Tire Loaders,Crawler Tractors/Dozers,Tractors/Loaders/Backhoes, OffHighwayTrucksup to 80% reductiont 1, 16Agricultural Tractors, Combines upto 80% reductiont 1, 16Excavators, Rubber Tire Loaders,Crawler Tractors/Dozers,Tractors/Loaders/Backhoes, OffHighway Trucksup to 80% reductionu 1, 16Agricultural Tractors, Combines upto 80% reductionu 1, 16[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 vehicles and off-roadconstruction, cargo-handling, and marine equipment.B-4Appendix B-2. Control Strategies for EGUsTechnologyProcesses CoveredEfficiency of ControlNotes ReferenceBaseline and On-the-books regional programsBaseline 2002: (MRPO average SO2 is 1.16 lbs/mmBtu, NOx is0.43 lbs/mmBtu): NSPS; PSD/NSR; State RACT Rules; Title IVSO2 ProgramEGUs MRPO average SO2 is 1.16lbs/mmBtu, NOx is 0.43 lbs/mmBtubb 192009 On-the-Books measures: CAIREGUsEPA CAIR levels are estimated at0.13 lbs/mmBtu NOX and 0.26lbs/mmBtu SO2 in 2015.bb 19, 222009 On-the-Books measures: CAIR -- Michigan ImpactsEGUsEPA estimates a 10% reduction inSO2 and a 29% reduction in NOXfrom 2003 levels.bb232009 On-the-Books measures: CAIR -- Minnesota ImpactsEGUsEPA estimates a 36% reduction inSO2 and a 59% reduction in NOXfrom 2003 levels.bb242009 On-the-Books measures: CAIR -- Wisconsin ImpactsEGUsEPA estimates a 32% reduction inSO2 and a 61% reduction in NOXfrom 2003 levels.bb25Additional regionalprogramsAdopt Emission Caps Based on “Retrofit SO2 BACT Level” of0.15 lbs/mmBtu by 2013 (with Interim Cap Based on 0.36lbs/mmBtu in 2009)EGUs Additional 0.11 lbs/mmBtu reductionin SO2 from original CAIR emissionscapv 19Adopt Emission Caps Based on “Retrofit NOx BACT Level” of0.10 lbs/mmBtu by 2013 (with Interim Cap Based on 0.15lbs/mmBtu in 2009)EGUsAdditional 0.03 lbs/mmBtu reductionin NOX from original CAIRemissions cap19Adopt Emission Caps Based on “SO2 BACT Level for NewPlants” of 0.10 lbs/mmBtu by 2013 (with Interim Cap Based on0.24 lbs/mmBtu in 2009)EGUs Additional 0.16 lbs/mmBtu reductionin SO2 from original CAIR emissionscapw 19Adopt Emission Caps Based on “NOx BACT Level for NewPlants” of 0.07 lbs/mmBtu by 2013 (with Interim Cap Based on0.12 lbs/mmBtu in 2009)EGUs Additional 0.06 lbs/mmBtu reductionin NOX from original CAIRemissions cap19Replace old boilers to boost efficiency by 50-60% EGUs Not Available 19Implement Consumer Education programs to promote energyefficiencyand reduce demand.Not Available19B-5Appendix B-2. Control Strategies for EGUsTechnologyProcesses CoveredEfficiency of ControlNotes ReferenceFuel OptionsUse fuel oil with a sulfur content of 0.05% or less for all boilersizes (<50 - >250 MmBtu/hr)#1 and #2 fuel oil26Use fuel oil with a sulfur content of 0.5% or less#4 and #6 fuel oil26Use coal with low sulfur contentCoal for units between 50-100mmBtu/hr2.0 lb/MmBtu or 30% SO2 reduction26Use coal with low sulfur content Coal for units between 100-250mmBtu/hr1.2 lb/MmBtu or 85% SO2 reduction26Use coal with low sulfur contentCoal for units >250 MmBtu/hr0.25 lb/MmBtu or 85% SO2 reduction 26Retrofit Technologies for individual emission unitsBurner ModificationsMost units10 to 30% NOx reduction19Fuel ReburnMost units. Furnace height (residencetime) may restrict some applications20 to 30% NOx reduction for FuelLean Gas Reburning (no OFA), and30 to 60% reduction for conventionalreburning.19Hydrocarbon-enhanced SNCRMost units. Can use more NH3 withless slip.40 to 60% NOx reduction 19Low-NOx BurnersMost boilers alreadyhave LNB. 30 to 50% NOx reduction19Overfire AirMost units. Furnace height may restrictsome applications20 to 40% NOx reduction 19Oxygen-enhanced combustion modificationBest applied with new OFA systemdesigned to achieve stoichiometric airfuel ratio < 0.8.30-50% beyond OFA19Rich Reagent InjectionMost units. Modeling required todetermine injection locations.20 to 30% additional NOx reductionbeyond OFA.19Selective Catalytic Reduction (SCR) Most units. Space availability mayconstrain some options. High sulfurfuels more challenging70 to 90+% NOx reduction19Selective Non-catalytic Reduction (SNCR)Most units. Residence time andtemperature characteristics areimportant25 to 50% NOx reduction, dependingon the furnace temperature and timefor reaction.19[continued]B-6Appendix B-2. Control Strategies for EGUsTechnologyProcesses CoveredEfficiency of ControlNotes ReferencePhysical Coal CleaningAvailable for all units10-40% SO2 reduction19Chemical Coal CleaningAvailable for all units50-85% SO2 reduction19Switch to Low Sulfur CoalAvailable for all units50-80% SO2 reduction19Limestone forced oxidation system (LSFO)Generally used for >100 MW unitsunits firing high-sulfur (>2 percent)bituminous coals.52 – 98% reduction in SO2, withmedian reduction of 90%; EPA used95% in CAIR analysis19Magnesium enhanced lime system (MEL) Generally used for 100-550 MW unitsunits firing low-sulfur (<2 percent)bituminous, sub-bituminous, and lignitecoals.52 – 98% reduction in SO2, withmedian reduction of 90%; EPA used96% for CAIR analysis19Lime spray dryer system (LSD) Can be used for both low-and highsulfur coals, depending on theeconomics of each application.70 - 96% reduction in SO2, withmedian reduction of 90%; EPA used90% for CAIR analysis19Dryor wet FGDCoal-burningunits >250 mmBtu/hr 90% SO2 reduction26Combustion TuningAll units 50-100 mmBtu/hr5-35% NOX reduction26[continued]B-7Appendix B-3. Control Strategies for ICI BoilersTechnologyProcesses CoveredEfficiency of Control (% atthe unit) Notes ReferenceBaseline and On-the-books regionalprogramsBaseline 2002: NSPS; PSD/NSR; State RACT Rules ICI BoilersNAbb 202009 On-the-Books (OTB) measures: Enforcement settlementsand Alcoa announced scrubbersICI Boilers18% SO2 reduction from2002 levelsbb 202009 OTB measures: NOx SIP Call for large boilers,enforcement settlementsICI Boilers3% NOX reduction from2002 levelsbb 20Additional regionalprogramsOTB measures plus 40% SO2 Reduction and 60% Reduction(similar to NOx SIP Call) to All Medium and Large ICI BoilersICI Boilers29% SO2 reduction and19% NOX reduction from2002 levelsx 20OTB Measures plus Likely Controls to ICI Boilers subject to theproposed BART requirements Emission Reductions.ICI Boilers8% NOX reduction and40% SO2 reduction from2002 levelsy 20OTB Measures plus 90% SO2 Reduction and 80% NOXreduction (similar to BART) to All Medium and Large ICIBoilers Emission Reductions.ICI Boilers66% SO2 reduction and31% NOX reduction from2002 levelsz 20Fuel OptionsUse fuel oil with a sulfur content of 0.05% or less for all boilersizes(<50 - >250 MmBtu/hr)#1 and #2 fuel oil26Use fuel oil with a sulfur content of 0.5% or less#4 and #6 fuel oil26Use coal with low sulfur contentCoal for units between 50-100mmBtu/hr2.0 lb/MmBtu or 30% SO2reduction26Use coal with low sulfur contentCoal for units between 100-250mmBtu/hr1.2 lb/MmBtu or 85% SO2reduction26Use coal with low sulfur contentCoal for units >250 MmBtu/hr0.25 lb/MmBtu or 85%SO2 reduction26B-8Appendix B-3. Control Strategies for ICI BoilersTechnologyProcesses CoveredEfficiency of Control (% atthe unit) Notes ReferenceRetrofit Technologies for individual emission unitsLNB (Low NOX Burner)Coal Sub-bituminous fueled boiler 51% NOX reduction20Coal Sub-bituminous fueled boiler 65% NOX reduction20Coal Bituminous fueled boiler 51% NOX reduction20Gas fueled boiler60% NOX reduction20Oil fueled boiler30% NOX reduction20LNB + OFA + FGR(Flue Gas Recirculation)Gas fueled boiler80% NOX reduction20, 26LNB + OFA + FGR(0.5 lbs/mmBtu inlet NOx)Oil fueled boiler50% NOX reduction20, 26Coal fueled boiler80% NOX reduction20, 26Gas fueled boiler80% NOX reduction20, 26Oil fueled boiler80% NOX reduction20, 26Coal fueled boiler40% NOX reduction20, 26Oil fueled boiler40% NOX reduction20, 26Wood/Non-fossil solid fuel not available26Gas fueled boiler40% NOX reduction20Coal High Sulfur fueled boiler 40% SO2 reduction20Coal Low Sulfur fueled boiler 40% SO2 reduction20SDACoal fueled boiler90% SO2 reduction20Coal High Sulfur fueled boiler 90% SO2 reduction20Coal Low Sulfur fueled boiler 90% SO2 reduction20Oil fueled boiler90% SO2 reduction20Water InjectionGas fueled boiler75% NOX reduction26[continued]LNB + OFA (Over-fire air)In-duct Dry Sorbent Injection (IDSI)Wet FGDSNCRSCRB-9Control MeasureSources CoveredEstimated Efficiency(%) Notes ReferencesLow-Emission CombustionInternal Combustion80-90% reduction27Prestratified ChargeInternal Combustion75-90% reduction27High Energy/Plasma Ignition SystemsInternal Combustion80% reductioncc 27SCONOx TechnologyInternal Combustion95% reductiondd 27NOxTech SystemInternal Combustion90-95% reduction27High-pressure Fuel InjectionInternal Combustion80% reduction27Air Fuel w/Ignition RetardInternal Combustion - Gas53 tons/30% reduction hh28, 29Air Fuel w/Ignition RetardIC Engines - Gas53 tons/30% reduction hh28, 29Air Fuel Ratio AdjustmentInternal Combustion - Gas36 tons/20% reduction hh28, 29Air Fuel Ratio AdjustmentIC Engines - Gas38 tons/20% reduction hh28, 29Ignition RetardIC Engine - Oil6 tons/25% reduction hh28, 29Ignition RetardIC Engines - Gas, Diesel, LPG 9 tons/25% reduction hh28, 29L-E(Low Speed)IC Engine - Gas148 tons/87% reduction hh28, 29L-E(Medium Speed)IC Engine - Gas98 tons/87% reduction hh28, 29NSCRIC Engine - Oil19 tons/90% reduction ee, hh 27, 28, 29NSCRIC Engine - Gas, Diesel, LPG26 tons/90% reduction ff, hh27, 28, 29SCRIC Engine - Gas150 tons/90% reductiongg, hh27, 28, 29SCRIC Engine - Gas, Diesel, LPG23 tons/80% reduction hh27, 28, 29SCRIC Engine - Oil17 tons/80% reduction hh27, 28, 29Appendix B-4. Control Strategies for Reciprocating EnginesB-10Control MeasureSources CoveredEstimated Efficiency(%) Notes ReferencesExternal Flue Gas Recirculation TurbineN/Aii 30Overfire AirTurbineN/A30Low NOx BurnersTurbine25-50% reduction30Selective Catalytic Reduction (High Dust) Turbine70-90% control efficiency ii 30Selective Catalytic Reduction (Low Dust) Turbine80-90% control efficiency30Selective Non-Catalytic ReductionTurbine25-50% control efficiency30Low Temperature Oxidation(Tri-NOx)Turbine99% control efficiency30Low Temperature Oxidation (LoTox) Turbine80-95% control efficiency30Non Selective Catalytic ReductionTurbineN/Aii 30Novel Multi-Pollutant Controls (ElectroCatalytic Oxidation)TurbineN/A30Novel Multi-Pollutant Controls (PahlmanProcess)TurbineN/Aii 30SCONOx TechnologyGas Turbines95% reduction27DryLow NOx CombusterCombustion Turbines - Natural Gas 102 tons/50% reduction hh28, 29DryLow NOx CombusterCombustion Turbines - Natural Gas 102 tons/84% reduction hh28, 29SCR w/Low NOx BurnerCombustion Turbines - Natural Gas 143 tons/94% reduction hh28, 29SCR w/Steam InjectionCombustion Turbines - Natural Gas 145 tons/95% reduction hh28, 29SCR w/Water InjectionCombustion Turbines - Natural Gas 145 tons/95% reduction hh28, 29SCR w/Water InjectionCombustion Turbines - Oil31 tons/90% reduction hh28, 29SCR w/Water InjectionCombustion Turbines - Jet Fuel 13 tons/90% reduction hh28, 29Steam InjectionCombustion Turbines - Natural Gas 119 tons/80% reduction hh28, 29Water InjectionCombustion Turbines - Natural Gas 112 tons/76% reduction hh28, 29Water InjectionCombustion Turbines - Oil23 tons/68% reduction hh28, 29Water InjectionCombustion Turbines - Jet Fuel 10 tons/68% reduction hh28, 29DryLow NOx CombusterCombustion Turbines - Natural Gas 102 tons/50% reduction hh28, 29DryLow NOx CombusterCombustion Turbines - Natural Gas 102 tons/84% reduction hh28, 29Appendix B-5. Control Strategies for TurbinesB-11Appendix B-6. Control Strategies for AmmoniaControl MeasureSources CoveredEstimatedEfficiency (%) Notes ReferencesFloor housingsystem with stockpilingof manureStorage and handlingofpoultrymanure(solid)N/Ajj31Cage housingsystem with conveyor beltsStorage and handlingofpoultrymanure(solid)N/Ajj31Cage housingsystem with deeppitsStorage and handlingofpoultrymanure(solid)N/Ajj31Lagoons/concrete tanks for storage of poultry manure Storage of poultry manure (storage)N/Ajj 31Spread manure and incorporate within 3 days Application ofpoultrymanure(solid)36 - 80% reductionjj, kk 32Spread manure and incorporate within 3 days Application of dairymanure(solid and liquid)70% reductionjj, kk 32Spread manure and incorporate within 3 days Application of beef manure(solid and liquid)36-70% reductionjj, kk 32Spread manure and incorporate within 3 days Application of swine manure(solid and liquid)36-70% reductionjj, kk 32Inject manure using tank wagon and incorporate withknives or disksApplication of dairy and beef manure (liquid) N/A 33Above-ground manure storage tanksStorage of dairyand beef manure(solid and liquid)N/All 33Walled enclosures to store manureStorage of dairyand beef manure(solid and liquid)N/Amm33Outwinter cattle by rotating through pastures to "store"manure in frozen form until it can be used in the springHousing cattle (winter) N/A 34Outwinter cattle by keeping them outside in one paddock(sacrifice paddock) to store manure in one locationHousing cattle (winter)N/A34Compost manure before applyingTreatment of livestock manure(solid and liquid)N/A35Daily scraping and hauling of manure for collection andstorageStorage and handling of swine manure (solid) 42-63% reduction jj, nn 36Leaving manure to mix with bedding to form manure packfor collection and storageStorage and handling of swine manure (solid) 33-50% reduction jj, nn 36Storingmanure in linedpitStorage and handlingof swine manure(liquid)jj, oo 36Storingmanure in above-ground storage facilityStorage and handlingof swine manure(liquid)25-50% reductionjj, oo 36Broadcasting manure w/incorporation into soil within 12hoursApplication of swine manure (solid) 80% reduction jj, h1 36B-12Appendix B-6. Control Strategies for AmmoniaControl MeasureSources CoveredEstimatedEfficiency (%) Notes ReferencesBroadcasting manure w/incorporation into soil within 4daysApplication of swine manure (solid) 40% reduction jj, h1 36Injection of manure with sweepsApplication of swine manure(liquid)87% reductionjj, h1 36Injection of manure with knivesApplication of swine manure(liquid)62% reductionjj, h1 36Collectionponds to store manureStorage and handlingof swine manure(liquid)N/A37Deep pits to store manure and minimize gasconcentrationsStorage and handling of swine manure (solid) N/A 37Stockpile manure on concrete or claypadStorage and handlingof swine manure(solid)N/A37System than separates liquid and solid manureStorage and handlingof swine manure(solid)N/A37CompostingmanureTreatment of swine manure(liquid and solid)N/A37Anaerobic lagoons and digesters to store and "treat"manureTreatment of swine manure (liquid and solid) N/A 37Oxidation ditches and aerated lagoons to store and "treat"manureTreatment of swine manure (liquid and solid) N/A 37Daily scraping and hauling of manure for collection andstorageStorage and handling of poultry manure (solid) 42-63% reduction jj, nn 38Leaving manure to mix with bedding to form manure packfor collection and storageStorage and handling of poultry manure (solid) 33-50% reduction jj, nn 38Broadcasting manure w/incorporation into soil within 12hoursApplication of poultry manure (solid)83% reduction jj, h1 38Broadcasting manure w/incorporation into soil within 4daysApplication of poultry manure (solid) 33% reduction jj, h1 38[continued]B-13Appendix B-6. Control Strategies for AmmoniaControl MeasureSources CoveredEstimatedEfficiency (%) Notes ReferencesDaily scraping and hauling of manure for collection andstorageStorage and handling of dairy manure (solid) 42-62% reduction jj, nn 39Leaving manure to mix with bedding to form manure packfor collection and storageStorage and handling of dairy manure (solid) 30-50% reduction jj, nn 39Storingmanure in linedpitStorage and handlingof dairymanure(liquid)25% reductionjj, oo 39Storingmanure in above-ground storage facilityStorage and handlingof dairymanure(liquid)25-50% reductionjj, oo 39Broadcasting manure w/incorporation into soil within 12hoursApplication of dairy manure (solid) 75% reduction jj, h1 39Broadcasting manure w/incorporation into soil within 4daysApplication of dairy manure (solid) 50% reduction jj, h1 39Injection of manure with sweepsApplication of dairymanure(liquid)86% reductionjj, h1 39Injection of manure with knivesApplication of dairymanure(liquid)71% reductionjj, h1 39Daily scraping and hauling of manure for collection andstorageStorage and handling of beef manure (solid) 42-63% reduction jj, nn 40Leaving manure to mix with bedding to form manure packfor collection and storageStorage and handling of beef manure (solid) 33-50% reduction jj, nn 40Storingmanure in linedpitStorage and handlingof beef manure(liquid)25% reductionjj, oo 40Storingmanure in above-ground storage facilityStorage and handlingof beef manure(liquid)25-50% reductionjj, oo 40Broadcasting manure w/incorporation into soil within 12hoursApplication of beef manure (solid) 87% reduction jj, h1 40Broadcasting manure w/incorporation into soil within 4daysApplication of beef manure (solid) 50% reduction jj, h1 40Injection of manure with sweepsApplication of beef manure(liquid)56% reductionjj, h1 40Injection of manure with knivesApplication of beef manure(liquid)71% reductionjj, h1 40Best Management PracticesN/A41Manure Storage CoversStorage of livestock manure(solid and liquid)N/A41Manure Digesters(Biogas)Handlingof livestock manure(solid and liquid)N/A41Animal Lot Increased CleaningN/A41Injection of manure into fieldsApplication of livestock manure(liquid)N/A41[continued]B-14Appendix B-6. Control Strategies for AmmoniaControl MeasureSources CoveredEstimatedEfficiency (%) Notes ReferencesNutrient Management PlansHousing, storage, handling, and application oflivestock manure(solid and liquid)N/A41Earthen storageStorage of manure(solid and liquid)N/Aqq42Clay-lined impoundmentStorage of manure(solid and liquid)N/A42Geomembrane-lined impoundmentStorage of manure(solid and liquid)N/A42Geosynthetic clay-lined impoundmentStorage of manure(solid and liquid)N/A42Concrete-lined impoundmentStorage of manure(solid and liquid)N/A42Manure storage structureStorage of manure(solid and liquid)N/Aqq42Clay-lined impoundmentStorage of manure(solid and liquid)N/A42Geomembrane-lined impoundmentStorage of manure(solid and liquid)N/A42Geosynthetic clay-lined impoundmentStorage of manure(solid and liquid)N/A42Concrete-lined impoundmentStorage of manure(solid and liquid)N/A42Nitrification inhibitorHandlingof livestock manure(liquid)N/Ass 43Minimize application on frozen or snow-covered ground Application of livestock manure (solid and liquid) N/A44Apply manure on crops that can use all of its nutrients Application of livestock manure (solid and liquid) N/A44Incorporate or inject manure within 72 hours using ureaseinhibitorApplication of livestock manure (solid and liquid) N/A44Cover manure storage structures or use organic matter inbeddingto form a crust coverStorage of livestock manure (solid and liquid) N/A 44Divert urine awayfrom fecesHandlingof livestock manure(solid and liquid)N/A44Incorporate manureApplication of dairymanure10% reductionjj, kk 44Incorporate manureApplication of beef manure10% reduction44Incorporate manureApplication of swine manure(solid)15% reduction44Incorporate manureApplication of swine manure(liquid)15% reduction tt44[continued]B-15Appendix B-6. Control Strategies for AmmoniaControl MeasureSources CoveredEstimatedEfficiency (%) Notes ReferencesIncorporate manureApplication ofpoultrymanure10% reduction uu44Incorporate manureApplication of sheepmanure(solid)10% reduction44Incorporate manureApplication of horse manure(solid)10% reduction44Solid and liquid separation systemHandlingof liquid and solid manureN/Avv45Treat waste by mechanical, chemical, or biological means Treatment of livestock manure (solid and liquid) N/A46, 47Hopper to transfer manureHandlingof liquid and solid manureN/A48Reception structure or tank to transfer manureHandlingof liquid and solid manureN/Aww48Piston pumps to transfer manure to storage or treatmentstructureHandling of liquid and solid manure N/A 48Channels to transfer manure(gravitytransfer)Handlingof liquid and solid manureN/Axx 48Transfer pipes to transfer manure to storage or treatmentstructureHandling of liquid and solid manureN/Axx 48Pipelines(gravitytransfer)Handlingof liquid and solid manureN/A48[continued]B-16

# Appendix B-7. References for Control Strategies

1. Chan et al. E mission 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. E valuating 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. E stimates 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. E valuation 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. R eport 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

E q ui p ment ( 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 inWisconsin." 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

p romul g ation of State laws. ( Similar measures were also mentioned in ENVIRON's p hase I mobile source strate gy 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

re p ort estimates an 8% NOX reduction in 2007 if all states in the LADCO re g ion full y im p lemented an IM and OBD
d. Co-benefits of this strate gy are si g nificant. PM, HC, and CO are reduced b y 48, 48, and 68% res p ectivel y . 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 stud y are p re-1998. Cetane additives ma y decrease NOX emissions.
f. O p acit y reduced 2-6% when switchin g from re g ular diesel to B20

g . O p acit y reduced 5-11% when switchin g from re g ular diesel to B30

h. This test did not demonstrate PM or HC reductions usin g B20 or CARB diesel.

i. Emission benefits are not readil y available for most nonroad a pp lications. However, biodiesel is bein g used for j . 1% NOX reduction for line-haul locomotives, 2% for switchin g

. k. Based on Port of Los An g eles Emissions Inventor y . Percenta g e ma y differ for LADCO re g ion. 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 com p ared to re g ular g asoline. m. ENVIRON report assumes 15% participation in 2009 and 30% participation of HDDV anti-idling measures by 2012.

The re p ort also assumes 25% and 50% of switchin g and linehaul locomotives res p ectivel y

. n. Calculation of percentage NOX control efficiency would require knowledge of the percentage of time a truck would

p artici p ate in anti-idlin g p ro g rams. It is assumed that 100% of NOX would be reduced durin g the anti-idlin g time.
o. Control efficienc y was cited from the ENVIRON Phase II re p ort.

p . Control efficiencies were calculated based on the g /bh p -hr en g ine standard of the u pg raded en g ine vs. the old en g ine.

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. Timin g o f

Im p lementation : Assumes full reductions achieved in 2009. I m

p lementation

y . Candidate measure ID ICI2. Timin g o f

Im p lementation : Assumes full reductions achieved in 2013 I m

p lementation Area : z. Candidate measure ID ICI3. Timin g o f

Im p lementation : Assumes full reductions achieved in 2009 I m

p lementation Area : aa. Applies to CO, HC (and toxics), PM, and somewhat for NOx, probably for nontailpipe HCs. Fresno Study referenced in

Dou g Lawson's p resentation 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

p a p ers. We will include discussion on these existin g or u p comin g measures for all source cate g ories in our final re p ort.

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 hi g h cos t
nn. Baseline is o p en g round stora g e ( leavin g manure on g round with no method of collection or stora g e )

oo. Baseline is earthen g round stora g e ( leavin g manure on g round with no method of collection or stora g e )

pp . Baseline is broadcastin g manure with no waitin g time before incor p oratio n qq. no particular strategy is described as "best practice" but State offers technical specifications for structures to meet standard, e. g ., stora g e volume, de p th, how much stress can be p laced on the structure de p endin g 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 timin g s of manure a pp lication ( s p ecific soil tem p eratures )
tt. reference broke out nutrient availabilit y amon g indoor p it, outdoor p it, and farrow-nurser y indoor p it stora g e o p tions; all

uu. reference broke out nutrient availabilit y amon g duck, chicken, turke y , and p oultr y manure; all had same nutrient

vv. reference p rovides efficienc y in ca p turin g solids from waste strea m ww. reference p rovides technical s p ecifications for dimensions and distances from water source s xx. reference p rovides material com p onents and technical s p ecifications for transfer mechanis m



## [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-31a 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 SO 2 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 SO 2 . The remaining units all burned natural gas and so had negligible SO 2 emissions. According to Boise's 2005 permit, the SO 2 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 SO 2 , and further cost analysis for ICI1 was not necessary. Analyses were conducted for ICI1 NO X , and the Workgroup recommendation for both NO X and SO 2 .



### 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 facilitiesincludes 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 PM 2.5 

### 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 SO 2 

### 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 CControl technologyFuel and boiler typeBase value($/kW)Scalefactor Expon-entBase value($/kW-yr) Scale factor Expon-entBase value(cents/kWh) Scale factor Expon-ent<100 MW511.1 100 0.62 20.75 100 0.470.153 na na100-300 MW251.2 300 0.62 12.01 300 0.390.153 na na300-500 MW190.0 500 0.55 9.83 500 0.350.153 na na500-700 MW 155.1 700 0.60 8.74 700 0.37 0.153 na na>700 MW 131.0 1,000 0.47 7.64 1,000 0.37 0.153 na na<100 MW 312.3 100 0.50 14.20 100 0.47 0.153 na na100-300 MW 169.3 300 0.33 8.74 300 0.56 0.153 na na300-500 MW 143.1 500 0.31 6.55 500 0.54 0.153 na na500-700 MW 128.9 700 0.15 5.46 700 0.63 0.153 na na>700 MW 122.3 1,000 0.15 4.37 1,000 0.63 0.153 na naSCR Coal 133.8 243 0.27 0.89 243 0.27 0.080 243 0.11Oil / gas 38.6 200 0.35 1.19 200 0.35 0.013 na naSNCR Coal, pulverized, term 1** 22.9 200 0.58 0.34 200 0.58 0.118 na naCoal, pulverized, term 2** 26.1 100 0.68 0.40 100 0.68 0.118 na naCoal, cyclone 13.2 300 0.58 0.19 300 0.58 0.223 na naCoal, fluidized bed 22.9 200 0.58 0.35 200 0.58 0.102 na naOil / gas 13.0 200 0.58 0.20 200 0.58 0.060 na naLNB without OFA Coal, wall-fired 23.1 300 0.36 0.35 300 0.36 0.007 na naLNB with OFA Coal, wall-fired 31.3 300 0.36 0.48 300 0.36 0.010 na naLNB with close-coupled OFA Coal, tangential 12.2 300 0.36 0.02 300 0.36 0.000 na naLNB with separated OFA Coal, tangential 17.0 300 0.36 0.25 300 0.36 0.003 na naLNB with close-coupled and separatedOFACoal, tangential 19.4 300 0.36 0.30 300 0.36 0.003 na na<100 MW 511.1 100 0.62 20.75 100 0.47 0.153 na na100-300 MW 251.2 300 0.62 12.01 300 0.39 0.153 na na300-500 MW 190.0 500 0.55 9.83 500 0.35 0.153 na na500-700 MW 155.1 700 0.60 8.74 700 0.37 0.153 na na>700 MW 131.0 1,000 0.47 7.64 1,000 0.37 0.153 na na<100 MW 312.3 100 0.50 14.20 100 0.47 0.153 na na100-300 MW 169.3 300 0.33 8.74 300 0.56 0.153 na na300-500 MW 143.1 500 0.31 6.55 500 0.54 0.153 na na500-700 MW 128.9 700 0.15 5.46 700 0.63 0.153 na na>700 MW 122.3 1,000 0.15 4.37 1,000 0.63 0.153 na naSource: Reference 1NOX ControlsLime 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 AnalysesSO2 ControlsCapital cost factors*Fixed operating and maintenancescaling factors*Variable operating and maintenance costfactors*Limestone forced oxidation scrubberLime spray dryer scrubberC-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-5Table C-3. Estimated Cost and Cost Effectiveness for EGU1 and EGU2 Control Strategies for theDetroit Edison/St. Clair-Belle River Facility (Michigan)State Facility Unit FuelCapacity(MW)BaselineEmissions(tons)ControlTechnology%Reduction Cost ModelTotal CapitalInvestment[$M2005]Total O&MCost[$M2005]TotalAnnualizedCost [$M2005]EmissionReduction(tons)CostEffectiveness[$2005/ton]LowestAnnualizedCost($M2005)HighestAnnualizedCost($M2005)LowestEmissionsReduced(tons)HighestEmissionsReduced(tons)CostEffectiveness($2005/ton)MISt. Clair/Belle River 1 Coal 153 5,491 LSD 90 CUECost 54,602 6,604 14,783 4,942 2,991 10,628 18,012 4,942 5,216 150-3452IPM 44,092 4,023 10,628 4,942 2,151STAPPA ----150-4000LSFO 95 CUECost 71,543 7,295 18,012 5,216 3,453IPM 69,090 4,938 15,288 5,216 2,931STAPPA ----200-50002 Coal 162 6,162 LSD 90 CUECost 59,169 7,156 16,020 5,546 2,888 11,009 19,257 4,942 5,216 150-3289IPM 45,379 4,211 11,009 5,546 1,985STAPPA ----150-4000LSFO 95 CUECost 76,687 7,769 19,257 5,854 3,289IPM 70,608 5,155 15,732 5,854 2,687STAPPA ----200-50003 Coal 171 6,132 LSD 90 CUECost 58,567 7,149 15,923 5,519 2,885 11,425 19,263 4,942 5,825 150-3306IPM 46,631 4,440 11,425 5,519 2,070STAPPA ----150-4000LSFO 95 CUECost 76,094 7,864 19,263 5,825 3,307IPM 72,074 5,412 16,209 5,825 2,783STAPPA ----200-50004 Coal 158 5,734 LSD 90 CUECost 56,209 6,840 15,260 5,160 2,957 10,774 18,434 4,942 5,447 150-3384IPM 44,811 4,061 10,774 5,160 2,088STAPPA ----150-4000LSFO 95 CUECost 73,110 7,482 18,434 5,447 3,384IPM 69,940 4,992 15,469 5,447 2,840STAPPA ----200-50006 Coal 321 11,765 LSD 90 CUECost 75,056 10,823 22,066 10,588 2,084 16,444 25,653 4,942 11,176 150-2295IPM 61,545 7,224 16,444 10,588 1,553STAPPA ----150-4000LSFO 95 CUECost 92,898 11,737 25,653 11,176 2,295IPM 89,995 8,446 21,928 11,176 1,962STAPPA ----200-50007 Coal 450 11,765 LSD 90 CUECost 90,888 15,164 28,779 10,588 2,718 21,036 32,737 4,942 11,176 150-2929IPM 77,195 9,472 21,036 10,588 1,987STAPPA ----150-4000LSFO 95 CUECost 111,146 16,088 32,737 11,176 2,929IPM 104,903 11,187 26,902 11,176 2,407STAPPA ----200-5000Plant Total1,415 47,04877,147 133,356 42,344 44,696 1822-2984State Facility Unit FuelCapacity(MW)BaselineEmissions(tons)ControlTechnology%Reduction Cost ModelTotal CapitalInvestment[$M2005]Total O&MCost[$M2005]TotalAnnualizedCost [$M2005]EmissionReduction(tons)CostEffectiveness[$2005/ton]LowestAnnualizedCost($M2005)HighestAnnualizedCost($M2005)LowestEmissionsReduced(tons)HighestEmissionsReduced(tons)CostEffectiveness($2005/ton)MISt. Clair/Belle River 1 Coal 153 1,071 SCR 90 CUECost 15,493 1,520 3,602 963 3,739 599 6,764 375 963 200-1148IPM 24,436 1,143 4,428 963 4,596STAPPA ----1000-2000Costs of SO2 Controls for EGUsCosts of NOx Controls for EGUsC-6Table C-3. Estimated Cost and Cost Effectiveness for EGU1 and EGU2 Control Strategies for theDetroit Edison/St. Clair-Belle River Facility (Michigan)State Facility Unit FuelCapacity(MW)BaselineEmissions(tons)ControlTechnology%Reduction Cost ModelTotal CapitalInvestment[$M2005]Total O&MCost[$M2005]TotalAnnualizedCost [$M2005]EmissionReduction(tons)CostEffectiveness[$2005/ton]LowestAnnualizedCost($M2005)HighestAnnualizedCost($M2005)LowestEmissionsReduced(tons)HighestEmissionsReduced(tons)CostEffectiveness($2005/ton)SNCR 35 CUECost 2,219 301 599375 1,600IPM 3,727 1,420 1,921 375 5,126STAPPA - - - - 800-1500LNB 35 CUECost 5,375 120 843 375 2,250IPM 4,741 155 792 375 2,114STAPPA - - - - 200-1000NGR 55 CUECost 5,006 6,091 6,764 589 11,488IPM - - - 589 -STAPPA - - - - 500-20002 Coal 162 1,693 SCR 90 CUECost 17,433 1,736 4,079 1,524 2,677 744 7,595 593 1,524 200-8156IPM 25,477 1,207 4,631 1,524 3,039STAPPA - - - - 1000-2000SNCR 35 CUECost 2,479 411 744 593 1,255IPM 3,809 1,508 2,020 593 3,409STAPPA - - - - 800-1500LNB 35 CUECost 5,579 125 875 593 1,476IPM - - - 593 -STAPPA - - - - 200-1000NGR 55 CUECost 5,339 6,878 7,595 931 8,156IPM - - - 931 -STAPPA - - - - 500-20003 Coal 171 1,195 SCR 90 CUECost 16,866 1,651 3,918 1,076 3,641 638 7,505 418 1,076 200-1141IPM 26,503 1,291 4,853 1,076 4,510STAPPA - - - - 1000-2000SNCR 35 CUECost 2,376 319 638 418 1,525IPM 3,888 1,627 2,149 418 5,137STAPPA - - - - 800-1500LNB 35 CUECost 5,778 129 906 418 2,166IPM - - - 418 -STAPPA - - - - 200-1000NGR 55 CUECost 5,485 6,767 7,505 657 11,414IPM - - - 657 -STAPPA - - - - 500-20004 Coal 158 1,118 SCR 90 CUECost 16,244 1,616 3,799 1,006 3,776 609 7,079 391 1,006 200-1151IPM 25,017 1,145 4,507 1,006 4,480STAPPA - - - - 1000-2000SNCR 35 CUECost 2,276 303 609 391 1,556IPM 3,773 1,422 1,929 391 4,931STAPPA - - - - 800-1500LNB 35 CUECost 5,489 123 861 391 2,200IPM 4,840 157 807 391 2,063STAPPA - - - - 200-1000NGR 55 CUECost 5,083 6,396 7,079 615 11,514IPM - - - 615 -STAPPA - - - - 500-2000C-7Table C-3. Estimated Cost and Cost Effectiveness for EGU1 and EGU2 Control Strategies for theDetroit Edison/St. Clair-Belle River Facility (Michigan)State Facility Unit FuelCapacity(MW)BaselineEmissions(tons)ControlTechnology%Reduction Cost ModelTotal CapitalInvestment[$M2005]Total O&MCost[$M2005]TotalAnnualizedCost [$M2005]EmissionReduction(tons)CostEffectiveness[$2005/ton]LowestAnnualizedCost($M2005)HighestAnnualizedCost($M2005)LowestEmissionsReduced(tons)HighestEmissionsReduced(tons)CostEffectiveness($2005/ton)6 Coal 321 1,766 SCR 90 CUECost 25,234 2,886 6,278 1,589 3,950 846 13,028 618 1,589 200-1341IPM 41,972 2,180 7,821 1,589 4,921STAPPA ----1000-2000SNCR 35 CUECost 3,070 433 846618 1,369IPM 4,939 2,942 3,606 618 5,834STAPPA ----800-1500LNB 35 CUECost 8,701 195 1,364 618 2,207IPM ---618 -STAPPA ----200-1000NGR 55 CUECost 7,844 11,974 13,028 971 13,414IPM ---971 -STAPPA ----500-20007 Coal 450 1,766 SCR 90 CUECost 33,526 4,143 8,648 1,589 5,442 1,214 10,190 618 1,589 200-7980IPM 53,710 2,972 10,190 1,589 6,412STAPPA ----1000-2000SNCR 35 CUECost 3,891 691 1,214 618 1,964IPM 5,619 4,177 4,932 618 7,980STAPPA ----800-1500Plant Total1,415 8,6094,649 51,639 3,013 7,748 1543-6665C-8Table C-4. Consumers Energy Company/JH Campbell Facility (Michigan)State Facility Unit FuelCapacity(MW)BaselineEmissions(tons)ControlTechnology%Reduction Cost ModelTotal CapitalInvestment[$M2005]TotalO&M Cost[$M2005]TotalAnnualizedCost [$M2005]EmissionReduction(tons)CostEffectiveness[$2005/ton]LowestAnnualizedCost($M2005)HighestAnnualizedCost($M2005)LowestEmissionsReduced(tons)HighestEmissionsReduced(tons)CostEffectiveness($2005/ton)MI JH Campbell 1 Coal 260 10,767 LSD 90 CUECost 78,193 11,709 23,423 9,690 2,417 14,483 24,314 9,690 10,229 150-2417IPM 57,580 5,858 14,483 9,690 1,495STAPPA -- --150-4000LSFO 95 CUECost 93,492 10,309 24,314 10,229 2,377IPM 84,520 7,077 19,738 10,229 1,930STAPPA -- --200-50002 Coal 355 12,986 LSD 90 CUECost 83,538 13,935 26,449 11,688 2,263 17,567 27,430 11,688 12,337 150-2263IPM 65,844 7,704 17,567 11,688 1,503STAPPA -- --150-4000LSFO 95 CUECost 99,523 12,521 27,430 12,337 2,223IPM 94,201 9,060 23,171 12,337 1,878STAPPA -- --200-50003 Coal 820 30,020 LSD 90 CUECost 112,653 24,860 41,735 27,018 1,545 32,371 47,039 27,018 28,519 150-1649IPM 119,585 14,457 32,371 27,018 1,198STAPPA -- --150-4000LSFO 95 CUECost 156,806 23,550 47,039 28,519 1,649IPM 136,680 17,580 38,055 28,519 1,334STAPPA -- --200-5000Plant Total1435 5377364,421 98,783 48,396 51,085 1331-1934State Facility Unit FuelCapacity(MW)BaselineEmissions(tons)ControlTechnology%Reduction Cost ModelTotal CapitalInvestment[$M2005]TotalO&M Cost[$M2005]TotalAnnualizedCost [$M2005]EmissionReduction(tons)CostEffectiveness[$2005/ton]LowestAnnualizedCost($M2005)HighestAnnualizedCost($M2005)LowestEmissionsReduced(tons)HighestEmissionsReduced(tons)CostEffectiveness($2005/ton)MI JH Campbell 1 Coal 260 3,153 SCR 78 CUECost 29,285 3,146 7,082 2,459 2,880 1,116 12,797 1,104 2,459 200-7379IPM 35,987 1,719 6,556 2,459 2,666STAPPA -- --1000-2000SNCR 35 CUECost 3,316 671 1,116 1,104 1,012IPM 4,559 2,250 2,862 1,104 2,594STAPPA -- --800-1500LNB 35 CUECost 7,589 170 1,190 1,104 1,078IPM -- -1,104 -STAPPA -- --200-1000NGR 55 CUECost 6,885 11,872 12,797 1,734 7,379IPM -- -1,734 -STAPPA -- --500-2000Costs of SO2 Controls for EGUsCosts of NOx Controls for EGUsC-9Table C-4. Consumers Energy Company/JH Campbell Facility (Michigan)State Facility Unit FuelCapacity(MW)BaselineEmissions(tons)ControlTechnology%Reduction Cost ModelTotal CapitalInvestment[$M2005]TotalO&M Cost[$M2005]TotalAnnualizedCost [$M2005]EmissionReduction(tons)CostEffectiveness[$2005/ton]LowestAnnualizedCost($M2005)HighestAnnualizedCost($M2005)LowestEmissionsReduced(tons)HighestEmissionsReduced(tons)CostEffectiveness($2005/ton)2 Coal 355 7,359 SCR 88 CUECost 33,388 4,005 8,492 6,476 1,311 1,457 15,574 2,576 6,476 200-3848IPM 45,173 2,336 8,407 6,476 1,298STAPPA -- --1000-2000SNCR 35 CUECost 3,946 1,424 1,954 2,576 759IPM 5,133 3,182 3,872 2,576 1,503STAPPA -- --800-1500LNB 35 CUECost 9,292 208 1,457 2,576 566IPM -- -2,576 -STAPPA -- --200-1000NGR 55 CUECost 8,375 14,448 15,574 4,047 3,848IPM -- -4,047 -STAPPA -- --500-20003 Coal 820 11,799 SCR 70 CUECost 64,401 8,825 17,481 8,259 2,117 2,511 17,481 4,130 8,259 200-2117IPM 90,557 4,830 17,000 8,259 2,058STAPPA -- --1000-2000SNCR 35 CUECost 6,647 2,231 3,124 4,130 757IPM 7,069 6,937 7,887 4,130 1,910STAPPA -- --800-1500LNB 35 CUECost 16,012 359 2,511 4,130 608IPM -- -4,130 -STAPPA -- --200-1000NGR 55 CUECost 17,069 6,921 9,215 6,489 1,420IPM -- -6,489 -STAPPA -- --500-2000Plant Total1435 223115,084 45,851 7,809 17,194 651-2667C-10Table C-5. Wisconsin Electric/Presque Isle Facility (Michigan)State Facility Unit FuelCapacity(MW)BaselineEmissions(tons)ControlTechnology%Reduction Cost ModelTotal CapitalInvestment[$M2005]TotalO&M Cost[$M2005]TotalAnnualizedCost [$M2005]EmissionReduction(tons)CostEffectiveness[$2005/ton]LowestAnnualizedCost($M2005)HighestAnnualizedCost($M2005)LowestEmissionsReduced(tons)HighestEmissionsReduced(tons)CostEffectiveness($2005/ton)MIWIElectric/Presque Isle 5 Coal 883,431LSD 90 CUECost 45,698 4,761 11,607 3,088 3,759 6,536 14,697 3,088 3,259 150-4509IPM 27,815 2,369 6,536 3,088 2,117STAPPA - - - - 150-4000LSFO 95 CUECost 62,139 5,389 14,697 3,259 4,509IPM 46,657 2,935 9,924 3,259 3,045STAPPA - - - - 200-50006 Coal 883,416LSD 90 CUECost 45,635 4,750 11,586 3,075 3,768 6,536 14,680 3,075 3,245 150-4523IPM 27,815 2,369 6,536 3,075 2,126STAPPA - - - - 150-4000LSFO 95 CUECost 62,076 5,381 14,680 3,245 4,523IPM 46,657 2,935 9,924 3,245 3,058STAPPA - - - - 200-50007 Coal 882,046LSD 90 CUECost 47,226 5,026 12,100 1,842 6,570 6,536 15,113 1,842 1,944 150-7773IPM 27,815 2,369 6,536 1,842 3,549STAPPA - - - - 150-4000LSFO 95 CUECost 63,665 5,576 15,113 1,944 7,773IPM 46,657 2,935 9,924 1,944 5,104STAPPA - - - - 200-50008 Coal 881,965LSD 90 CUECost 46,584 4,914 11,893 1,768 6,726 6,536 14,938 1,768 1,866 150-8004IPM 27,815 2,369 6,536 1,768 3,697STAPPA - - - - 150-4000LSFO 95 CUECost 63,027 5,497 14,938 1,866 8,004IPM 46,657 2,935 9,924 1,866 5,317STAPPA - - - - 200-50009 Coal 881,967LSD 90 CUECost 46,605 4,918 11,899 1,770 6,721 6,536 14,944 1,770 1,869 150-7997IPM 27,815 2,369 6,536 1,770 3,692STAPPA - - - - 150-4000LSFO 95 CUECost 63,047 5,499 14,944 1,869 7,997IPM 46,657 2,935 9,924 1,869 5,310STAPPA - - - - 200-5000Plant Total440 12,82532,679 74,371 11,543 12,184 2831-6104State Facility Unit FuelCapacity(MW)BaselineEmissions(tons)ControlTechnology%Reduction Cost ModelTotal CapitalInvestment[$M2005]TotalO&M Cost[$M2005]TotalAnnualizedCost [$M2005]EmissionReduction(tons)CostEffectiveness[$2005/ton]LowestAnnualizedCost($M2005)HighestAnnualizedCost($M2005)LowestEmissionsReduced(tons)HighestEmissionsReduced(tons)CostEffectiveness($2005/ton)MIWIElectric/Presque Isle 5 Coal 881,012SCR 90 CUECost 12,663 988 2,690 910 2,954 427 4,066 354 910 200-7308IPM 16,319 685 2,878 910 3,161STAPPA - - - - 1000-2000SNCR 35 CUECost 1,916 288 546 354 1,542IPM 3,023 799 1,205 354 3,404STAPPA - - - - 800-1500Costs of SO2 Controls for EGUsCosts of NOx Controls for EGUsC-11Table C-5. Wisconsin Electric/Presque Isle Facility (Michigan)State Facility Unit FuelCapacity(MW)BaselineEmissions(tons)ControlTechnology%Reduction Cost ModelTotal CapitalInvestment[$M2005]TotalO&M Cost[$M2005]TotalAnnualizedCost [$M2005]EmissionReduction(tons)CostEffectiveness[$2005/ton]LowestAnnualizedCost($M2005)HighestAnnualizedCost($M2005)LowestEmissionsReduced(tons)HighestEmissionsReduced(tons)CostEffectiveness($2005/ton)LNB 35 CUECost 2,720 61 427354 1,205IPM -- -354 -STAPPA -- --200-1000NGR 55 CUECost 3,962 3,534 4,066 556 7,308IPM -- -556 -STAPPA -- --500-20006 Coal 881,049SCR 90 CUECost 12,630 984 2,681 944 2,839 427 4,051 367 944 200-7020IPM 16,319 685 2,878 944 3,047STAPPA - - - - 1000-2000SNCR 35 CUECost 1,913 288 545 367 1,483IPM 3,023 799 1,205 367 3,282STAPPA - - - - 800-1500LNB 35 CUECost 2,720 61 427 367 1,161IPM - - - 367 -STAPPA - - - - 200-1000NGR 55 CUECost 3,962 3,519 4,051 577 7,020IPM - - - 577 -STAPPA - - - - 500-20007 Coal 881,218SCR 90 CUECost 13,467 1,082 2,892 1,096 2,640 427 4,430 426 1,096 200-6615IPM 16,319 685 2,878 1,096 2,626STAPPA - - - - 1000-2000SNCR 35 CUECost 1,982 308 574 426 1,348IPM 3,023 799 1,205 426 2,828STAPPA - - - - 800-1500LNB 35 CUECost 2,720 61 427 426 1,001IPM - - - 426 -STAPPA - - - - 200-1000NGR 55 CUECost 3,962 3,897 4,430 670 6,615IPM - - - 670 -STAPPA - - - - 500-20008 Coal 881,063SCR 90 CUECost 13,130 1,042 2,807 957 2,934 427 4,276 372 957 200-7314IPM 16,319 108 2,302 957 2,406STAPPA - - - - 1000-2000SNCR 35 CUECost 1,954 300 562 372 1,512IPM 3,023 799 1,205 372 3,240STAPPA - - - - 800-1500LNB 35 CUECost 2,720 61 427 372 1,146IPM - - - 372 -STAPPA - - - - 200-1000NGR 55 CUECost 3,962 3,744 4,276 585 7,314IPM - - - 585 -STAPPA - - - - 500-2000C-12Table C-5. Wisconsin Electric/Presque Isle Facility (Michigan)State Facility Unit FuelCapacity(MW)BaselineEmissions(tons)ControlTechnology%Reduction Cost ModelTotal CapitalInvestment[$M2005]TotalO&M Cost[$M2005]TotalAnnualizedCost [$M2005]EmissionReduction(tons)CostEffectiveness[$2005/ton]LowestAnnualizedCost($M2005)HighestAnnualizedCost($M2005)LowestEmissionsReduced(tons)HighestEmissionsReduced(tons)CostEffectiveness($2005/ton)9 Coal 881,120SCR 90 CUECost 13,141 1,044 2,690 1,008 2,668 427 4,066 392 1,008 200-6084IPM 16,319 685 2,878 1,008 2,854STAPPA - - - - 1000-2000SNCR 35 CUECost 1,955 300 546 392 1,392IPM 3,023 799 1,205 392 3,074STAPPA - - - - 800-1500LNB 35 CUECost 2,720 61 427 392 1,088IPM - - - 392 -STAPPA - - - - 200-1000NGR 55 CUECost 3,962 3,749 4,066 616 6,084IPM - - - 616 -STAPPA - - - - 500-2000Plant Total440 5,4622,133 20,890 1,912 4,916 1116-4250C-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-15Table C-8. Northshore Mining Company/Silver Bay Facility (Minnesota)State Facility Unit FuelCapacity(MW)BaselineEmissions(tons)ControlTechnology%Reduction Cost ModelTotal CapitalInvestment[$M2005]TotalO&M Cost[$M2005]TotalAnnualizedCost [$M2005]EmissionReduction(tons)CostEffectiveness[$2005/ton]LowestAnnualizedCost($M2005)HighestAnnualizedCost($M2005)LowestEmissionsReduced(tons)HighestEmissionsReduced(tons)CostEffectiveness($2005/ton)MNNorthshore/Silver Bay 1 Coal 85 851 LSD 90 CUECost 43,277,712 3,894 10,377 766 13,549 3,465 12,918 766 808 150-16041IPM17,737 808 3,465 766 4,524STAPPA -- --150-4000LSFO 95 CUECost 58,235 4,195 12,918 808 15,979IPM33,215 1,156 6,132 808 7,585STAPPA -- --200-5000Plant Total85 8513,465 12,918 766 808 922-16041State Facility Unit FuelCapacity(MW)BaselineEmissions(tons)ControlTechnology%Reduction Cost ModelTotal CapitalInvestment[$M2005]TotalO&M Cost[$M2005]TotalAnnualizedCost [$M2005]EmissionReduction(tons)CostEffectiveness[$2005/ton]LowestAnnualizedCost($M2005)HighestAnnualizedCost($M2005)LowestEmissionsReduced(tons)HighestEmissionsReduced(tons)CostEffectiveness($2005/ton)MNNorthshore/Silver Bay 1 Coal 85 1122 SCR 90 CUECost 11,870 849 2,627 1,010 2,602 322 2,627 16 40 200-2602IPM8,498 56 1,199 1,010 1,187STAPPA -- --1000-2000SNCR 35 CUECost 1,758 205 468393 1,192IPM2,160 32 322393 821STAPPA -- --800-1500LNB 35 CUECost 3,668 82 632393 1,609IPM2,546 39 381393 971STAPPA -- --200-1000NGR 55 CUECost 3,912 844 1,430 617 2,317IPM-- -617 -STAPPA -- --500-2000Plant Total85 1122322 2,627 16 40 821-2322Costs of SO2 Controls for EGUsCosts of NOx Controls for EGUsC-16Table C-9. Virginia Public Utilities Commission Facility (Minnesota)State Facility Unit FuelCapacity(MW)BaselineEmissions(tons)ControlTechnology%Reduction Cost ModelTotal CapitalInvestment[$M2005]TotalO&M Cost[$M2005]TotalAnnualized Cost[$M2005]EmissionReduction(tons)CostEffectiveness[$2005/ton]LowestAnnualizedCost($M2005)HighestAnnualizedCost($M2005)LowestEmissionsReduced(tons)HighestEmissionsReduced(tons)CostEffectiveness($2005/ton)MN Virginia PUC 7 Coal 10 584 LSD 90 CUECost 30,787 1,616 6,228525 11,859 6,228 8,933 525 554 150-16116IPM-- -525 -STAPPA -- --150-4000LSFO 95 CUECost 44,821 2,219 8,933554 16,116IPM-- -554 -STAPPA -- --200-50009 Coal 10 584 LSD 90 CUECost 30,787 1,616 6,228525 11,859 6,228 8,933 525 554 150-16116IPM-- -525 -STAPPA -- --150-4000LSFO 95 CUECost 44,821 2,219 8,933554 16,116IPM-- -554 -STAPPA -- --200-500010 Coal 10 12,606 LSD 90 CUECost 30,787 1,616 6,22811,346 5496,228 8,933 11,346 11,976 150-922IPM-- -11,346 -STAPPA -- --150-4000LSFO 95 CUECost 44,821 2,219 8,93311,976 -IPM-- -11,976 -STAPPA -- --200-5000Plant Total30 13,77318,684 26,800 12,396 13,085 1507-2048State Facility Unit FuelCapacity(MW)BaselineEmissions(tons)ControlTechnology%Reduction Cost ModelTotal CapitalInvestment[$M2005]TotalO&M Cost[$M2005]TotalAnnualized Cost[$M2005]EmissionReduction(tons)CostEffectiveness[$2005/ton]LowestAnnualizedCost($M2005)HighestAnnualizedCost($M2005)LowestEmissionsReduced(tons)HighestEmissionsReduced(tons)CostEffectiveness($2005/ton)MN Virginia PUC 7 Coal 10 125 SCR 90 CUECost 4,188 180 743113 6,589 143 743 44 113 200-9011IPM3,254 68 505113 4,481STAPPA -- --1000-2000SNCR 35 CUECost 1,259 115 284446,477IPM1,322 67 245445,584STAPPA -- --800-1500LNB 35 CUECost 91320 143443,264IPM-- -44-STAPPA -- -200-1000NGR 55 CUECost 2,270 316 621699,011IPM-- -69-STAPPA -- --500-20009 Coal 10 125 SCR 90 CUECost 4,188 180 743113 6,589 143 743 44 113 200-9011IPM3,254 68 505113 4,481STAPPA -- --1000-2000SNCR 35 CUECost 1,259 115 284446,477IPM1,322 67 245445,584STAPPA -- --800-1500LNB 35 CUECost 91320 143443,264IPM-- -44-STAPPA -- -200-1000NGR 55 CUECost 2,270 316 621699,011IPM-- -69-STAPPA -- --500-2000Costs of SO2 Controls for EGUsCosts of NOx Controls for EGUsC-17Table C-9. Virginia Public Utilities Commission Facility (Minnesota)State Facility Unit FuelCapacity(MW)BaselineEmissions(tons)ControlTechnology%Reduction Cost ModelTotal CapitalInvestment[$M2005]TotalO&M Cost[$M2005]TotalAnnualized Cost[$M2005]EmissionReduction(tons)CostEffectiveness[$2005/ton]LowestAnnualizedCost($M2005)HighestAnnualizedCost($M2005)LowestEmissionsReduced(tons)HighestEmissionsReduced(tons)CostEffectiveness($2005/ton)10 Coal 10 0 SCR 90 CUECost 4,188 180 7430-108 743 0 0 -IPM-- -0-STAPPA -- ---SNCR 35 CUECost 1,259 115 2840-IPM72011 1080-STAPPA -- ---LNB 35 CUECost 91320 1430-IPM-- -0-STAPPA -- ---NGR 55 CUECost 2,270 316 6210-IPM-- -0-STAPPA -- ---Plant Total30 251394 2,229 88 226 4495-9884C-18Table C-10. Dairyland Power Coop/Alma Facility (Wisconsin)State Facility Unit FuelCapacity(MW)BaselineEmissions(tons)ControlTechnology%Reduction Cost ModelTotal CapitalInvestment[$M2005]TotalO&M Cost[$M2005]TotalAnnualizedCost [$M2005]EmissionReduction(tons)CostEffectiveness[$2005/ton]LowestAnnualizedCost($M2005)HighestAnnualizedCost($M2005)LowestEmissionsReduced(tons)HighestEmissionsReduced(tons)CostEffectiveness($2005/ton)WI Dairyland1 Coal 18 1,384 LSD 90 CUECost 33,226 2,297 7,274 1,245 5,841 2,748 9,953 1,245 1,315 150-7571IPM12,606 859 2,748 1,245 2,206STAPPA - - - - 150-4000LSFO 95 CUECost 47,057 2,904 9,953 1,315 7,571IPM 25,663 1,101 4,945 1,315 3,762STAPPA - - - - 200-50002 Coal 18 1,165 LSD 90 CUECost 33,226 2,213 7,190 1,048 6,858 2,701 9,874 1,048 1,107 150-8922IPM 12,606 813 2,701 1,048 2,576STAPPA - - - - 150-4000LSFO 95 CUECost 47,057 2,825 9,874 1,107 8,922IPM 25,663 1,054 4,899 1,107 4,426STAPPA - - - - 200-50003 Coal 22 1,396 LSD 90 CUECost 34,312 2,416 7,556 1,256 6,016 2,986 10,284 1,256 1,326 150-7757IPM 13,805 918 2,986 1,256 2,378STAPPA - - - - 150-4000LSFO 95 CUECost 48,384 3,036 10,284 1,326 7,757IPM 27,487 1,184 5,302 1,326 3,999STAPPA - - - - 200-50004 Coal 57 2,415 LSD 90 CUECost 42,672 4,086 10,478 2,174 4,820 5,090 13,325 2,174 2,295 150-5807IPM 22,357 1,741 5,090 2,174 2,341STAPPA - - - - 150-4000LSFO 95 CUECost 57,570 4,701 13,325 2,295 5,807IPM 39,561 2,188 8,114 2,295 3,536STAPPA - - - - 200-50005 Coal 77 3,514 LSD 90 CUECost 43,802 4,382 10,944 3,163 3,460 6,175 14,097 3,163 3,338 150-4223IPM 26,064 2,271 6,175 3,163 1,953STAPPA - - - - 150-4000LSFO 95 CUECost 60,464 5,039 14,097 3,338 4,223IPM 44,421 2,798 9,453 3,338 2,832STAPPA - - - - 200-5000Plant Total 192 9,87419,701 57,533 8,886 9,380 2217-6134State Facility Unit FuelCapacity(MW)BaselineEmissions(tons)ControlTechnology% ReductionCost ModelTotal CapitalInvestment[$M2005]TotalO&M Cost[$M2005]TotalAnnualizedCost [$M2005]EmissionReduction(tons)CostEffectiveness[$2005/ton]LowestAnnualizedCost($M2005)HighestAnnualizedCost($M2005)LowestEmissionsReduced(tons)HighestEmissionsReduced(tons)CostEffectiveness($2005/ton)WI Dairyland1 Coal 18 316 SCR 90 CUECost 5,047 244 922285 3,238 152 1,336 111 285 200-7682IPM5,178 221 917285 3,223STAPPA -- --1000-2000SNCR 35 CUECost 1,301 146 321111 2,900IPM1,675 231 456111 4,119STAPPA -- --800-1500LNB 35 CUECost 97022 152111 1,373IPM1,214 31 194111 1,753STAPPA -- --200-1000NGR 55 CUECost 2,548 994 1,336 174 7,682IPM-- -174 -STAPPA -- --500-2000Costs of SO2 Controls for EGUsCosts of NOx Controls for EGUsC-19Table C-10. Dairyland Power Coop/Alma Facility (Wisconsin)State Facility Unit FuelCapacity(MW)BaselineEmissions(tons)ControlTechnology%Reduction Cost ModelTotal CapitalInvestment[$M2005]TotalO&M Cost[$M2005]TotalAnnualizedCost [$M2005]EmissionReduction(tons)CostEffectiveness[$2005/ton]LowestAnnualizedCost($M2005)HighestAnnualizedCost($M2005)LowestEmissionsReduced(tons)HighestEmissionsReduced(tons)CostEffectiveness($2005/ton)2 Coal 18 266 SCR 90 CUECost 5,047 242 920240 3,840 152 1,226 93 240 200-8370IPM5,178 192 888240 3,705STAPPA -- --1000-2000SNCR 35 CUECost 1,300 139 314933,369IPM1,675 198 423934,544STAPPA -- --800-1500LNB 35 CUECost 97022 152931,631IPM1,214 29 192932,061STAPPA -- --200-1000NGR 55 CUECost 2,548 883 1,226 146 8,370IPM-- -146 -STAPPA -- --500-20003 Coal 22 319 SCR 90 CUECost 5,662 290 1,051 287 3,662 173 1,411 112 287 200-8043IPM5,908 224 1,018 287 3,547STAPPA -- --1000-2000SNCR 35 CUECost 1,349 148 330112 2,953IPM1,792 234 475112 4,257STAPPA -- --800-1500LNB 35 CUECost 1,105 25 173112 1,552IPM1,363 33 216112 1,939STAPPA -- --200-1000NGR 55 CUECost 2,661 1,053 1,411 175 8,043IPM-- -175 -STAPPA -- --500-20004 Coal 57 773 SCR 90 CUECost 10,041 697 2,046 696 2,942 322 2,973 271 696 200-6993IPM11,888 479 2,076 696 2,985STAPPA -- --1000-2000SNCR 35 CUECost 1,700 227 456271 1,684IPM2,567 537 882271 3,259STAPPA -- --800-1500LNB 35 CUECost 2,051 46 322271 1,189IPM-- -271 -STAPPA -- --200-1000NGR 55 CUECost 3,418 2,513 2,973 425 6,993IPM-- -425 -STAPPA -- --500-20005 Coal 77 1,124 SCR 90 CUECost 11,907 922 2,522 1,012 2,492 391 4,119 394 1,012 200-6660IPM14,851 676 2,672 1,012 2,640STAPPA -- --1000-2000SNCR 35 CUECost 1,856 288 538394 1,366IPM2,880 787 1,174 394 2,984STAPPA -- --800-1500LNB 35 CUECost 2,494 56 391394 994IPM-- -394 -STAPPA -- -200-1000NGR 55 CUECost 3,775 3,611 4,119 618 6,660IPM-- -618 -STAPPA -- --500-2000Plant Total 192 2,7991,190 11,065 980 2,519 1556-4392C-20Table C-11. Xcel Energy/Bay Front Facility (Wisconsin)State Facility Unit FuelCapacity(MW)BaselineEmissions(tons)ControlTechnology%Reduction Cost ModelTotal CapitalInvestment[$M2005]TotalO&M Cost[$M2005]TotalAnnualizedCost [$M2005]EmissionReduction(tons)CostEffectiveness[$2005/ton]LowestAnnualizedCost($M2005)HighestAnnualizedCost($M2005)LowestEmissionsReduced(tons)HighestEmissionsReduced(tons)CostEffectiveness($2005/ton)WI Xcel Energ1 Coal 22 1,890 LSD 90 CUECost 37,322 2,701 8,291 1,701 4,876 2,953 11,074 1,701 1,795 150-6169IPM13,843 879 2,953 1,701 1,736STAPPA -- --150-4000LSFO 95 CUECost 51,934 3,294 11,074 1,795 6,169IPM27,544 1,146 5,272 1,795 2,937STAPPA -- --200-50002 Coal 22 1,890 LSD 90 CUECost 36,222 2,666 8,092 1,701 4,758 2,992 10,865 1,701 1,795 150-6053IPM13,843 919 2,992 1,701 1,760STAPPA -- --150-4000LSFO 95 CUECost 50,684 3,272 10,865 1,795 6,053IPM27,544 1,186 5,312 1,795 2,959STAPPA -- --200-50005 Coal 30 1,478 LSD 90 CUECost 36,662 2,553 8,045 1,330 6,047 3,457 10,888 1,330 1,404 150-7753IPM16,182 1,033 3,457 1,330 2,598STAPPA -- --150-4000LSFO 95 CUECost 51,173 3,222 10,888 1,404 7,753IPM30,991 1,348 5,991 1,404 4,266STAPPA -- --200-5000Plant Total74 5,2579,402 32,826 4,731 4,994 1987-6573State Facility Unit FuelCapacity(MW)BaselineEmissions(tons)ControlTechnology%Reduction Cost ModelTotal CapitalInvestment[$M2005]TotalO&M Cost[$M2005]TotalAnnualizedCost [$M2005]EmissionReduction(tons)CostEffectiveness[$2005/ton]LowestAnnualizedCost($M2005)HighestAnnualizedCost($M2005)LowestEmissionsReduced(tons)HighestEmissionsReduced(tons)CostEffectiveness($2005/ton)WI Xcel Energ1 Coal 22 509 SCR 90 CUECost 7,479 443 1,448 458 3,163 173 1,777 178 458 200-6350IPM5,932 199 996458 2,175STAPPA - - - - 1000-2000SNCR 35 CUECost 1,518 192 396178 2,223IPM1,796 206 447178 2,510STAPPA - - - - 800-1500LNB 35 CUECost 1,105 25 173178 973IPM-- -178 -STAPPA - - - - 200-1000NGR 55 CUECost 2,661 1,419 1,777 280 6,350IPM - - - 280 -STAPPA - - - - 500-20002 Coal 22 447 SCR 90 CUECost 6,757 384 1,292 402 3,213 173 1,777 156 402 200-7227IPM 5,932 223 1,021 402 2,537STAPPA - - - - 1000-2000SNCR 35 CUECost 1,437 168 361156 2,310IPM1,796 233 475156 3,036STAPPA - - - - 800-1500LNB 35 CUECost 1,105 25 173156 1,107IPM-- -156 -STAPPA - - - - 200-1000Costs of SO2 Controls for EGUsCosts of NOx Controls for EGUsC-21Table C-11. Xcel Energy/Bay Front Facility (Wisconsin)State Facility Unit FuelCapacity(MW)BaselineEmissions(tons)ControlTechnology%Reduction Cost ModelTotal CapitalInvestment[$M2005]TotalO&M Cost[$M2005]TotalAnnualizedCost [$M2005]EmissionReduction(tons)CostEffectiveness[$2005/ton]LowestAnnualizedCost($M2005)HighestAnnualizedCost($M2005)LowestEmissionsReduced(tons)HighestEmissionsReduced(tons)CostEffectiveness($2005/ton)NGR 55 CUECost 2,661 1,419 1,777 246 7,227IPM-- -246 500-2000STAPPA -- --1,2855 Coal 30 517 SCR 90 CUECost 7,216 411 1,381 466 2,966 212 1,505 181 466 200-5287IPM7,439 229 1,229 466 2,640STAPPA -- --1000-2000SNCR 35 CUECost 1,515 188 392181 2,165IPM1,582 419 631181 3,486STAPPA -- --800-1500LNB 35 CUECost 1,352 30 212181 1,170IPM-- -181 -STAPPA -- -181 200-1000NGR 55 CUECost 2,862 1,120 1,505 285 5,287IPM-- -285 -STAPPA -- --500-2000Plant Total74 1,473558 5,058 516 1,326 1083-3815C-22Table C-12. Alliant Energy-Wisconsin Power/Edgewater Facility (Wisconsin)State Facility Unit FuelCapacity(MW)BaselineEmissions(tons)ControlTechnology%Reduction Cost ModelTotal CapitalInvestment[$M2005]TotalO&M Cost[$M2005]TotalAnnualizedCost [$M2005]EmissionReduction(tons)CostEffectiveness[$2005/ton]LowestAnnualizedCost($M2005)HighestAnnualizedCost($M2005)LowestEmissionsReduced(tons)HighestEmissionsReduced(tons)CostEffectiveness($2005/ton)WI Alliant Ener3 Coal 751,864LSD 90 CUECost 47,351 5,328 12,421 1,677 7,406 5,955 14,711 1,677 1,770 150-8310IPM 25,747 2,098 5,955 1,677 3,550STAPPA -- -- 150-4000LSFO 95 CUECost 60,864 5,593 14,711 1,770 8,310IPM 44,012 2,618 9,211 1,770 5,203STAPPA -- -- 200-50004 Coal 334 8,277 LSD 90 CUECost 86,380 17,366 30,306 7,449 4,068 17,153 31,414 7,449 7,863 150-4068IPM 63,174 7,690 17,153 7,449 2,303STAPPA -- -- 150-4000LSFO 95 CUECost 98,542 16,653 31,414 7,863 3,995IPM 91,600 8,963 22,684 7,863 2,885STAPPA -- -- 200-50005 Coal 42210,672LSD 90 CUECost 87,931 13,842 27,014 9,605 2,813 19,892 30,888 9,605 10,138 150-3047IPM 73,892 8,823 19,892 9,605 2,071STAPPA -- -- 150-4000LSFO 95 CUECost 107,638 14,764 30,888 10,138 3,047IPM 101,846 10,432 25,689 10,138 2,534STAPPA -- -- 200-5000Plant Total 831 20,81243,000 77,013 18,731 19,771 2296-3895State Facility Unit FuelCapacity(MW)BaselineEmissions(tons)ControlTechnology%Reduction Cost ModelTotal CapitalInvestment[$M2005]TotalO&M Cost[$M2005]TotalAnnualizedCost [$M2005]EmissionReduction(tons)CostEffectiveness[$2005/ton]LowestAnnualizedCost($M2005)HighestAnnualizedCost($M2005)LowestEmissionsReduced(tons)HighestEmissionsReduced(tons)CostEffectiveness($2005/ton)WI Alliant Ener3 Coal 75865SCR 90 CUECost 11,459 844 2,384 779 3,061 497 3,501 303 779 200-7355IPM 14,589 590 2,550 779 3,275STAPPA -- -- 1000-2000SNCR 35 CUECost 1,815 253 497303 1,641IPM 2,337 1,233 1,547 303 5,109STAPPA -- -- 800-1500LNB 35 CUECost 3,382 76 530303 1,751IPM -- -303 -STAPPA -- -- 200-1000NGR 55 CUECost 3,743 2,998 3,501 476 7,355IPM -- -476 -STAPPA -- -- 500-20004 Coal 3343,285SCR 90 CUECost 28,738 3,183 7,045 2,957 2,383 1,232 14,090 1,150 2,957 200-7797IPM 43,182 2,370 8,174 2,957 2,764STAPPA -- -- 1000-2000SNCR 35 CUECost 3,322 785 1,232 1,150 1,071IPM 4,382 6,012 6,601 1,150 5,741STAPPA -- -- 800-1500Costs of SO2 Controls for EGUsCosts of NOx Controls for EGUsC-23Table C-12. Alliant Energy-Wisconsin Power/Edgewater Facility (Wisconsin)State Facility Unit FuelCapacity(MW)BaselineEmissions(tons)ControlTechnology%Reduction Cost ModelTotal CapitalInvestment[$M2005]TotalO&M Cost[$M2005]TotalAnnualizedCost [$M2005]EmissionReduction(tons)CostEffectiveness[$2005/ton]LowestAnnualizedCost($M2005)HighestAnnualizedCost($M2005)LowestEmissionsReduced(tons)HighestEmissionsReduced(tons)CostEffectiveness($2005/ton)LNB 35 CUECost 8,929 200 1,400 1,150 1,218IPM -- -1,150 -STAPPA -- -- 200-1000NGR 55 CUECost 8,058 13,007 14,090 1,807 7,797IPM -- -1,807 -STAPPA -- -- 500-20005 Coal 4221,971SCR 90 CUECost 33,963 3,698 8,263 1,774 4,659 863 16,789 690 1,774 200-15491IPM 51,214 2,727 9,610 1,774 5,419STAPPA -- -- 1000-2000SNCR 35 CUECost 3,533 388 863690 1,251IPM 5,481 3,792 4,529 690 6,566STAPPA -- -- 800-1500LNB 35 CUECost 7,536 169 1,182 690 1,713IPM -- -690 -STAPPA -- -- 200-1000NGR 55 CUECost 9,791 15,474 16,789 1,084 15,491IPM -- -1,084 -STAPPA -- -- 500-2000Plant Total 831 6,1212,592 34,380 2,142 5,509 1210-6240C-24Table C-13. Alliant Energy-Wisconsin Power/Nelson Dewey Facility (Wisconsin)State Facility Unit FuelCapacity(MW)BaselineEmissions(tons)ControlTechnology%Reduction Cost ModelTotal CapitalInvestment[$M2005]TotalO&M Cost[$M2005]TotalAnnualizedCost [$M2005]EmissionReduction(tons)CostEffectiveness[$2005/ton]LowestAnnualizedCost($M2005)HighestAnnualizedCost($M2005)LowestEmissionsReduced(tons)HighestEmissionsReduced(tons)CostEffectiveness($2005/ton)WI Alliant Energy/N1 Coal 108 4,206 LSD 90 CUECost 54,250 8,018 16,145 3,786 4,265 8,642 17,324 3,786 3,996 150-4335IPM36,950 3,107 8,642 3,786 2,283STAPPA - - - - 150-4000LSFO 95 CUECost 66,535 7,357 17,324 3,996 4,335IPM 60,457 3,864 12,921 3,996 3,233STAPPA - - - - 200-50002 Coal 111 4,127 LSD 90 CUECost 54,432 7,949 16,103 3,714 4,336 8,738 17,320 3,714 3,920 150-4418IPM 37,434 3,131 8,738 3,714 2,353STAPPA - - - - 150-4000LSFO 95 CUECost 66,701 7,328 17,320 3,920 4,418IPM 61,054 3,898 13,044 3,920 3,327STAPPA - - - - 200-5000Plant Total219 8,33317,381 17,320 7,500 7,916 2318-2199State Facility Unit FuelCapacity(MW)BaselineEmissions(tons)ControlTechnology%Reduction Cost ModelTotal CapitalInvestment[$M2005]TotalO&M Cost[$M2005]TotalAnnualizedCost [$M2005]EmissionReduction(tons)CostEffectiveness[$2005/ton]LowestAnnualizedCost($M2005)HighestAnnualizedCost($M2005)LowestEmissionsReduced(tons)HighestEmissionsReduced(tons)CostEffectiveness($2005/ton)WI Alliant Energy/N1 Coal 108 1,262 SCR 90 CUECost 14,058 1,159 3,049 1,136 2,684 487 4,904 442 1,136 200-7066IPM18,912 849 3,391 1,136 2,986STAPPA - - - - 1000-2000SNCR 35 CUECost 2,033 326 599 442 1,357IPM 2,716 1,871 2,236 442 5,063STAPPA - - - - 800-1500LNB 35 CUECost 3,108 70 487 442 1,103IPM - - - 442 -STAPPA - - - - 200-1000NGR 55 CUECost 4,294 4,327 4,904 694 7,066IPM - - - 694 -STAPPA - - - - 500-20002 Coal 111 1,238 SCR 90 CUECost 14,135 1,161 3,061 1,114 2,747 496 4,830 433 1,114 200-7093IPM 19,272 850 3,440 1,114 3,087STAPPA - - - - 1000-2000SNCR 35 CUECost 2,039 322 596 433 1,375IPM 2,746 1,871 2,240 433 5,171STAPPA - - - - 800-1500LNB 35 CUECost 3,163 71 496 433 1,145IPM - - - 433 -STAPPA - - - - 200-1000NGR 55 CUECost 4,343 4,246 4,830 681 7,093IPM - - - 681 -STAPPA - - - - 500-2000Plant Total219 2,500983 9,734 875 2,250 1124-4326Costs of SO2 Controls for EGUsCosts of NOx Controls for EGUsC-25Table C-14. Boise Cascade Corporation (Minnesota)State FacilityUnit FuelCapacity(MW)BaselineEmissions(tons)ControlTechnology%Reduction Cost ModelTotal CapitalInvestment[$M2005]Total O&MCost[$M2005]TotalAnnualizedCost [$M2005]EmissionReduction(tons)CostEffectiveness[$2005/ton]LowestAnnualizedCost ($M2005)HighestAnnualizedCost($M2005)LowestEmissionsReduced(tons)HighestEmissionsReduced(tons)CostEffectiveness($2005/ton)MI Boise Cascade Corp. 2 Gas 38 48 LSD 90 CUECost 51,688 3,169 10,912 43 254,398 3,966 10,912 43 45 92472-242492IPM 18,130 1,373 4,089 43 95,333Khan (2003)* 17,294 1,376 3,966 43 92,472STAPPA ---- 1,011LSFO 95 CUECost 32,346 2,199 7,044 45 155,586IPM 33,769 1,730 6,789 45 149,938Khan (2003)* 17,294 1,376 3,966 45 87,605STAPPA ---- 1,011Plant Total38 483,966 10,912 43 45 92472-242492State FacilityUnit FuelCapacity(MW)BaselineEmissions(tons)ControlTechnology%Reduction Cost ModelTotal CapitalInvestment[$M2005]Total O&MCost[$M2005]TotalAnnualizedCost [$M2005]EmissionReduction(tons)CostEffectiveness[$2005/ton]LowestAnnualizedCost ($M2005)HighestAnnualizedCost($M2005)LowestEmissionsReduced(tons)HighestEmissionsReduced(tons)CostEffectiveness($2005/ton)MI Boise Cascade Corp. 1 Gas 38 104 SCR 80 CUECost 7,076 398 1,349 84 16,146 1202,769 37 81 424-43450IPM 2,768 129 50184 5,990Khan (2003)* 2,485 238 57284 6,847STAPPA ---- 1,354SNCR 50 CUECost 1,366 116 29952 5,733IPM 1,353 219 40152 7,678Khan (2003)* 1,307 299 47552 9,094STAPPA ---- 2,193LNB 35 CUECost 2,174 49 34137 9,322IPM 1,023 213937 3,805Khan (2003)* 792 61 16737 4,569STAPPA ---424NGR 61 CUECost 3,041 2,360 2,769 64 43,450IPM ---64 -Khan (2003)* 446 61 12064 1,891STAPPA ---- -Costs of SO2 Controls for ICIsCosts of NOx Controls for ICIsC-26Table C-14. Boise Cascade Corporation (Minnesota)State FacilityUnit FuelCapacity(MW)BaselineEmissions(tons)ControlTechnology%Reduction Cost ModelTotal CapitalInvestment[$M2005]Total O&MCost[$M2005]TotalAnnualizedCost [$M2005]EmissionReduction(tons)CostEffectiveness[$2005/ton]LowestAnnualizedCost ($M2005)HighestAnnualizedCost($M2005)LowestEmissionsReduced(tons)HighestEmissionsReduced(tons)CostEffectiveness($2005/ton)2 Gas 38 331 SCR 90 CUECost 7,331 421 1,406 265 5,307 1691,406 116 291 424-27803IPM 2,749 127 497265 1,875Khan (2003)* 2,511 241 579265 2,185STAPPA ---- 1,354SNCR 35 CUECost 1,448 159 354166 2,137IPM 1,347 217 398166 2,401Khan (2003)* 1,321 304 482166 2,908STAPPA ---- 2,193LNB 35 CUECost 2,159 48 33937 9,258IPM 21,016 1,017 37 27,803Khan (2003)* 801 61 16937 4,623STAPPA ---4243 Gas 35 25 SCR 90 CUECost 6,669 361 1,257 20 62,895 1171,652 9 19 797-108392IPM 2,624 97 45020 22,500Khan (2003)* 2,413 230 55420 27,716STAPPA ---- 2,330SNCR 35 CUECost 1,322 101 27912 22,303IPM 1,307 96 27112 21,728Khan (2003)* 1,269 287 45812 36,626STAPPA ---- 3,116LNB 35 CUECost 2,061 46 3239 36,942IPM 1,550 28 2369 27,018Khan (2003)* 769 58 1629 18,501STAPPA797NGR 61 CUECost 2,975 1,252 1,652 15 108,392IPM ---15 -Khan (2003)* 433 58 11715 7,648STAPPA ---- -Plant Total76 4364065,827 161 392 2519-14849* "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-27APC 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-28Table 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-29Table 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-30Table 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-31Table 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-3EGU 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-1State 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-22002 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 SO 2 

# and NO X 

# 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-19Appendix B-1. Control Strategies for Mobile SourcesTechnologyProcesses CoveredEstimated NOX ControlEfficiency Notes Reference1993 to 1998 MHDDV24% reduction in tailpipeemissionsa1, 21993 to 1998 HHDDV24% reduction in tailpipeemissionsa1, 21995 and older enhanced IM tailpipetest8-9% annual inventoryreductionb, c31996 and newer OBDII equippedgasoline vehicles0.1 gram/mile reduction forpost-repair vehiclesb 41997 and newer OBDII equipped lightdutydiesel vehicles0.6% reduction in tailpipeemissionsb 52007 and newer heavy-duty dieseltrucks(on the books)6Smoking vehicles (identification,repair, and/or replace)up to 53% decrease in NOXemissions for all vehiclesparticipatingin theprogramaa 1, 21Use 7.0 RVP fuel in urban areas; e.g., Detroit area LDGV26Fuel Switching: Biodiesel B100 HDDV +10% pre-1998, +30% 98-04increase in tailpipe emissionsd 7Fuel Switching: Biodiesel B20 HDDV +2% pre-1998, +4% 98-04increase in tailpipe emissionse 7Low NOX Calibration/Reflashing. Adopt regulations similar to the CARBLow NOx Software Upgrade program with a set phase in schedule that wouldrequire all low NOx rebuild engines to have low NOx rebuild kit installed by2009.Emissions Inspections Program. Implement a State emissions inspectionprogram 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 natural gas.(*Recommendation may be restricted to fuels already available in the Petroleum Administration for Defense District.)B-1Appendix B-1. Control Strategies for Mobile SourcesTechnologyProcesses CoveredEstimated NOX ControlEfficiency Notes ReferenceFuel Switching: Biodiesel B20Bulldozer, Motor Graderunknownf8Fuel Switching: Biodiesel B30Bulldozer, Motor Graderunknowng8Fuel Switching: Biodiesel B20Locomotive (line haul or switching) +5-6% increase in tailpipeemissionsh 9Fuel Switching: Biodiesel B20Marine Port applicationsunknowni10Locomotive (line haul or switching) 1-2% reduction in tailpipeemissionsh, j 9Harbor craft15% inventoryreductionk18Large deepdraft marine vessels15% inventoryreductionk18Harbor craft(ferries, tugs)15% inventoryreductionk18Large deepdraft marine vessels15% inventoryreductionk18Increase use of E10LDGV+5% increase in tailpipeemissionsl 11, 12Fuel Switching: Convert public fleets to Flex Fuel Vehicles fueled with E85. LDGVtailpipe control efficiencyunavailablel 12Fuel Switching: LNG or CNGLDGV60% reduction in tailpipeemissions13Fuel Switching: LNGLocomotive (line haul or switching) tailpipe control efficiencyunavailable14Fuel Switching: LNG or CNGMDGV, HDGV50% reduction in tailpipeemissions131993 to 1998 MHDDVunknownm,n1Switching locomotives50% reduction in tailpipeemissionso 1Line-haul locomotives 75% reduction in tailpipeemissionso 1[continued]Use lower sulfur fuel: CARB Diesel*Use lower sulfur fuel: Highway or ULSD*Anti-Idling. Reduce idling emissions from heavy-duty diesel trucks andlocomotives using truck stop electrification and locomotive anti-idlingtechnology.B-2Appendix B-1. Control Strategies for Mobile SourcesTechnologyProcesses CoveredEstimated NOX ControlEfficiency Notes ReferenceUpgrade to 1990 EngineMY 1989 and earlier HDDV 43% reductionp1MY 1989 and earlier HDDV 63% reductionp1MY 1990 HDDV33% reductionp1MY 1991-1997 HDDV20% reductionp1MY 1989 and earlier HDDV 78% reductionp1MY 1990 HDDV66% reductionp1MY 1991-1997 HDDV52% reductionp1MY 1998-2001 HDDV95% reductionp1MY 2002-2006 HDDV92% reductionp1Upgrade construction and agricultural equipment to Tier 2, 3, or 4Excavators, Rubber Tire Loaders,Crawler Tractors/Dozers,Tractors/Loaders/Backhoes, OffHighway Trucks, Agricultural Tractors,CombinesDependent on model year andhorsepower. See Reference11 for engine standardschematic.1, 15Fleet turnover to 2007 and newer engines(On the books)HDDVunknown[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 EngineB-3Appendix B-1. Control Strategies for Mobile SourcesTechnologyProcesses CoveredEstimated NOX ControlEfficiency Notes ReferenceMYpre-1989 through 2006 HDDV upto 80% reduction1, 16Excavators, Rubber Tire Loaders,Crawler Tractors/Dozers,Tractors/Loaders/Backhoes, OffHighwayTrucksup to 80% reduction1, 16Locomotive(line haul or switching)90% reduction16Agricultural Tractors, Combines upto 80% reductionq1, 16Lean NOX Catalyst(LNC)combined with Diesel Particulate Filter(DPF)MYpre-1989 through 2006 HDDV 15-25% reductionr1, 16Excavators, Rubber Tire Loaders,Crawler Tractors/Dozers,Tractors/Loaders/Backhoes, OffHighwayTrucks15-25% reduction1, 17Agricultural Tractors, Combines 15-25% reduction1, 16Excavators, Rubber Tire Loaders,Crawler Tractors/Dozers,Tractors/Loaders/Backhoes, OffHighwayTrucksup to 50% reductions 1, 16Agricultural Tractors, Combines upto 50% reductions 1, 16Excavators, Rubber Tire Loaders,Crawler Tractors/Dozers,Tractors/Loaders/Backhoes, OffHighwayTrucksup to 80% reductiont 1, 16Agricultural Tractors, Combines upto 80% reductiont 1, 16Excavators, Rubber Tire Loaders,Crawler Tractors/Dozers,Tractors/Loaders/Backhoes, OffHighway Trucksup to 80% reductionu 1, 16Agricultural Tractors, Combines upto 80% reductionu 1, 16[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 vehicles and off-roadconstruction, cargo-handling, and marine equipment.B-4Appendix B-2. Control Strategies for EGUsTechnologyProcesses CoveredEfficiency of ControlNotes ReferenceBaseline and On-the-books regional programsBaseline 2002: (MRPO average SO2 is 1.16 lbs/mmBtu, NOx is0.43 lbs/mmBtu): NSPS; PSD/NSR; State RACT Rules; Title IVSO2 ProgramEGUs MRPO average SO2 is 1.16lbs/mmBtu, NOx is 0.43 lbs/mmBtubb 192009 On-the-Books measures: CAIREGUsEPA CAIR levels are estimated at0.13 lbs/mmBtu NOX and 0.26lbs/mmBtu SO2 in 2015.bb 19, 222009 On-the-Books measures: CAIR -- Michigan ImpactsEGUsEPA estimates a 10% reduction inSO2 and a 29% reduction in NOXfrom 2003 levels.bb232009 On-the-Books measures: CAIR -- Minnesota ImpactsEGUsEPA estimates a 36% reduction inSO2 and a 59% reduction in NOXfrom 2003 levels.bb242009 On-the-Books measures: CAIR -- Wisconsin ImpactsEGUsEPA estimates a 32% reduction inSO2 and a 61% reduction in NOXfrom 2003 levels.bb25Additional regionalprogramsAdopt Emission Caps Based on “Retrofit SO2 BACT Level” of0.15 lbs/mmBtu by 2013 (with Interim Cap Based on 0.36lbs/mmBtu in 2009)EGUs Additional 0.11 lbs/mmBtu reductionin SO2 from original CAIR emissionscapv 19Adopt Emission Caps Based on “Retrofit NOx BACT Level” of0.10 lbs/mmBtu by 2013 (with Interim Cap Based on 0.15lbs/mmBtu in 2009)EGUsAdditional 0.03 lbs/mmBtu reductionin NOX from original CAIRemissions cap19Adopt Emission Caps Based on “SO2 BACT Level for NewPlants” of 0.10 lbs/mmBtu by 2013 (with Interim Cap Based on0.24 lbs/mmBtu in 2009)EGUs Additional 0.16 lbs/mmBtu reductionin SO2 from original CAIR emissionscapw 19Adopt Emission Caps Based on “NOx BACT Level for NewPlants” of 0.07 lbs/mmBtu by 2013 (with Interim Cap Based on0.12 lbs/mmBtu in 2009)EGUs Additional 0.06 lbs/mmBtu reductionin NOX from original CAIRemissions cap19Replace old boilers to boost efficiency by 50-60% EGUs Not Available 19Implement Consumer Education programs to promote energyefficiencyand reduce demand.Not Available19B-5Appendix B-2. Control Strategies for EGUsTechnologyProcesses CoveredEfficiency of ControlNotes ReferenceFuel OptionsUse fuel oil with a sulfur content of 0.05% or less for all boilersizes (<50 - >250 MmBtu/hr)#1 and #2 fuel oil26Use fuel oil with a sulfur content of 0.5% or less#4 and #6 fuel oil26Use coal with low sulfur contentCoal for units between 50-100mmBtu/hr2.0 lb/MmBtu or 30% SO2 reduction26Use coal with low sulfur content Coal for units between 100-250mmBtu/hr1.2 lb/MmBtu or 85% SO2 reduction26Use coal with low sulfur contentCoal for units >250 MmBtu/hr0.25 lb/MmBtu or 85% SO2 reduction 26Retrofit Technologies for individual emission unitsBurner ModificationsMost units10 to 30% NOx reduction19Fuel ReburnMost units. Furnace height (residencetime) may restrict some applications20 to 30% NOx reduction for FuelLean Gas Reburning (no OFA), and30 to 60% reduction for conventionalreburning.19Hydrocarbon-enhanced SNCRMost units. Can use more NH3 withless slip.40 to 60% NOx reduction 19Low-NOx BurnersMost boilers alreadyhave LNB. 30 to 50% NOx reduction19Overfire AirMost units. Furnace height may restrictsome applications20 to 40% NOx reduction 19Oxygen-enhanced combustion modificationBest applied with new OFA systemdesigned to achieve stoichiometric airfuel ratio < 0.8.30-50% beyond OFA19Rich Reagent InjectionMost units. Modeling required todetermine injection locations.20 to 30% additional NOx reductionbeyond OFA.19Selective Catalytic Reduction (SCR) Most units. Space availability mayconstrain some options. High sulfurfuels more challenging70 to 90+% NOx reduction19Selective Non-catalytic Reduction (SNCR)Most units. Residence time andtemperature characteristics areimportant25 to 50% NOx reduction, dependingon the furnace temperature and timefor reaction.19[continued]B-6Appendix B-2. Control Strategies for EGUsTechnologyProcesses CoveredEfficiency of ControlNotes ReferencePhysical Coal CleaningAvailable for all units10-40% SO2 reduction19Chemical Coal CleaningAvailable for all units50-85% SO2 reduction19Switch to Low Sulfur CoalAvailable for all units50-80% SO2 reduction19Limestone forced oxidation system (LSFO)Generally used for >100 MW unitsunits firing high-sulfur (>2 percent)bituminous coals.52 – 98% reduction in SO2, withmedian reduction of 90%; EPA used95% in CAIR analysis19Magnesium enhanced lime system (MEL) Generally used for 100-550 MW unitsunits firing low-sulfur (<2 percent)bituminous, sub-bituminous, and lignitecoals.52 – 98% reduction in SO2, withmedian reduction of 90%; EPA used96% for CAIR analysis19Lime spray dryer system (LSD) Can be used for both low-and highsulfur coals, depending on theeconomics of each application.70 - 96% reduction in SO2, withmedian reduction of 90%; EPA used90% for CAIR analysis19Dryor wet FGDCoal-burningunits >250 mmBtu/hr 90% SO2 reduction26Combustion TuningAll units 50-100 mmBtu/hr5-35% NOX reduction26[continued]B-7Appendix B-3. Control Strategies for ICI BoilersTechnologyProcesses CoveredEfficiency of Control (% atthe unit) Notes ReferenceBaseline and On-the-books regionalprogramsBaseline 2002: NSPS; PSD/NSR; State RACT Rules ICI BoilersNAbb 202009 On-the-Books (OTB) measures: Enforcement settlementsand Alcoa announced scrubbersICI Boilers18% SO2 reduction from2002 levelsbb 202009 OTB measures: NOx SIP Call for large boilers,enforcement settlementsICI Boilers3% NOX reduction from2002 levelsbb 20Additional regionalprogramsOTB measures plus 40% SO2 Reduction and 60% Reduction(similar to NOx SIP Call) to All Medium and Large ICI BoilersICI Boilers29% SO2 reduction and19% NOX reduction from2002 levelsx 20OTB Measures plus Likely Controls to ICI Boilers subject to theproposed BART requirements Emission Reductions.ICI Boilers8% NOX reduction and40% SO2 reduction from2002 levelsy 20OTB Measures plus 90% SO2 Reduction and 80% NOXreduction (similar to BART) to All Medium and Large ICIBoilers Emission Reductions.ICI Boilers66% SO2 reduction and31% NOX reduction from2002 levelsz 20Fuel OptionsUse fuel oil with a sulfur content of 0.05% or less for all boilersizes(<50 - >250 MmBtu/hr)#1 and #2 fuel oil26Use fuel oil with a sulfur content of 0.5% or less#4 and #6 fuel oil26Use coal with low sulfur contentCoal for units between 50-100mmBtu/hr2.0 lb/MmBtu or 30% SO2reduction26Use coal with low sulfur contentCoal for units between 100-250mmBtu/hr1.2 lb/MmBtu or 85% SO2reduction26Use coal with low sulfur contentCoal for units >250 MmBtu/hr0.25 lb/MmBtu or 85%SO2 reduction26B-8Appendix B-3. Control Strategies for ICI BoilersTechnologyProcesses CoveredEfficiency of Control (% atthe unit) Notes ReferenceRetrofit Technologies for individual emission unitsLNB (Low NOX Burner)Coal Sub-bituminous fueled boiler 51% NOX reduction20Coal Sub-bituminous fueled boiler 65% NOX reduction20Coal Bituminous fueled boiler 51% NOX reduction20Gas fueled boiler60% NOX reduction20Oil fueled boiler30% NOX reduction20LNB + OFA + FGR(Flue Gas Recirculation)Gas fueled boiler80% NOX reduction20, 26LNB + OFA + FGR(0.5 lbs/mmBtu inlet NOx)Oil fueled boiler50% NOX reduction20, 26Coal fueled boiler80% NOX reduction20, 26Gas fueled boiler80% NOX reduction20, 26Oil fueled boiler80% NOX reduction20, 26Coal fueled boiler40% NOX reduction20, 26Oil fueled boiler40% NOX reduction20, 26Wood/Non-fossil solid fuel not available26Gas fueled boiler40% NOX reduction20Coal High Sulfur fueled boiler 40% SO2 reduction20Coal Low Sulfur fueled boiler 40% SO2 reduction20SDACoal fueled boiler90% SO2 reduction20Coal High Sulfur fueled boiler 90% SO2 reduction20Coal Low Sulfur fueled boiler 90% SO2 reduction20Oil fueled boiler90% SO2 reduction20Water InjectionGas fueled boiler75% NOX reduction26[continued]LNB + OFA (Over-fire air)In-duct Dry Sorbent Injection (IDSI)Wet FGDSNCRSCRB-9Control MeasureSources CoveredEstimated Efficiency(%) Notes ReferencesLow-Emission CombustionInternal Combustion80-90% reduction27Prestratified ChargeInternal Combustion75-90% reduction27High Energy/Plasma Ignition SystemsInternal Combustion80% reductioncc 27SCONOx TechnologyInternal Combustion95% reductiondd 27NOxTech SystemInternal Combustion90-95% reduction27High-pressure Fuel InjectionInternal Combustion80% reduction27Air Fuel w/Ignition RetardInternal Combustion - Gas53 tons/30% reduction hh28, 29Air Fuel w/Ignition RetardIC Engines - Gas53 tons/30% reduction hh28, 29Air Fuel Ratio AdjustmentInternal Combustion - Gas36 tons/20% reduction hh28, 29Air Fuel Ratio AdjustmentIC Engines - Gas38 tons/20% reduction hh28, 29Ignition RetardIC Engine - Oil6 tons/25% reduction hh28, 29Ignition RetardIC Engines - Gas, Diesel, LPG 9 tons/25% reduction hh28, 29L-E(Low Speed)IC Engine - Gas148 tons/87% reduction hh28, 29L-E(Medium Speed)IC Engine - Gas98 tons/87% reduction hh28, 29NSCRIC Engine - Oil19 tons/90% reduction ee, hh 27, 28, 29NSCRIC Engine - Gas, Diesel, LPG26 tons/90% reduction ff, hh27, 28, 29SCRIC Engine - Gas150 tons/90% reductiongg, hh27, 28, 29SCRIC Engine - Gas, Diesel, LPG23 tons/80% reduction hh27, 28, 29SCRIC Engine - Oil17 tons/80% reduction hh27, 28, 29Appendix B-4. Control Strategies for Reciprocating EnginesB-10Control MeasureSources CoveredEstimated Efficiency(%) Notes ReferencesExternal Flue Gas Recirculation TurbineN/Aii 30Overfire AirTurbineN/A30Low NOx BurnersTurbine25-50% reduction30Selective Catalytic Reduction (High Dust) Turbine70-90% control efficiency ii 30Selective Catalytic Reduction (Low Dust) Turbine80-90% control efficiency30Selective Non-Catalytic ReductionTurbine25-50% control efficiency30Low Temperature Oxidation(Tri-NOx)Turbine99% control efficiency30Low Temperature Oxidation (LoTox) Turbine80-95% control efficiency30Non Selective Catalytic ReductionTurbineN/Aii 30Novel Multi-Pollutant Controls (ElectroCatalytic Oxidation)TurbineN/A30Novel Multi-Pollutant Controls (PahlmanProcess)TurbineN/Aii 30SCONOx TechnologyGas Turbines95% reduction27DryLow NOx CombusterCombustion Turbines - Natural Gas 102 tons/50% reduction hh28, 29DryLow NOx CombusterCombustion Turbines - Natural Gas 102 tons/84% reduction hh28, 29SCR w/Low NOx BurnerCombustion Turbines - Natural Gas 143 tons/94% reduction hh28, 29SCR w/Steam InjectionCombustion Turbines - Natural Gas 145 tons/95% reduction hh28, 29SCR w/Water InjectionCombustion Turbines - Natural Gas 145 tons/95% reduction hh28, 29SCR w/Water InjectionCombustion Turbines - Oil31 tons/90% reduction hh28, 29SCR w/Water InjectionCombustion Turbines - Jet Fuel 13 tons/90% reduction hh28, 29Steam InjectionCombustion Turbines - Natural Gas 119 tons/80% reduction hh28, 29Water InjectionCombustion Turbines - Natural Gas 112 tons/76% reduction hh28, 29Water InjectionCombustion Turbines - Oil23 tons/68% reduction hh28, 29Water InjectionCombustion Turbines - Jet Fuel 10 tons/68% reduction hh28, 29DryLow NOx CombusterCombustion Turbines - Natural Gas 102 tons/50% reduction hh28, 29DryLow NOx CombusterCombustion Turbines - Natural Gas 102 tons/84% reduction hh28, 29Appendix B-5. Control Strategies for TurbinesB-11Appendix B-6. Control Strategies for AmmoniaControl MeasureSources CoveredEstimatedEfficiency (%) Notes ReferencesFloor housingsystem with stockpilingof manureStorage and handlingofpoultrymanure(solid)N/Ajj31Cage housingsystem with conveyor beltsStorage and handlingofpoultrymanure(solid)N/Ajj31Cage housingsystem with deeppitsStorage and handlingofpoultrymanure(solid)N/Ajj31Lagoons/concrete tanks for storage of poultry manure Storage of poultry manure (storage)N/Ajj 31Spread manure and incorporate within 3 days Application ofpoultrymanure(solid)36 - 80% reductionjj, kk 32Spread manure and incorporate within 3 days Application of dairymanure(solid and liquid)70% reductionjj, kk 32Spread manure and incorporate within 3 days Application of beef manure(solid and liquid)36-70% reductionjj, kk 32Spread manure and incorporate within 3 days Application of swine manure(solid and liquid)36-70% reductionjj, kk 32Inject manure using tank wagon and incorporate withknives or disksApplication of dairy and beef manure (liquid) N/A 33Above-ground manure storage tanksStorage of dairyand beef manure(solid and liquid)N/All 33Walled enclosures to store manureStorage of dairyand beef manure(solid and liquid)N/Amm33Outwinter cattle by rotating through pastures to "store"manure in frozen form until it can be used in the springHousing cattle (winter) N/A 34Outwinter cattle by keeping them outside in one paddock(sacrifice paddock) to store manure in one locationHousing cattle (winter)N/A34Compost manure before applyingTreatment of livestock manure(solid and liquid)N/A35Daily scraping and hauling of manure for collection andstorageStorage and handling of swine manure (solid) 42-63% reduction jj, nn 36Leaving manure to mix with bedding to form manure packfor collection and storageStorage and handling of swine manure (solid) 33-50% reduction jj, nn 36Storingmanure in linedpitStorage and handlingof swine manure(liquid)jj, oo 36Storingmanure in above-ground storage facilityStorage and handlingof swine manure(liquid)25-50% reductionjj, oo 36Broadcasting manure w/incorporation into soil within 12hoursApplication of swine manure (solid) 80% reduction jj, h1 36B-12Appendix B-6. Control Strategies for AmmoniaControl MeasureSources CoveredEstimatedEfficiency (%) Notes ReferencesBroadcasting manure w/incorporation into soil within 4daysApplication of swine manure (solid) 40% reduction jj, h1 36Injection of manure with sweepsApplication of swine manure(liquid)87% reductionjj, h1 36Injection of manure with knivesApplication of swine manure(liquid)62% reductionjj, h1 36Collectionponds to store manureStorage and handlingof swine manure(liquid)N/A37Deep pits to store manure and minimize gasconcentrationsStorage and handling of swine manure (solid) N/A 37Stockpile manure on concrete or claypadStorage and handlingof swine manure(solid)N/A37System than separates liquid and solid manureStorage and handlingof swine manure(solid)N/A37CompostingmanureTreatment of swine manure(liquid and solid)N/A37Anaerobic lagoons and digesters to store and "treat"manureTreatment of swine manure (liquid and solid) N/A 37Oxidation ditches and aerated lagoons to store and "treat"manureTreatment of swine manure (liquid and solid) N/A 37Daily scraping and hauling of manure for collection andstorageStorage and handling of poultry manure (solid) 42-63% reduction jj, nn 38Leaving manure to mix with bedding to form manure packfor collection and storageStorage and handling of poultry manure (solid) 33-50% reduction jj, nn 38Broadcasting manure w/incorporation into soil within 12hoursApplication of poultry manure (solid)83% reduction jj, h1 38Broadcasting manure w/incorporation into soil within 4daysApplication of poultry manure (solid) 33% reduction jj, h1 38[continued]B-13Appendix B-6. Control Strategies for AmmoniaControl MeasureSources CoveredEstimatedEfficiency (%) Notes ReferencesDaily scraping and hauling of manure for collection andstorageStorage and handling of dairy manure (solid) 42-62% reduction jj, nn 39Leaving manure to mix with bedding to form manure packfor collection and storageStorage and handling of dairy manure (solid) 30-50% reduction jj, nn 39Storingmanure in linedpitStorage and handlingof dairymanure(liquid)25% reductionjj, oo 39Storingmanure in above-ground storage facilityStorage and handlingof dairymanure(liquid)25-50% reductionjj, oo 39Broadcasting manure w/incorporation into soil within 12hoursApplication of dairy manure (solid) 75% reduction jj, h1 39Broadcasting manure w/incorporation into soil within 4daysApplication of dairy manure (solid) 50% reduction jj, h1 39Injection of manure with sweepsApplication of dairymanure(liquid)86% reductionjj, h1 39Injection of manure with knivesApplication of dairymanure(liquid)71% reductionjj, h1 39Daily scraping and hauling of manure for collection andstorageStorage and handling of beef manure (solid) 42-63% reduction jj, nn 40Leaving manure to mix with bedding to form manure packfor collection and storageStorage and handling of beef manure (solid) 33-50% reduction jj, nn 40Storingmanure in linedpitStorage and handlingof beef manure(liquid)25% reductionjj, oo 40Storingmanure in above-ground storage facilityStorage and handlingof beef manure(liquid)25-50% reductionjj, oo 40Broadcasting manure w/incorporation into soil within 12hoursApplication of beef manure (solid) 87% reduction jj, h1 40Broadcasting manure w/incorporation into soil within 4daysApplication of beef manure (solid) 50% reduction jj, h1 40Injection of manure with sweepsApplication of beef manure(liquid)56% reductionjj, h1 40Injection of manure with knivesApplication of beef manure(liquid)71% reductionjj, h1 40Best Management PracticesN/A41Manure Storage CoversStorage of livestock manure(solid and liquid)N/A41Manure Digesters(Biogas)Handlingof livestock manure(solid and liquid)N/A41Animal Lot Increased CleaningN/A41Injection of manure into fieldsApplication of livestock manure(liquid)N/A41[continued]B-14Appendix B-6. Control Strategies for AmmoniaControl MeasureSources CoveredEstimatedEfficiency (%) Notes ReferencesNutrient Management PlansHousing, storage, handling, and application oflivestock manure(solid and liquid)N/A41Earthen storageStorage of manure(solid and liquid)N/Aqq42Clay-lined impoundmentStorage of manure(solid and liquid)N/A42Geomembrane-lined impoundmentStorage of manure(solid and liquid)N/A42Geosynthetic clay-lined impoundmentStorage of manure(solid and liquid)N/A42Concrete-lined impoundmentStorage of manure(solid and liquid)N/A42Manure storage structureStorage of manure(solid and liquid)N/Aqq42Clay-lined impoundmentStorage of manure(solid and liquid)N/A42Geomembrane-lined impoundmentStorage of manure(solid and liquid)N/A42Geosynthetic clay-lined impoundmentStorage of manure(solid and liquid)N/A42Concrete-lined impoundmentStorage of manure(solid and liquid)N/A42Nitrification inhibitorHandlingof livestock manure(liquid)N/Ass 43Minimize application on frozen or snow-covered ground Application of livestock manure (solid and liquid) N/A44Apply manure on crops that can use all of its nutrients Application of livestock manure (solid and liquid) N/A44Incorporate or inject manure within 72 hours using ureaseinhibitorApplication of livestock manure (solid and liquid) N/A44Cover manure storage structures or use organic matter inbeddingto form a crust coverStorage of livestock manure (solid and liquid) N/A 44Divert urine awayfrom fecesHandlingof livestock manure(solid and liquid)N/A44Incorporate manureApplication of dairymanure10% reductionjj, kk 44Incorporate manureApplication of beef manure10% reduction44Incorporate manureApplication of swine manure(solid)15% reduction44Incorporate manureApplication of swine manure(liquid)15% reduction tt44[continued]B-15Appendix B-6. Control Strategies for AmmoniaControl MeasureSources CoveredEstimatedEfficiency (%) Notes ReferencesIncorporate manureApplication ofpoultrymanure10% reduction uu44Incorporate manureApplication of sheepmanure(solid)10% reduction44Incorporate manureApplication of horse manure(solid)10% reduction44Solid and liquid separation systemHandlingof liquid and solid manureN/Avv45Treat waste by mechanical, chemical, or biological means Treatment of livestock manure (solid and liquid) N/A46, 47Hopper to transfer manureHandlingof liquid and solid manureN/A48Reception structure or tank to transfer manureHandlingof liquid and solid manureN/Aww48Piston pumps to transfer manure to storage or treatmentstructureHandling of liquid and solid manure N/A 48Channels to transfer manure(gravitytransfer)Handlingof liquid and solid manureN/Axx 48Transfer pipes to transfer manure to storage or treatmentstructureHandling of liquid and solid manureN/Axx 48Pipelines(gravitytransfer)Handlingof liquid and solid manureN/A48[continued]B-16

# Appendix B-7. References for Control Strategies

1. Chan et al. E mission 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. E valuating 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. E stimates 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. E valuation 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. R eport 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

E q ui p ment ( 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 inWisconsin." 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

p romul g ation of State laws. ( Similar measures were also mentioned in ENVIRON's p hase I mobile source strate gy 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

re p ort estimates an 8% NOX reduction in 2007 if all states in the LADCO re g ion full y im p lemented an IM and OBD
d. Co-benefits of this strate gy are si g nificant. PM, HC, and CO are reduced b y 48, 48, and 68% res p ectivel y . 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 stud y are p re-1998. Cetane additives ma y decrease NOX emissions.
f. O p acit y reduced 2-6% when switchin g from re g ular diesel to B20

g . O p acit y reduced 5-11% when switchin g from re g ular diesel to B30

h. This test did not demonstrate PM or HC reductions usin g B20 or CARB diesel.

i. Emission benefits are not readil y available for most nonroad a pp lications. However, biodiesel is bein g used for j . 1% NOX reduction for line-haul locomotives, 2% for switchin g

. k. Based on Port of Los An g eles Emissions Inventor y . Percenta g e ma y differ for LADCO re g ion. 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 com p ared to re g ular g asoline. m. ENVIRON report assumes 15% participation in 2009 and 30% participation of HDDV anti-idling measures by 2012.

The re p ort also assumes 25% and 50% of switchin g and linehaul locomotives res p ectivel y

. n. Calculation of percentage NOX control efficiency would require knowledge of the percentage of time a truck would

p artici p ate in anti-idlin g p ro g rams. It is assumed that 100% of NOX would be reduced durin g the anti-idlin g time.
o. Control efficienc y was cited from the ENVIRON Phase II re p ort.

p . Control efficiencies were calculated based on the g /bh p -hr en g ine standard of the u pg raded en g ine vs. the old en g ine.

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. Timin g o f

Im p lementation : Assumes full reductions achieved in 2009. I m

p lementation

y . Candidate measure ID ICI2. Timin g o f

Im p lementation : Assumes full reductions achieved in 2013 I m

p lementation Area : z. Candidate measure ID ICI3. Timin g o f

Im p lementation : Assumes full reductions achieved in 2009 I m

p lementation Area : aa. Applies to CO, HC (and toxics), PM, and somewhat for NOx, probably for nontailpipe HCs. Fresno Study referenced in

Dou g Lawson's p resentation 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

p a p ers. We will include discussion on these existin g or u p comin g measures for all source cate g ories in our final re p ort.

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 hi g h cos t
nn. Baseline is o p en g round stora g e ( leavin g manure on g round with no method of collection or stora g e )

oo. Baseline is earthen g round stora g e ( leavin g manure on g round with no method of collection or stora g e )

pp . Baseline is broadcastin g manure with no waitin g time before incor p oratio n qq. no particular strategy is described as "best practice" but State offers technical specifications for structures to meet standard, e. g ., stora g e volume, de p th, how much stress can be p laced on the structure de p endin g 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 timin g s of manure a pp lication ( s p ecific soil tem p eratures )
tt. reference broke out nutrient availabilit y amon g indoor p it, outdoor p it, and farrow-nurser y indoor p it stora g e o p tions; all

uu. reference broke out nutrient availabilit y amon g duck, chicken, turke y , and p oultr y manure; all had same nutrient

vv. reference p rovides efficienc y in ca p turin g solids from waste strea m ww. reference p rovides technical s p ecifications for dimensions and distances from water source s xx. reference p rovides material com p onents and technical s p ecifications for transfer mechanis m



## [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-31a 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 SO 2 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 SO 2 . The remaining units all burned natural gas and so had negligible SO 2 emissions. According to Boise's 2005 permit, the SO 2 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 SO 2 , and further cost analysis for ICI1 was not necessary. Analyses were conducted for ICI1 NO X , and the Workgroup recommendation for both NO X and SO 2 .



### 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 facilitiesincludes 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 PM 2.5 

### 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 SO 2 

### 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 CControl technologyFuel and boiler typeBase value($/kW)Scalefactor Expon-entBase value($/kW-yr) Scale factor Expon-entBase value(cents/kWh) Scale factor Expon-ent<100 MW511.1 100 0.62 20.75 100 0.470.153 na na100-300 MW251.2 300 0.62 12.01 300 0.390.153 na na300-500 MW190.0 500 0.55 9.83 500 0.350.153 na na500-700 MW 155.1 700 0.60 8.74 700 0.37 0.153 na na>700 MW 131.0 1,000 0.47 7.64 1,000 0.37 0.153 na na<100 MW 312.3 100 0.50 14.20 100 0.47 0.153 na na100-300 MW 169.3 300 0.33 8.74 300 0.56 0.153 na na300-500 MW 143.1 500 0.31 6.55 500 0.54 0.153 na na500-700 MW 128.9 700 0.15 5.46 700 0.63 0.153 na na>700 MW 122.3 1,000 0.15 4.37 1,000 0.63 0.153 na naSCR Coal 133.8 243 0.27 0.89 243 0.27 0.080 243 0.11Oil / gas 38.6 200 0.35 1.19 200 0.35 0.013 na naSNCR Coal, pulverized, term 1** 22.9 200 0.58 0.34 200 0.58 0.118 na naCoal, pulverized, term 2** 26.1 100 0.68 0.40 100 0.68 0.118 na naCoal, cyclone 13.2 300 0.58 0.19 300 0.58 0.223 na naCoal, fluidized bed 22.9 200 0.58 0.35 200 0.58 0.102 na naOil / gas 13.0 200 0.58 0.20 200 0.58 0.060 na naLNB without OFA Coal, wall-fired 23.1 300 0.36 0.35 300 0.36 0.007 na naLNB with OFA Coal, wall-fired 31.3 300 0.36 0.48 300 0.36 0.010 na naLNB with close-coupled OFA Coal, tangential 12.2 300 0.36 0.02 300 0.36 0.000 na naLNB with separated OFA Coal, tangential 17.0 300 0.36 0.25 300 0.36 0.003 na naLNB with close-coupled and separatedOFACoal, tangential 19.4 300 0.36 0.30 300 0.36 0.003 na na<100 MW 511.1 100 0.62 20.75 100 0.47 0.153 na na100-300 MW 251.2 300 0.62 12.01 300 0.39 0.153 na na300-500 MW 190.0 500 0.55 9.83 500 0.35 0.153 na na500-700 MW 155.1 700 0.60 8.74 700 0.37 0.153 na na>700 MW 131.0 1,000 0.47 7.64 1,000 0.37 0.153 na na<100 MW 312.3 100 0.50 14.20 100 0.47 0.153 na na100-300 MW 169.3 300 0.33 8.74 300 0.56 0.153 na na300-500 MW 143.1 500 0.31 6.55 500 0.54 0.153 na na500-700 MW 128.9 700 0.15 5.46 700 0.63 0.153 na na>700 MW 122.3 1,000 0.15 4.37 1,000 0.63 0.153 na naSource: Reference 1NOX ControlsLime 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 AnalysesSO2 ControlsCapital cost factors*Fixed operating and maintenancescaling factors*Variable operating and maintenance costfactors*Limestone forced oxidation scrubberLime spray dryer scrubberC-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-5Table C-3. Estimated Cost and Cost Effectiveness for EGU1 and EGU2 Control Strategies for theDetroit Edison/St. Clair-Belle River Facility (Michigan)State Facility Unit FuelCapacity(MW)BaselineEmissions(tons)ControlTechnology%Reduction Cost ModelTotal CapitalInvestment[$M2005]Total O&MCost[$M2005]TotalAnnualizedCost [$M2005]EmissionReduction(tons)CostEffectiveness[$2005/ton]LowestAnnualizedCost($M2005)HighestAnnualizedCost($M2005)LowestEmissionsReduced(tons)HighestEmissionsReduced(tons)CostEffectiveness($2005/ton)MISt. Clair/Belle River 1 Coal 153 5,491 LSD 90 CUECost 54,602 6,604 14,783 4,942 2,991 10,628 18,012 4,942 5,216 150-3452IPM 44,092 4,023 10,628 4,942 2,151STAPPA ----150-4000LSFO 95 CUECost 71,543 7,295 18,012 5,216 3,453IPM 69,090 4,938 15,288 5,216 2,931STAPPA ----200-50002 Coal 162 6,162 LSD 90 CUECost 59,169 7,156 16,020 5,546 2,888 11,009 19,257 4,942 5,216 150-3289IPM 45,379 4,211 11,009 5,546 1,985STAPPA ----150-4000LSFO 95 CUECost 76,687 7,769 19,257 5,854 3,289IPM 70,608 5,155 15,732 5,854 2,687STAPPA ----200-50003 Coal 171 6,132 LSD 90 CUECost 58,567 7,149 15,923 5,519 2,885 11,425 19,263 4,942 5,825 150-3306IPM 46,631 4,440 11,425 5,519 2,070STAPPA ----150-4000LSFO 95 CUECost 76,094 7,864 19,263 5,825 3,307IPM 72,074 5,412 16,209 5,825 2,783STAPPA ----200-50004 Coal 158 5,734 LSD 90 CUECost 56,209 6,840 15,260 5,160 2,957 10,774 18,434 4,942 5,447 150-3384IPM 44,811 4,061 10,774 5,160 2,088STAPPA ----150-4000LSFO 95 CUECost 73,110 7,482 18,434 5,447 3,384IPM 69,940 4,992 15,469 5,447 2,840STAPPA ----200-50006 Coal 321 11,765 LSD 90 CUECost 75,056 10,823 22,066 10,588 2,084 16,444 25,653 4,942 11,176 150-2295IPM 61,545 7,224 16,444 10,588 1,553STAPPA ----150-4000LSFO 95 CUECost 92,898 11,737 25,653 11,176 2,295IPM 89,995 8,446 21,928 11,176 1,962STAPPA ----200-50007 Coal 450 11,765 LSD 90 CUECost 90,888 15,164 28,779 10,588 2,718 21,036 32,737 4,942 11,176 150-2929IPM 77,195 9,472 21,036 10,588 1,987STAPPA ----150-4000LSFO 95 CUECost 111,146 16,088 32,737 11,176 2,929IPM 104,903 11,187 26,902 11,176 2,407STAPPA ----200-5000Plant Total1,415 47,04877,147 133,356 42,344 44,696 1822-2984State Facility Unit FuelCapacity(MW)BaselineEmissions(tons)ControlTechnology%Reduction Cost ModelTotal CapitalInvestment[$M2005]Total O&MCost[$M2005]TotalAnnualizedCost [$M2005]EmissionReduction(tons)CostEffectiveness[$2005/ton]LowestAnnualizedCost($M2005)HighestAnnualizedCost($M2005)LowestEmissionsReduced(tons)HighestEmissionsReduced(tons)CostEffectiveness($2005/ton)MISt. Clair/Belle River 1 Coal 153 1,071 SCR 90 CUECost 15,493 1,520 3,602 963 3,739 599 6,764 375 963 200-1148IPM 24,436 1,143 4,428 963 4,596STAPPA ----1000-2000Costs of SO2 Controls for EGUsCosts of NOx Controls for EGUsC-6Table C-3. Estimated Cost and Cost Effectiveness for EGU1 and EGU2 Control Strategies for theDetroit Edison/St. Clair-Belle River Facility (Michigan)State Facility Unit FuelCapacity(MW)BaselineEmissions(tons)ControlTechnology%Reduction Cost ModelTotal CapitalInvestment[$M2005]Total O&MCost[$M2005]TotalAnnualizedCost [$M2005]EmissionReduction(tons)CostEffectiveness[$2005/ton]LowestAnnualizedCost($M2005)HighestAnnualizedCost($M2005)LowestEmissionsReduced(tons)HighestEmissionsReduced(tons)CostEffectiveness($2005/ton)SNCR 35 CUECost 2,219 301 599375 1,600IPM 3,727 1,420 1,921 375 5,126STAPPA - - - - 800-1500LNB 35 CUECost 5,375 120 843 375 2,250IPM 4,741 155 792 375 2,114STAPPA - - - - 200-1000NGR 55 CUECost 5,006 6,091 6,764 589 11,488IPM - - - 589 -STAPPA - - - - 500-20002 Coal 162 1,693 SCR 90 CUECost 17,433 1,736 4,079 1,524 2,677 744 7,595 593 1,524 200-8156IPM 25,477 1,207 4,631 1,524 3,039STAPPA - - - - 1000-2000SNCR 35 CUECost 2,479 411 744 593 1,255IPM 3,809 1,508 2,020 593 3,409STAPPA - - - - 800-1500LNB 35 CUECost 5,579 125 875 593 1,476IPM - - - 593 -STAPPA - - - - 200-1000NGR 55 CUECost 5,339 6,878 7,595 931 8,156IPM - - - 931 -STAPPA - - - - 500-20003 Coal 171 1,195 SCR 90 CUECost 16,866 1,651 3,918 1,076 3,641 638 7,505 418 1,076 200-1141IPM 26,503 1,291 4,853 1,076 4,510STAPPA - - - - 1000-2000SNCR 35 CUECost 2,376 319 638 418 1,525IPM 3,888 1,627 2,149 418 5,137STAPPA - - - - 800-1500LNB 35 CUECost 5,778 129 906 418 2,166IPM - - - 418 -STAPPA - - - - 200-1000NGR 55 CUECost 5,485 6,767 7,505 657 11,414IPM - - - 657 -STAPPA - - - - 500-20004 Coal 158 1,118 SCR 90 CUECost 16,244 1,616 3,799 1,006 3,776 609 7,079 391 1,006 200-1151IPM 25,017 1,145 4,507 1,006 4,480STAPPA - - - - 1000-2000SNCR 35 CUECost 2,276 303 609 391 1,556IPM 3,773 1,422 1,929 391 4,931STAPPA - - - - 800-1500LNB 35 CUECost 5,489 123 861 391 2,200IPM 4,840 157 807 391 2,063STAPPA - - - - 200-1000NGR 55 CUECost 5,083 6,396 7,079 615 11,514IPM - - - 615 -STAPPA - - - - 500-2000C-7Table C-3. Estimated Cost and Cost Effectiveness for EGU1 and EGU2 Control Strategies for theDetroit Edison/St. Clair-Belle River Facility (Michigan)State Facility Unit FuelCapacity(MW)BaselineEmissions(tons)ControlTechnology%Reduction Cost ModelTotal CapitalInvestment[$M2005]Total O&MCost[$M2005]TotalAnnualizedCost [$M2005]EmissionReduction(tons)CostEffectiveness[$2005/ton]LowestAnnualizedCost($M2005)HighestAnnualizedCost($M2005)LowestEmissionsReduced(tons)HighestEmissionsReduced(tons)CostEffectiveness($2005/ton)6 Coal 321 1,766 SCR 90 CUECost 25,234 2,886 6,278 1,589 3,950 846 13,028 618 1,589 200-1341IPM 41,972 2,180 7,821 1,589 4,921STAPPA ----1000-2000SNCR 35 CUECost 3,070 433 846618 1,369IPM 4,939 2,942 3,606 618 5,834STAPPA ----800-1500LNB 35 CUECost 8,701 195 1,364 618 2,207IPM ---618 -STAPPA ----200-1000NGR 55 CUECost 7,844 11,974 13,028 971 13,414IPM ---971 -STAPPA ----500-20007 Coal 450 1,766 SCR 90 CUECost 33,526 4,143 8,648 1,589 5,442 1,214 10,190 618 1,589 200-7980IPM 53,710 2,972 10,190 1,589 6,412STAPPA ----1000-2000SNCR 35 CUECost 3,891 691 1,214 618 1,964IPM 5,619 4,177 4,932 618 7,980STAPPA ----800-1500Plant Total1,415 8,6094,649 51,639 3,013 7,748 1543-6665C-8Table C-4. Consumers Energy Company/JH Campbell Facility (Michigan)State Facility Unit FuelCapacity(MW)BaselineEmissions(tons)ControlTechnology%Reduction Cost ModelTotal CapitalInvestment[$M2005]TotalO&M Cost[$M2005]TotalAnnualizedCost [$M2005]EmissionReduction(tons)CostEffectiveness[$2005/ton]LowestAnnualizedCost($M2005)HighestAnnualizedCost($M2005)LowestEmissionsReduced(tons)HighestEmissionsReduced(tons)CostEffectiveness($2005/ton)MI JH Campbell 1 Coal 260 10,767 LSD 90 CUECost 78,193 11,709 23,423 9,690 2,417 14,483 24,314 9,690 10,229 150-2417IPM 57,580 5,858 14,483 9,690 1,495STAPPA -- --150-4000LSFO 95 CUECost 93,492 10,309 24,314 10,229 2,377IPM 84,520 7,077 19,738 10,229 1,930STAPPA -- --200-50002 Coal 355 12,986 LSD 90 CUECost 83,538 13,935 26,449 11,688 2,263 17,567 27,430 11,688 12,337 150-2263IPM 65,844 7,704 17,567 11,688 1,503STAPPA -- --150-4000LSFO 95 CUECost 99,523 12,521 27,430 12,337 2,223IPM 94,201 9,060 23,171 12,337 1,878STAPPA -- --200-50003 Coal 820 30,020 LSD 90 CUECost 112,653 24,860 41,735 27,018 1,545 32,371 47,039 27,018 28,519 150-1649IPM 119,585 14,457 32,371 27,018 1,198STAPPA -- --150-4000LSFO 95 CUECost 156,806 23,550 47,039 28,519 1,649IPM 136,680 17,580 38,055 28,519 1,334STAPPA -- --200-5000Plant Total1435 5377364,421 98,783 48,396 51,085 1331-1934State Facility Unit FuelCapacity(MW)BaselineEmissions(tons)ControlTechnology%Reduction Cost ModelTotal CapitalInvestment[$M2005]TotalO&M Cost[$M2005]TotalAnnualizedCost [$M2005]EmissionReduction(tons)CostEffectiveness[$2005/ton]LowestAnnualizedCost($M2005)HighestAnnualizedCost($M2005)LowestEmissionsReduced(tons)HighestEmissionsReduced(tons)CostEffectiveness($2005/ton)MI JH Campbell 1 Coal 260 3,153 SCR 78 CUECost 29,285 3,146 7,082 2,459 2,880 1,116 12,797 1,104 2,459 200-7379IPM 35,987 1,719 6,556 2,459 2,666STAPPA -- --1000-2000SNCR 35 CUECost 3,316 671 1,116 1,104 1,012IPM 4,559 2,250 2,862 1,104 2,594STAPPA -- --800-1500LNB 35 CUECost 7,589 170 1,190 1,104 1,078IPM -- -1,104 -STAPPA -- --200-1000NGR 55 CUECost 6,885 11,872 12,797 1,734 7,379IPM -- -1,734 -STAPPA -- --500-2000Costs of SO2 Controls for EGUsCosts of NOx Controls for EGUsC-9Table C-4. Consumers Energy Company/JH Campbell Facility (Michigan)State Facility Unit FuelCapacity(MW)BaselineEmissions(tons)ControlTechnology%Reduction Cost ModelTotal CapitalInvestment[$M2005]TotalO&M Cost[$M2005]TotalAnnualizedCost [$M2005]EmissionReduction(tons)CostEffectiveness[$2005/ton]LowestAnnualizedCost($M2005)HighestAnnualizedCost($M2005)LowestEmissionsReduced(tons)HighestEmissionsReduced(tons)CostEffectiveness($2005/ton)2 Coal 355 7,359 SCR 88 CUECost 33,388 4,005 8,492 6,476 1,311 1,457 15,574 2,576 6,476 200-3848IPM 45,173 2,336 8,407 6,476 1,298STAPPA -- --1000-2000SNCR 35 CUECost 3,946 1,424 1,954 2,576 759IPM 5,133 3,182 3,872 2,576 1,503STAPPA -- --800-1500LNB 35 CUECost 9,292 208 1,457 2,576 566IPM -- -2,576 -STAPPA -- --200-1000NGR 55 CUECost 8,375 14,448 15,574 4,047 3,848IPM -- -4,047 -STAPPA -- --500-20003 Coal 820 11,799 SCR 70 CUECost 64,401 8,825 17,481 8,259 2,117 2,511 17,481 4,130 8,259 200-2117IPM 90,557 4,830 17,000 8,259 2,058STAPPA -- --1000-2000SNCR 35 CUECost 6,647 2,231 3,124 4,130 757IPM 7,069 6,937 7,887 4,130 1,910STAPPA -- --800-1500LNB 35 CUECost 16,012 359 2,511 4,130 608IPM -- -4,130 -STAPPA -- --200-1000NGR 55 CUECost 17,069 6,921 9,215 6,489 1,420IPM -- -6,489 -STAPPA -- --500-2000Plant Total1435 223115,084 45,851 7,809 17,194 651-2667C-10Table C-5. Wisconsin Electric/Presque Isle Facility (Michigan)State Facility Unit FuelCapacity(MW)BaselineEmissions(tons)ControlTechnology%Reduction Cost ModelTotal CapitalInvestment[$M2005]TotalO&M Cost[$M2005]TotalAnnualizedCost [$M2005]EmissionReduction(tons)CostEffectiveness[$2005/ton]LowestAnnualizedCost($M2005)HighestAnnualizedCost($M2005)LowestEmissionsReduced(tons)HighestEmissionsReduced(tons)CostEffectiveness($2005/ton)MIWIElectric/Presque Isle 5 Coal 883,431LSD 90 CUECost 45,698 4,761 11,607 3,088 3,759 6,536 14,697 3,088 3,259 150-4509IPM 27,815 2,369 6,536 3,088 2,117STAPPA - - - - 150-4000LSFO 95 CUECost 62,139 5,389 14,697 3,259 4,509IPM 46,657 2,935 9,924 3,259 3,045STAPPA - - - - 200-50006 Coal 883,416LSD 90 CUECost 45,635 4,750 11,586 3,075 3,768 6,536 14,680 3,075 3,245 150-4523IPM 27,815 2,369 6,536 3,075 2,126STAPPA - - - - 150-4000LSFO 95 CUECost 62,076 5,381 14,680 3,245 4,523IPM 46,657 2,935 9,924 3,245 3,058STAPPA - - - - 200-50007 Coal 882,046LSD 90 CUECost 47,226 5,026 12,100 1,842 6,570 6,536 15,113 1,842 1,944 150-7773IPM 27,815 2,369 6,536 1,842 3,549STAPPA - - - - 150-4000LSFO 95 CUECost 63,665 5,576 15,113 1,944 7,773IPM 46,657 2,935 9,924 1,944 5,104STAPPA - - - - 200-50008 Coal 881,965LSD 90 CUECost 46,584 4,914 11,893 1,768 6,726 6,536 14,938 1,768 1,866 150-8004IPM 27,815 2,369 6,536 1,768 3,697STAPPA - - - - 150-4000LSFO 95 CUECost 63,027 5,497 14,938 1,866 8,004IPM 46,657 2,935 9,924 1,866 5,317STAPPA - - - - 200-50009 Coal 881,967LSD 90 CUECost 46,605 4,918 11,899 1,770 6,721 6,536 14,944 1,770 1,869 150-7997IPM 27,815 2,369 6,536 1,770 3,692STAPPA - - - - 150-4000LSFO 95 CUECost 63,047 5,499 14,944 1,869 7,997IPM 46,657 2,935 9,924 1,869 5,310STAPPA - - - - 200-5000Plant Total440 12,82532,679 74,371 11,543 12,184 2831-6104State Facility Unit FuelCapacity(MW)BaselineEmissions(tons)ControlTechnology%Reduction Cost ModelTotal CapitalInvestment[$M2005]TotalO&M Cost[$M2005]TotalAnnualizedCost [$M2005]EmissionReduction(tons)CostEffectiveness[$2005/ton]LowestAnnualizedCost($M2005)HighestAnnualizedCost($M2005)LowestEmissionsReduced(tons)HighestEmissionsReduced(tons)CostEffectiveness($2005/ton)MIWIElectric/Presque Isle 5 Coal 881,012SCR 90 CUECost 12,663 988 2,690 910 2,954 427 4,066 354 910 200-7308IPM 16,319 685 2,878 910 3,161STAPPA - - - - 1000-2000SNCR 35 CUECost 1,916 288 546 354 1,542IPM 3,023 799 1,205 354 3,404STAPPA - - - - 800-1500Costs of SO2 Controls for EGUsCosts of NOx Controls for EGUsC-11Table C-5. Wisconsin Electric/Presque Isle Facility (Michigan)State Facility Unit FuelCapacity(MW)BaselineEmissions(tons)ControlTechnology%Reduction Cost ModelTotal CapitalInvestment[$M2005]TotalO&M Cost[$M2005]TotalAnnualizedCost [$M2005]EmissionReduction(tons)CostEffectiveness[$2005/ton]LowestAnnualizedCost($M2005)HighestAnnualizedCost($M2005)LowestEmissionsReduced(tons)HighestEmissionsReduced(tons)CostEffectiveness($2005/ton)LNB 35 CUECost 2,720 61 427354 1,205IPM -- -354 -STAPPA -- --200-1000NGR 55 CUECost 3,962 3,534 4,066 556 7,308IPM -- -556 -STAPPA -- --500-20006 Coal 881,049SCR 90 CUECost 12,630 984 2,681 944 2,839 427 4,051 367 944 200-7020IPM 16,319 685 2,878 944 3,047STAPPA - - - - 1000-2000SNCR 35 CUECost 1,913 288 545 367 1,483IPM 3,023 799 1,205 367 3,282STAPPA - - - - 800-1500LNB 35 CUECost 2,720 61 427 367 1,161IPM - - - 367 -STAPPA - - - - 200-1000NGR 55 CUECost 3,962 3,519 4,051 577 7,020IPM - - - 577 -STAPPA - - - - 500-20007 Coal 881,218SCR 90 CUECost 13,467 1,082 2,892 1,096 2,640 427 4,430 426 1,096 200-6615IPM 16,319 685 2,878 1,096 2,626STAPPA - - - - 1000-2000SNCR 35 CUECost 1,982 308 574 426 1,348IPM 3,023 799 1,205 426 2,828STAPPA - - - - 800-1500LNB 35 CUECost 2,720 61 427 426 1,001IPM - - - 426 -STAPPA - - - - 200-1000NGR 55 CUECost 3,962 3,897 4,430 670 6,615IPM - - - 670 -STAPPA - - - - 500-20008 Coal 881,063SCR 90 CUECost 13,130 1,042 2,807 957 2,934 427 4,276 372 957 200-7314IPM 16,319 108 2,302 957 2,406STAPPA - - - - 1000-2000SNCR 35 CUECost 1,954 300 562 372 1,512IPM 3,023 799 1,205 372 3,240STAPPA - - - - 800-1500LNB 35 CUECost 2,720 61 427 372 1,146IPM - - - 372 -STAPPA - - - - 200-1000NGR 55 CUECost 3,962 3,744 4,276 585 7,314IPM - - - 585 -STAPPA - - - - 500-2000C-12Table C-5. Wisconsin Electric/Presque Isle Facility (Michigan)State Facility Unit FuelCapacity(MW)BaselineEmissions(tons)ControlTechnology%Reduction Cost ModelTotal CapitalInvestment[$M2005]TotalO&M Cost[$M2005]TotalAnnualizedCost [$M2005]EmissionReduction(tons)CostEffectiveness[$2005/ton]LowestAnnualizedCost($M2005)HighestAnnualizedCost($M2005)LowestEmissionsReduced(tons)HighestEmissionsReduced(tons)CostEffectiveness($2005/ton)9 Coal 881,120SCR 90 CUECost 13,141 1,044 2,690 1,008 2,668 427 4,066 392 1,008 200-6084IPM 16,319 685 2,878 1,008 2,854STAPPA - - - - 1000-2000SNCR 35 CUECost 1,955 300 546 392 1,392IPM 3,023 799 1,205 392 3,074STAPPA - - - - 800-1500LNB 35 CUECost 2,720 61 427 392 1,088IPM - - - 392 -STAPPA - - - - 200-1000NGR 55 CUECost 3,962 3,749 4,066 616 6,084IPM - - - 616 -STAPPA - - - - 500-2000Plant Total440 5,4622,133 20,890 1,912 4,916 1116-4250C-13Table C-6. Minnesota Power/Clay Boswell Facility (Minnesota)State Facility Unit FuelCapacity(MW)BaselineEmissions(tons)ControlTechnology % Reduction Cost ModelTotal CapitalInvestment[$M2005]Total O&M Cost[$M2005]TotalAnnualized Cost[$M2005]EmissionReduction(tons)Cost Effectiveness[$2005/ton]LowestAnnualized Cost($M2005)HighestAnnualizedCost ($M2005)LowestEmissionsReduced (tons)HighestEmissionsReduced (tons)Cost Effectiveness($2005/ton)MN Clay Boswell 1 Coal 69 2,587 LSD90CUECost 45,6015,27112,102 2,328 5,1985,66014,108 2,3282,458150-5741IPM24,6101,9745,6602,328 2,431STAPPA ----150-4000LSFO95CUECost 59,2325,23514,108 2,458 5,741IPM42,5362,4698,8412,458 3,598STAPPA ----200-50002 Coal 69 2,572 LSD90CUECost 46,1125,26612,174 2,315 5,2595,62514,169 2,3152,443150-5799IPM24,6101,9385,6252,315 2,430STAPPA ----150-4000LSFO95CUECost 59,7395,22014,169 2,443 5,799IPM42,5362,4348,8062,443 3,604STAPPA ----200-5000Plant Total138 515911,285 28,276 4,6434,9012431-5770State Facility Unit FuelCapacity(MW)BaselineEmissions(tons)ControlTechnology % Reduction Cost ModelTotal CapitalInvestment[$M2005]Total O&M Cost[$M2005]TotalAnnualized Cost[$M2005]EmissionReduction(tons)Cost Effectiveness[$2005/ton]LowestAnnualized Cost($M2005)HighestAnnualizedCost ($M2005)LowestEmissionsReduced (tons)HighestEmissionsReduced (tons)Cost Effectiveness($2005/ton)MN Clay Boswell 1 Coal 69 693 SCR90CUECost 10,6937612,1986243,5244723,157243624500-8281IPM13,6645502,3876243,825STAPPA ----1000-2000SNCR35CUECost 1,7542374722431,947IPM2,7586279972434,111STAPPA ----800-1500NGR55CUECost 3,6352,6693,1573818,281IPM---381-STAPPA ----500-20002 Coal 69 689 SCR90CUECost 10,9377812,2516203,6284743,142241620500-8289IPM13,6645312,3676203,817STAPPA ----1000-2000SNCR35CUECost 1,7732364742411,965IPM2,7586029732414,032STAPPA ----800-1500NGR55CUECost 3,6352,6543,1423798,289IPM---379-STAPPA ----500-20004 Coal 426 4,859 SCR90CUECost 36,4473,8058,7034,373 1,9901,40823,558 1,7014,373500-8815IPM51,6113,52510,461 4,373 2,392STAPPA ----1000-2000SNCR35CUECost 3,9198821,4081,701 828IPM5,5035,0335,7731,701 3,394STAPPA ----800-1500NGR55CUECost 9,85422,234 23,558 2,673 8,815IPM---2,673 -STAPPA ----500-2000Plant Total564 62422,35529,857 2,1855,6171078-5315Costs of SO2 Controls for EGUsCosts of NOx Controls for EGUsC-14Table C-7. Minnesota Power/Syl Laskin Facility (Minnesota)*State Facility Unit FuelCapacity(MW)BaselineEmissions(tons)ControlTechnology % Reduction Cost ModelTotal CapitalInvestment[$M2005]TotalO&M Cost[$M2005]TotalAnnualizedCost [$M2005]EmissionReduction(tons)CostEffectiveness[$2005/ton]LowestAnnualizedCost($M2005)HighestAnnualizedCost($M2005)LowestEmissionsReduced(tons)HighestEmissionsReduced(tons)CostEffectiveness($2005/ton)MN Syl Laskin 1 Coal 55 951 LSD 90CUECost 44,526 4,856 11,526 856 13,460 4,955 11,526 856 904 150-13460IPM 21,945 1,668 4,955 856 5,786STAPPA -- --150-4000LSFO 95CUECost 37,652 4,253 9,894 904 10,945IPM 39,005 2,106 7,949 904 8,794STAPPA -- --200-50002 Coal 55 950 LSD 90CUECost 58,190 4,856 13,573 855 15,873 4,698 13,573 855 903 150-15873IPM 21,945 1,662 4,949 855 5,788STAPPA -- --150-4000LSFO 95CUECost 58,192 4,852 13,569 903 15,033IPM 39,005 2,100 7,943 903 8,800STAPPA -- --200-5000Plant Total110 19029,653 25,099 1,711 1,807 5640-13894* This facility is installing NOx controls so NOx control costs were not evaluatedCosts of SO2 Controls for EGUsC-15Table C-8. Northshore Mining Company/Silver Bay Facility (Minnesota)State Facility Unit FuelCapacity(MW)BaselineEmissions(tons)ControlTechnology%Reduction Cost ModelTotal CapitalInvestment[$M2005]TotalO&M Cost[$M2005]TotalAnnualizedCost [$M2005]EmissionReduction(tons)CostEffectiveness[$2005/ton]LowestAnnualizedCost($M2005)HighestAnnualizedCost($M2005)LowestEmissionsReduced(tons)HighestEmissionsReduced(tons)CostEffectiveness($2005/ton)MNNorthshore/Silver Bay 1 Coal 85 851 LSD 90 CUECost 43,277,712 3,894 10,377 766 13,549 3,465 12,918 766 808 150-16041IPM17,737 808 3,465 766 4,524STAPPA -- --150-4000LSFO 95 CUECost 58,235 4,195 12,918 808 15,979IPM33,215 1,156 6,132 808 7,585STAPPA -- --200-5000Plant Total85 8513,465 12,918 766 808 922-16041State Facility Unit FuelCapacity(MW)BaselineEmissions(tons)ControlTechnology%Reduction Cost ModelTotal CapitalInvestment[$M2005]TotalO&M Cost[$M2005]TotalAnnualizedCost [$M2005]EmissionReduction(tons)CostEffectiveness[$2005/ton]LowestAnnualizedCost($M2005)HighestAnnualizedCost($M2005)LowestEmissionsReduced(tons)HighestEmissionsReduced(tons)CostEffectiveness($2005/ton)MNNorthshore/Silver Bay 1 Coal 85 1122 SCR 90 CUECost 11,870 849 2,627 1,010 2,602 322 2,627 16 40 200-2602IPM8,498 56 1,199 1,010 1,187STAPPA -- --1000-2000SNCR 35 CUECost 1,758 205 468393 1,192IPM2,160 32 322393 821STAPPA -- --800-1500LNB 35 CUECost 3,668 82 632393 1,609IPM2,546 39 381393 971STAPPA -- --200-1000NGR 55 CUECost 3,912 844 1,430 617 2,317IPM-- -617 -STAPPA -- --500-2000Plant Total85 1122322 2,627 16 40 821-2322Costs of SO2 Controls for EGUsCosts of NOx Controls for EGUsC-16Table C-9. Virginia Public Utilities Commission Facility (Minnesota)State Facility Unit FuelCapacity(MW)BaselineEmissions(tons)ControlTechnology%Reduction Cost ModelTotal CapitalInvestment[$M2005]TotalO&M Cost[$M2005]TotalAnnualized Cost[$M2005]EmissionReduction(tons)CostEffectiveness[$2005/ton]LowestAnnualizedCost($M2005)HighestAnnualizedCost($M2005)LowestEmissionsReduced(tons)HighestEmissionsReduced(tons)CostEffectiveness($2005/ton)MN Virginia PUC 7 Coal 10 584 LSD 90 CUECost 30,787 1,616 6,228525 11,859 6,228 8,933 525 554 150-16116IPM-- -525 -STAPPA -- --150-4000LSFO 95 CUECost 44,821 2,219 8,933554 16,116IPM-- -554 -STAPPA -- --200-50009 Coal 10 584 LSD 90 CUECost 30,787 1,616 6,228525 11,859 6,228 8,933 525 554 150-16116IPM-- -525 -STAPPA -- --150-4000LSFO 95 CUECost 44,821 2,219 8,933554 16,116IPM-- -554 -STAPPA -- --200-500010 Coal 10 12,606 LSD 90 CUECost 30,787 1,616 6,22811,346 5496,228 8,933 11,346 11,976 150-922IPM-- -11,346 -STAPPA -- --150-4000LSFO 95 CUECost 44,821 2,219 8,93311,976 -IPM-- -11,976 -STAPPA -- --200-5000Plant Total30 13,77318,684 26,800 12,396 13,085 1507-2048State Facility Unit FuelCapacity(MW)BaselineEmissions(tons)ControlTechnology%Reduction Cost ModelTotal CapitalInvestment[$M2005]TotalO&M Cost[$M2005]TotalAnnualized Cost[$M2005]EmissionReduction(tons)CostEffectiveness[$2005/ton]LowestAnnualizedCost($M2005)HighestAnnualizedCost($M2005)LowestEmissionsReduced(tons)HighestEmissionsReduced(tons)CostEffectiveness($2005/ton)MN Virginia PUC 7 Coal 10 125 SCR 90 CUECost 4,188 180 743113 6,589 143 743 44 113 200-9011IPM3,254 68 505113 4,481STAPPA -- --1000-2000SNCR 35 CUECost 1,259 115 284446,477IPM1,322 67 245445,584STAPPA -- --800-1500LNB 35 CUECost 91320 143443,264IPM-- -44-STAPPA -- -200-1000NGR 55 CUECost 2,270 316 621699,011IPM-- -69-STAPPA -- --500-20009 Coal 10 125 SCR 90 CUECost 4,188 180 743113 6,589 143 743 44 113 200-9011IPM3,254 68 505113 4,481STAPPA -- --1000-2000SNCR 35 CUECost 1,259 115 284446,477IPM1,322 67 245445,584STAPPA -- --800-1500LNB 35 CUECost 91320 143443,264IPM-- -44-STAPPA -- -200-1000NGR 55 CUECost 2,270 316 621699,011IPM-- -69-STAPPA -- --500-2000Costs of SO2 Controls for EGUsCosts of NOx Controls for EGUsC-17Table C-9. Virginia Public Utilities Commission Facility (Minnesota)State Facility Unit FuelCapacity(MW)BaselineEmissions(tons)ControlTechnology%Reduction Cost ModelTotal CapitalInvestment[$M2005]TotalO&M Cost[$M2005]TotalAnnualized Cost[$M2005]EmissionReduction(tons)CostEffectiveness[$2005/ton]LowestAnnualizedCost($M2005)HighestAnnualizedCost($M2005)LowestEmissionsReduced(tons)HighestEmissionsReduced(tons)CostEffectiveness($2005/ton)10 Coal 10 0 SCR 90 CUECost 4,188 180 7430-108 743 0 0 -IPM-- -0-STAPPA -- ---SNCR 35 CUECost 1,259 115 2840-IPM72011 1080-STAPPA -- ---LNB 35 CUECost 91320 1430-IPM-- -0-STAPPA -- ---NGR 55 CUECost 2,270 316 6210-IPM-- -0-STAPPA -- ---Plant Total30 251394 2,229 88 226 4495-9884C-18Table C-10. Dairyland Power Coop/Alma Facility (Wisconsin)State Facility Unit FuelCapacity(MW)BaselineEmissions(tons)ControlTechnology%Reduction Cost ModelTotal CapitalInvestment[$M2005]TotalO&M Cost[$M2005]TotalAnnualizedCost [$M2005]EmissionReduction(tons)CostEffectiveness[$2005/ton]LowestAnnualizedCost($M2005)HighestAnnualizedCost($M2005)LowestEmissionsReduced(tons)HighestEmissionsReduced(tons)CostEffectiveness($2005/ton)WI Dairyland1 Coal 18 1,384 LSD 90 CUECost 33,226 2,297 7,274 1,245 5,841 2,748 9,953 1,245 1,315 150-7571IPM12,606 859 2,748 1,245 2,206STAPPA - - - - 150-4000LSFO 95 CUECost 47,057 2,904 9,953 1,315 7,571IPM 25,663 1,101 4,945 1,315 3,762STAPPA - - - - 200-50002 Coal 18 1,165 LSD 90 CUECost 33,226 2,213 7,190 1,048 6,858 2,701 9,874 1,048 1,107 150-8922IPM 12,606 813 2,701 1,048 2,576STAPPA - - - - 150-4000LSFO 95 CUECost 47,057 2,825 9,874 1,107 8,922IPM 25,663 1,054 4,899 1,107 4,426STAPPA - - - - 200-50003 Coal 22 1,396 LSD 90 CUECost 34,312 2,416 7,556 1,256 6,016 2,986 10,284 1,256 1,326 150-7757IPM 13,805 918 2,986 1,256 2,378STAPPA - - - - 150-4000LSFO 95 CUECost 48,384 3,036 10,284 1,326 7,757IPM 27,487 1,184 5,302 1,326 3,999STAPPA - - - - 200-50004 Coal 57 2,415 LSD 90 CUECost 42,672 4,086 10,478 2,174 4,820 5,090 13,325 2,174 2,295 150-5807IPM 22,357 1,741 5,090 2,174 2,341STAPPA - - - - 150-4000LSFO 95 CUECost 57,570 4,701 13,325 2,295 5,807IPM 39,561 2,188 8,114 2,295 3,536STAPPA - - - - 200-50005 Coal 77 3,514 LSD 90 CUECost 43,802 4,382 10,944 3,163 3,460 6,175 14,097 3,163 3,338 150-4223IPM 26,064 2,271 6,175 3,163 1,953STAPPA - - - - 150-4000LSFO 95 CUECost 60,464 5,039 14,097 3,338 4,223IPM 44,421 2,798 9,453 3,338 2,832STAPPA - - - - 200-5000Plant Total 192 9,87419,701 57,533 8,886 9,380 2217-6134State Facility Unit FuelCapacity(MW)BaselineEmissions(tons)ControlTechnology% ReductionCost ModelTotal CapitalInvestment[$M2005]TotalO&M Cost[$M2005]TotalAnnualizedCost [$M2005]EmissionReduction(tons)CostEffectiveness[$2005/ton]LowestAnnualizedCost($M2005)HighestAnnualizedCost($M2005)LowestEmissionsReduced(tons)HighestEmissionsReduced(tons)CostEffectiveness($2005/ton)WI Dairyland1 Coal 18 316 SCR 90 CUECost 5,047 244 922285 3,238 152 1,336 111 285 200-7682IPM5,178 221 917285 3,223STAPPA -- --1000-2000SNCR 35 CUECost 1,301 146 321111 2,900IPM1,675 231 456111 4,119STAPPA -- --800-1500LNB 35 CUECost 97022 152111 1,373IPM1,214 31 194111 1,753STAPPA -- --200-1000NGR 55 CUECost 2,548 994 1,336 174 7,682IPM-- -174 -STAPPA -- --500-2000Costs of SO2 Controls for EGUsCosts of NOx Controls for EGUsC-19Table C-10. Dairyland Power Coop/Alma Facility (Wisconsin)State Facility Unit FuelCapacity(MW)BaselineEmissions(tons)ControlTechnology%Reduction Cost ModelTotal CapitalInvestment[$M2005]TotalO&M Cost[$M2005]TotalAnnualizedCost [$M2005]EmissionReduction(tons)CostEffectiveness[$2005/ton]LowestAnnualizedCost($M2005)HighestAnnualizedCost($M2005)LowestEmissionsReduced(tons)HighestEmissionsReduced(tons)CostEffectiveness($2005/ton)2 Coal 18 266 SCR 90 CUECost 5,047 242 920240 3,840 152 1,226 93 240 200-8370IPM5,178 192 888240 3,705STAPPA -- --1000-2000SNCR 35 CUECost 1,300 139 314933,369IPM1,675 198 423934,544STAPPA -- --800-1500LNB 35 CUECost 97022 152931,631IPM1,214 29 192932,061STAPPA -- --200-1000NGR 55 CUECost 2,548 883 1,226 146 8,370IPM-- -146 -STAPPA -- --500-20003 Coal 22 319 SCR 90 CUECost 5,662 290 1,051 287 3,662 173 1,411 112 287 200-8043IPM5,908 224 1,018 287 3,547STAPPA -- --1000-2000SNCR 35 CUECost 1,349 148 330112 2,953IPM1,792 234 475112 4,257STAPPA -- --800-1500LNB 35 CUECost 1,105 25 173112 1,552IPM1,363 33 216112 1,939STAPPA -- --200-1000NGR 55 CUECost 2,661 1,053 1,411 175 8,043IPM-- -175 -STAPPA -- --500-20004 Coal 57 773 SCR 90 CUECost 10,041 697 2,046 696 2,942 322 2,973 271 696 200-6993IPM11,888 479 2,076 696 2,985STAPPA -- --1000-2000SNCR 35 CUECost 1,700 227 456271 1,684IPM2,567 537 882271 3,259STAPPA -- --800-1500LNB 35 CUECost 2,051 46 322271 1,189IPM-- -271 -STAPPA -- --200-1000NGR 55 CUECost 3,418 2,513 2,973 425 6,993IPM-- -425 -STAPPA -- --500-20005 Coal 77 1,124 SCR 90 CUECost 11,907 922 2,522 1,012 2,492 391 4,119 394 1,012 200-6660IPM14,851 676 2,672 1,012 2,640STAPPA -- --1000-2000SNCR 35 CUECost 1,856 288 538394 1,366IPM2,880 787 1,174 394 2,984STAPPA -- --800-1500LNB 35 CUECost 2,494 56 391394 994IPM-- -394 -STAPPA -- -200-1000NGR 55 CUECost 3,775 3,611 4,119 618 6,660IPM-- -618 -STAPPA -- --500-2000Plant Total 192 2,7991,190 11,065 980 2,519 1556-4392C-20Table C-11. Xcel Energy/Bay Front Facility (Wisconsin)State Facility Unit FuelCapacity(MW)BaselineEmissions(tons)ControlTechnology%Reduction Cost ModelTotal CapitalInvestment[$M2005]TotalO&M Cost[$M2005]TotalAnnualizedCost [$M2005]EmissionReduction(tons)CostEffectiveness[$2005/ton]LowestAnnualizedCost($M2005)HighestAnnualizedCost($M2005)LowestEmissionsReduced(tons)HighestEmissionsReduced(tons)CostEffectiveness($2005/ton)WI Xcel Energ1 Coal 22 1,890 LSD 90 CUECost 37,322 2,701 8,291 1,701 4,876 2,953 11,074 1,701 1,795 150-6169IPM13,843 879 2,953 1,701 1,736STAPPA -- --150-4000LSFO 95 CUECost 51,934 3,294 11,074 1,795 6,169IPM27,544 1,146 5,272 1,795 2,937STAPPA -- --200-50002 Coal 22 1,890 LSD 90 CUECost 36,222 2,666 8,092 1,701 4,758 2,992 10,865 1,701 1,795 150-6053IPM13,843 919 2,992 1,701 1,760STAPPA -- --150-4000LSFO 95 CUECost 50,684 3,272 10,865 1,795 6,053IPM27,544 1,186 5,312 1,795 2,959STAPPA -- --200-50005 Coal 30 1,478 LSD 90 CUECost 36,662 2,553 8,045 1,330 6,047 3,457 10,888 1,330 1,404 150-7753IPM16,182 1,033 3,457 1,330 2,598STAPPA -- --150-4000LSFO 95 CUECost 51,173 3,222 10,888 1,404 7,753IPM30,991 1,348 5,991 1,404 4,266STAPPA -- --200-5000Plant Total74 5,2579,402 32,826 4,731 4,994 1987-6573State Facility Unit FuelCapacity(MW)BaselineEmissions(tons)ControlTechnology%Reduction Cost ModelTotal CapitalInvestment[$M2005]TotalO&M Cost[$M2005]TotalAnnualizedCost [$M2005]EmissionReduction(tons)CostEffectiveness[$2005/ton]LowestAnnualizedCost($M2005)HighestAnnualizedCost($M2005)LowestEmissionsReduced(tons)HighestEmissionsReduced(tons)CostEffectiveness($2005/ton)WI Xcel Energ1 Coal 22 509 SCR 90 CUECost 7,479 443 1,448 458 3,163 173 1,777 178 458 200-6350IPM5,932 199 996458 2,175STAPPA - - - - 1000-2000SNCR 35 CUECost 1,518 192 396178 2,223IPM1,796 206 447178 2,510STAPPA - - - - 800-1500LNB 35 CUECost 1,105 25 173178 973IPM-- -178 -STAPPA - - - - 200-1000NGR 55 CUECost 2,661 1,419 1,777 280 6,350IPM - - - 280 -STAPPA - - - - 500-20002 Coal 22 447 SCR 90 CUECost 6,757 384 1,292 402 3,213 173 1,777 156 402 200-7227IPM 5,932 223 1,021 402 2,537STAPPA - - - - 1000-2000SNCR 35 CUECost 1,437 168 361156 2,310IPM1,796 233 475156 3,036STAPPA - - - - 800-1500LNB 35 CUECost 1,105 25 173156 1,107IPM-- -156 -STAPPA - - - - 200-1000Costs of SO2 Controls for EGUsCosts of NOx Controls for EGUsC-21Table C-11. Xcel Energy/Bay Front Facility (Wisconsin)State Facility Unit FuelCapacity(MW)BaselineEmissions(tons)ControlTechnology%Reduction Cost ModelTotal CapitalInvestment[$M2005]TotalO&M Cost[$M2005]TotalAnnualizedCost [$M2005]EmissionReduction(tons)CostEffectiveness[$2005/ton]LowestAnnualizedCost($M2005)HighestAnnualizedCost($M2005)LowestEmissionsReduced(tons)HighestEmissionsReduced(tons)CostEffectiveness($2005/ton)NGR 55 CUECost 2,661 1,419 1,777 246 7,227IPM-- -246 500-2000STAPPA -- --1,2855 Coal 30 517 SCR 90 CUECost 7,216 411 1,381 466 2,966 212 1,505 181 466 200-5287IPM7,439 229 1,229 466 2,640STAPPA -- --1000-2000SNCR 35 CUECost 1,515 188 392181 2,165IPM1,582 419 631181 3,486STAPPA -- --800-1500LNB 35 CUECost 1,352 30 212181 1,170IPM-- -181 -STAPPA -- -181 200-1000NGR 55 CUECost 2,862 1,120 1,505 285 5,287IPM-- -285 -STAPPA -- --500-2000Plant Total74 1,473558 5,058 516 1,326 1083-3815C-22Table C-12. Alliant Energy-Wisconsin Power/Edgewater Facility (Wisconsin)State Facility Unit FuelCapacity(MW)BaselineEmissions(tons)ControlTechnology%Reduction Cost ModelTotal CapitalInvestment[$M2005]TotalO&M Cost[$M2005]TotalAnnualizedCost [$M2005]EmissionReduction(tons)CostEffectiveness[$2005/ton]LowestAnnualizedCost($M2005)HighestAnnualizedCost($M2005)LowestEmissionsReduced(tons)HighestEmissionsReduced(tons)CostEffectiveness($2005/ton)WI Alliant Ener3 Coal 751,864LSD 90 CUECost 47,351 5,328 12,421 1,677 7,406 5,955 14,711 1,677 1,770 150-8310IPM 25,747 2,098 5,955 1,677 3,550STAPPA -- -- 150-4000LSFO 95 CUECost 60,864 5,593 14,711 1,770 8,310IPM 44,012 2,618 9,211 1,770 5,203STAPPA -- -- 200-50004 Coal 334 8,277 LSD 90 CUECost 86,380 17,366 30,306 7,449 4,068 17,153 31,414 7,449 7,863 150-4068IPM 63,174 7,690 17,153 7,449 2,303STAPPA -- -- 150-4000LSFO 95 CUECost 98,542 16,653 31,414 7,863 3,995IPM 91,600 8,963 22,684 7,863 2,885STAPPA -- -- 200-50005 Coal 42210,672LSD 90 CUECost 87,931 13,842 27,014 9,605 2,813 19,892 30,888 9,605 10,138 150-3047IPM 73,892 8,823 19,892 9,605 2,071STAPPA -- -- 150-4000LSFO 95 CUECost 107,638 14,764 30,888 10,138 3,047IPM 101,846 10,432 25,689 10,138 2,534STAPPA -- -- 200-5000Plant Total 831 20,81243,000 77,013 18,731 19,771 2296-3895State Facility Unit FuelCapacity(MW)BaselineEmissions(tons)ControlTechnology%Reduction Cost ModelTotal CapitalInvestment[$M2005]TotalO&M Cost[$M2005]TotalAnnualizedCost [$M2005]EmissionReduction(tons)CostEffectiveness[$2005/ton]LowestAnnualizedCost($M2005)HighestAnnualizedCost($M2005)LowestEmissionsReduced(tons)HighestEmissionsReduced(tons)CostEffectiveness($2005/ton)WI Alliant Ener3 Coal 75865SCR 90 CUECost 11,459 844 2,384 779 3,061 497 3,501 303 779 200-7355IPM 14,589 590 2,550 779 3,275STAPPA -- -- 1000-2000SNCR 35 CUECost 1,815 253 497303 1,641IPM 2,337 1,233 1,547 303 5,109STAPPA -- -- 800-1500LNB 35 CUECost 3,382 76 530303 1,751IPM -- -303 -STAPPA -- -- 200-1000NGR 55 CUECost 3,743 2,998 3,501 476 7,355IPM -- -476 -STAPPA -- -- 500-20004 Coal 3343,285SCR 90 CUECost 28,738 3,183 7,045 2,957 2,383 1,232 14,090 1,150 2,957 200-7797IPM 43,182 2,370 8,174 2,957 2,764STAPPA -- -- 1000-2000SNCR 35 CUECost 3,322 785 1,232 1,150 1,071IPM 4,382 6,012 6,601 1,150 5,741STAPPA -- -- 800-1500Costs of SO2 Controls for EGUsCosts of NOx Controls for EGUsC-23Table C-12. Alliant Energy-Wisconsin Power/Edgewater Facility (Wisconsin)State Facility Unit FuelCapacity(MW)BaselineEmissions(tons)ControlTechnology%Reduction Cost ModelTotal CapitalInvestment[$M2005]TotalO&M Cost[$M2005]TotalAnnualizedCost [$M2005]EmissionReduction(tons)CostEffectiveness[$2005/ton]LowestAnnualizedCost($M2005)HighestAnnualizedCost($M2005)LowestEmissionsReduced(tons)HighestEmissionsReduced(tons)CostEffectiveness($2005/ton)LNB 35 CUECost 8,929 200 1,400 1,150 1,218IPM -- -1,150 -STAPPA -- -- 200-1000NGR 55 CUECost 8,058 13,007 14,090 1,807 7,797IPM -- -1,807 -STAPPA -- -- 500-20005 Coal 4221,971SCR 90 CUECost 33,963 3,698 8,263 1,774 4,659 863 16,789 690 1,774 200-15491IPM 51,214 2,727 9,610 1,774 5,419STAPPA -- -- 1000-2000SNCR 35 CUECost 3,533 388 863690 1,251IPM 5,481 3,792 4,529 690 6,566STAPPA -- -- 800-1500LNB 35 CUECost 7,536 169 1,182 690 1,713IPM -- -690 -STAPPA -- -- 200-1000NGR 55 CUECost 9,791 15,474 16,789 1,084 15,491IPM -- -1,084 -STAPPA -- -- 500-2000Plant Total 831 6,1212,592 34,380 2,142 5,509 1210-6240C-24Table C-13. Alliant Energy-Wisconsin Power/Nelson Dewey Facility (Wisconsin)State Facility Unit FuelCapacity(MW)BaselineEmissions(tons)ControlTechnology%Reduction Cost ModelTotal CapitalInvestment[$M2005]TotalO&M Cost[$M2005]TotalAnnualizedCost [$M2005]EmissionReduction(tons)CostEffectiveness[$2005/ton]LowestAnnualizedCost($M2005)HighestAnnualizedCost($M2005)LowestEmissionsReduced(tons)HighestEmissionsReduced(tons)CostEffectiveness($2005/ton)WI Alliant Energy/N1 Coal 108 4,206 LSD 90 CUECost 54,250 8,018 16,145 3,786 4,265 8,642 17,324 3,786 3,996 150-4335IPM36,950 3,107 8,642 3,786 2,283STAPPA - - - - 150-4000LSFO 95 CUECost 66,535 7,357 17,324 3,996 4,335IPM 60,457 3,864 12,921 3,996 3,233STAPPA - - - - 200-50002 Coal 111 4,127 LSD 90 CUECost 54,432 7,949 16,103 3,714 4,336 8,738 17,320 3,714 3,920 150-4418IPM 37,434 3,131 8,738 3,714 2,353STAPPA - - - - 150-4000LSFO 95 CUECost 66,701 7,328 17,320 3,920 4,418IPM 61,054 3,898 13,044 3,920 3,327STAPPA - - - - 200-5000Plant Total219 8,33317,381 17,320 7,500 7,916 2318-2199State Facility Unit FuelCapacity(MW)BaselineEmissions(tons)ControlTechnology%Reduction Cost ModelTotal CapitalInvestment[$M2005]TotalO&M Cost[$M2005]TotalAnnualizedCost [$M2005]EmissionReduction(tons)CostEffectiveness[$2005/ton]LowestAnnualizedCost($M2005)HighestAnnualizedCost($M2005)LowestEmissionsReduced(tons)HighestEmissionsReduced(tons)CostEffectiveness($2005/ton)WI Alliant Energy/N1 Coal 108 1,262 SCR 90 CUECost 14,058 1,159 3,049 1,136 2,684 487 4,904 442 1,136 200-7066IPM18,912 849 3,391 1,136 2,986STAPPA - - - - 1000-2000SNCR 35 CUECost 2,033 326 599 442 1,357IPM 2,716 1,871 2,236 442 5,063STAPPA - - - - 800-1500LNB 35 CUECost 3,108 70 487 442 1,103IPM - - - 442 -STAPPA - - - - 200-1000NGR 55 CUECost 4,294 4,327 4,904 694 7,066IPM - - - 694 -STAPPA - - - - 500-20002 Coal 111 1,238 SCR 90 CUECost 14,135 1,161 3,061 1,114 2,747 496 4,830 433 1,114 200-7093IPM 19,272 850 3,440 1,114 3,087STAPPA - - - - 1000-2000SNCR 35 CUECost 2,039 322 596 433 1,375IPM 2,746 1,871 2,240 433 5,171STAPPA - - - - 800-1500LNB 35 CUECost 3,163 71 496 433 1,145IPM - - - 433 -STAPPA - - - - 200-1000NGR 55 CUECost 4,343 4,246 4,830 681 7,093IPM - - - 681 -STAPPA - - - - 500-2000Plant Total219 2,500983 9,734 875 2,250 1124-4326Costs of SO2 Controls for EGUsCosts of NOx Controls for EGUsC-25Table C-14. Boise Cascade Corporation (Minnesota)State FacilityUnit FuelCapacity(MW)BaselineEmissions(tons)ControlTechnology%Reduction Cost ModelTotal CapitalInvestment[$M2005]Total O&MCost[$M2005]TotalAnnualizedCost [$M2005]EmissionReduction(tons)CostEffectiveness[$2005/ton]LowestAnnualizedCost ($M2005)HighestAnnualizedCost($M2005)LowestEmissionsReduced(tons)HighestEmissionsReduced(tons)CostEffectiveness($2005/ton)MI Boise Cascade Corp. 2 Gas 38 48 LSD 90 CUECost 51,688 3,169 10,912 43 254,398 3,966 10,912 43 45 92472-242492IPM 18,130 1,373 4,089 43 95,333Khan (2003)* 17,294 1,376 3,966 43 92,472STAPPA ---- 1,011LSFO 95 CUECost 32,346 2,199 7,044 45 155,586IPM 33,769 1,730 6,789 45 149,938Khan (2003)* 17,294 1,376 3,966 45 87,605STAPPA ---- 1,011Plant Total38 483,966 10,912 43 45 92472-242492State FacilityUnit FuelCapacity(MW)BaselineEmissions(tons)ControlTechnology%Reduction Cost ModelTotal CapitalInvestment[$M2005]Total O&MCost[$M2005]TotalAnnualizedCost [$M2005]EmissionReduction(tons)CostEffectiveness[$2005/ton]LowestAnnualizedCost ($M2005)HighestAnnualizedCost($M2005)LowestEmissionsReduced(tons)HighestEmissionsReduced(tons)CostEffectiveness($2005/ton)MI Boise Cascade Corp. 1 Gas 38 104 SCR 80 CUECost 7,076 398 1,349 84 16,146 1202,769 37 81 424-43450IPM 2,768 129 50184 5,990Khan (2003)* 2,485 238 57284 6,847STAPPA ---- 1,354SNCR 50 CUECost 1,366 116 29952 5,733IPM 1,353 219 40152 7,678Khan (2003)* 1,307 299 47552 9,094STAPPA ---- 2,193LNB 35 CUECost 2,174 49 34137 9,322IPM 1,023 213937 3,805Khan (2003)* 792 61 16737 4,569STAPPA ---424NGR 61 CUECost 3,041 2,360 2,769 64 43,450IPM ---64 -Khan (2003)* 446 61 12064 1,891STAPPA ---- -Costs of SO2 Controls for ICIsCosts of NOx Controls for ICIsC-26Table C-14. Boise Cascade Corporation (Minnesota)State FacilityUnit FuelCapacity(MW)BaselineEmissions(tons)ControlTechnology%Reduction Cost ModelTotal CapitalInvestment[$M2005]Total O&MCost[$M2005]TotalAnnualizedCost [$M2005]EmissionReduction(tons)CostEffectiveness[$2005/ton]LowestAnnualizedCost ($M2005)HighestAnnualizedCost($M2005)LowestEmissionsReduced(tons)HighestEmissionsReduced(tons)CostEffectiveness($2005/ton)2 Gas 38 331 SCR 90 CUECost 7,331 421 1,406 265 5,307 1691,406 116 291 424-27803IPM 2,749 127 497265 1,875Khan (2003)* 2,511 241 579265 2,185STAPPA ---- 1,354SNCR 35 CUECost 1,448 159 354166 2,137IPM 1,347 217 398166 2,401Khan (2003)* 1,321 304 482166 2,908STAPPA ---- 2,193LNB 35 CUECost 2,159 48 33937 9,258IPM 21,016 1,017 37 27,803Khan (2003)* 801 61 16937 4,623STAPPA ---4243 Gas 35 25 SCR 90 CUECost 6,669 361 1,257 20 62,895 1171,652 9 19 797-108392IPM 2,624 97 45020 22,500Khan (2003)* 2,413 230 55420 27,716STAPPA ---- 2,330SNCR 35 CUECost 1,322 101 27912 22,303IPM 1,307 96 27112 21,728Khan (2003)* 1,269 287 45812 36,626STAPPA ---- 3,116LNB 35 CUECost 2,061 46 3239 36,942IPM 1,550 28 2369 27,018Khan (2003)* 769 58 1629 18,501STAPPA797NGR 61 CUECost 2,975 1,252 1,652 15 108,392IPM ---15 -Khan (2003)* 433 58 11715 7,648STAPPA ---- -Plant Total76 4364065,827 161 392 2519-14849* "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-27APC 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-28Table 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-29Table 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-30Table 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-31Table 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) 345-8556II 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) 345-85569



### 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) 345-8556In the matter of: Plan to Address Regional Haze, taken 011 February 26, 2009 

### Page I

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Fraley, Cooper & Associates (614) 228-0018 (800) 852-6163 (740) 345-8556In 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) 345-8556GLATFELTER

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.comMs. 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 AffairsIN REPLY REfER TO· 

# United States Department of the 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 of Air 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 of the 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 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.

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 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 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 of the 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 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

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 of these 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 ODP AC 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 Z 009

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,



# '"**~ib;,;,;~ ORe~;lri** **~~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 of the 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 of the 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 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 1 

### areas. 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 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.

• 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 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 its fair share of emission 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 of such 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
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.

• 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.

• 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 basis for 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 

## if the 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 of strategies

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 procedures for 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 of other

programs having the potential to contribute to impairment of visibility in Class I



### areas.

This is aformal consultative process. The basis for 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 of 40 

### CFR 51.308(i) and is not responsible 

## if a 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 

## + NO x 

### + PM 10 

## +
H 2 S04), but in fact a metric of LID was used (where L 

### = tons per year of S02 

## +
NO
x ). 

### 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 and participating in the CA1R cap and trade program/or S02 and NOx are allowed to treat the CA1R 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 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 P M1 0 may be used an indicator for PM in this step of the

determination and thus, P M10 can be used for 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 of Air 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 of Agriculture (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 of Interior. 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 of Interior to contribute to a common sense of purpose 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 of the methods used in the SIP. Calculations that include only portions of
established methods or utilize unique approaches will be better understood if the 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 if they 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 of the RHR prescribed factor analysis (if applicable). Consider discussing
whether BART levels apply to individual or grouped source categories.

### Area of Influence

The area of influence of significant 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 of transported 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 of the

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) if both 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 of progress 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 of smoke management techniques for agricultural and forestry management practices in the development of the LTS part of the 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. If fire 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 of states identifics and addresses
similar agreed upon goals for each Class I area within a common area of influence.

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 of similar progress goals, regardless of release 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 of the 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 Impl ementation 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 (Ohi o SIP for Regional Haze p. 5-15)

The US Forest Service would li ke 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 upd ate 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 (Ohi o 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 regiona l haze SIP. Specific listing of the other rule and requireme nts within the regional haze portion of the SIP provides linki ng mechanism so that changes in other programs require a review of the regional haze portion of the SIP as well. The long-te rm 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 obligatio n 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 indicat ed on page 6 of the SIP. Page 59 of LADCO’s Technical Support Document (TSD) identifies the known controls (on-the-books) in cluded 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, includ ing in Chicago-Gary,-Lake County, IL,IN; and Milwaukee, Racine, WI

Off-Highway Mobile Sources

• Federal control programs in corporated into NONROAD model (e.g., nonroad diesel rule), plus the evaporative Large Spark Ignition and Recr eational Vehicle standards

• Heavy-duty diesel (2007) engi ne 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 Ohio 2 

### , 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 contro l factors for three sources in Wayne County, MI. These control factors were not applied in the region al-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 wil l be updated with additi onal clarification
based on comments consistent with the Regional Haze program requirements.

Comment 4: Emission Inventories (Ohi o 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 greatl y expanded the discussion of emissions inventories and project ions from the October 2008 draft. The State should clar ify 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 emi ssions inventories provide references to the data sources. The 2002 base year inv entory data is intended to be actual emissions data (from point and area sources) and was obtained for USEPA’s national emi ssions 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 mode ling. However, as indicated in the SIP, for 2005, on-road data (or mobile source emissions) was obtained again from USE PA’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 Stra tegy report provide add itional details on inventories and modeling protocol s (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 inve ntories in this SIP. The SIP
document discusses both the 2002 (Base K) and 2005 (Base M) inventories although only the 2 005 inventory was used for the future 2018 projections. Ohio EPA is clarifying this in Section 7.

Section 6.1, detailed nonpoint so urce 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 purpos e of which is to allow for consideration of fugitive particu late emissions in Ohio. These fugitive emissions should not be di rectly compared to the emissions projected in the LA DCO modeling.

Comment 5: We appreciate the stat ement on page 34 that ODAPC will
enforce all emissions limitations and control measures used to meet reasonable progress goals th rough this SIP action. We interpret this to mean that the overall emissions targets, noted on Pages 5 through 7, and the ru les and measures establish to meet them, are enforceable as requirements for regional haze as well. (National Park Servi ce and U.S. Fish and Wildlife Service)

Response 5: The Regional Haze program requi res that emissions strategies themselves, used for visibility im provement 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 furt her clarify, the RHR states:

“Some commenters expressed concern that the State would be subject to sanctions or enfor cement actions in the event that a State fails to meet a reasonable progress target. As noted above, the reasonabl e progress goal is a goal and not a mandatory standard which mu st 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 towa rd that goal over a 10-year period, the goal itse lf is not enforceab le. All that is ‘‘enforceable’’ is the set of c ontrol measures which the State has adopted to meet that goal.”

Comment 6: Area of Influence (Ohi o 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 Planni ng Organizations (MWRPO)
assessments of baseline and the u se 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 do es identify which Class I areas are affected by emissions from Oh io by summarizing contribution assessment work of the MWRPO, th e Visibility Improvement State and Tribal Association of the Southeast (VISTAS), Mid
Atlantic and North East Visib ility Union (MANE-VU) regional planning organizations. The Ohio SIP must address all
emissions which are “reasonabl e anticipated to cause or contribute to” visibility impairme nt 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 identifi ed Class I areas. The area
of influence information should al so be used in the long-term strategy decision on what cont rol 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 Visibi lity Resulting from Projected Changes to Emissions Sections of the SIP document. We anticipate the changes will ad dress the comment above.

Comment 8: Area of Influence (Ohi o 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 PresidentialRange-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 incl ude 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 cont ribution assessment report, it appears that the analyses looked at Great Gulf and given its proximity to Pres idential Range-Dry Riv er, 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 Goal s 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-pr ogress “glide path” will not be achieved. However, page 36 disp lays 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 insignifi cant. (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 visibilit y 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 additi onal 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 s upported by the Clean Air Act Reasonable Progress factor-ana lysis. Please also provide specific information regarding c onsultation 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 stat es. 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 implement ing additional strategies to reduce both ozone levels and PM2.5 (and precur sor) levels as a part of implementation of the new ozone and PM2.5 standards. It is our

### Page | 8 intent to revisit and reevaluat e our Regional Haze commitment during our next review period wh ich will follow im plementation of
these new standards. In the meant ime, Ohio believes we will continue to see the progress that will be needed under the Regional Haze program.

With respect to the MRPO contribut ion threshold of 2 percent; this
level was not chosen as a level to determine significance of a contribution. Rather, the purpose of the 2 per cent level was as a minimum threshold for including a state as a cont ributing state.

With respect to Missouri, Ohio EPA participated in multi-state consultation process regarding its Cla ss I areas specifically in April and May of 2007 (see Appendix N of Missouri’s Regional Haze SIP). With respect to Ohio’s im pact 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 MR PO 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 represent ative of Ohio’s “fair share” of reductions necessary for Missouri to meet its reasonable progress goals. This is further s upport 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 suffi cient 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 ar eas. These ongoing programs such as CAIR, BACT, or BART have been demonstrated to be very cost effective in reduc ing 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 contri butor as demonstrated above and
Missouri states in its SIP that existing program s are sufficient for its
state and the other cont ributing 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 Stat es with Class I areas to identify and analyze
the “emissions measures that w ould 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. T hese 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 sour ce subject to the measures.”

The RHR requires states with em issions that may affect Class I

areas in another state to devel op a “long-term strategy” with measures “necessary to achieve the reasonable progress goals established by states having mandat ory Class I Federal areas.” In

### Page | 11 establishing this strategy, the st ates are required to included all “measures needed to achieve it s apportionment of emission reduction obligations agreed upon” during the collaborative process. In develop ing the long-term strat egy 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 tec hniques,” “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 t he 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 flex ibility 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 stringen cy of control, if any, for selected sources or activities, or some combin ation of both. The factors may be considered both individually and/or in
combination. As noted in sect ion 4.1, given the significant emissions reductions that we anticipate to result from BART, the CAIR, and the implementati on of other CAA programs, these reductions may be all that is necessary to achieve reasonable progress in the firs t 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 Ac t requirements including the reasonable progress factor-analysis approach.

Comment 10: Reasonable Progress Goal s 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 (Voyag eurs, Boundary Waters, Isle Royale, and Seney). This f actor-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 stil l 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 diffic ult process within the regional haze SIP development is a ddressing reasonable progress for all Class I areas affected by emissi ons from a State. On pages 28 through 37, the SIP re views ongoing programs and assesses current and future contribution to visibility impairment as the basis for re lying 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 w as 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 analys is 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 ar eas. It is the responsibility of states shown to impact a Class I ar ea in another state to document the technical basis, including model ing, monitoring and emissions information that the state is relying on to determine its apportionment of emission r eduction obligations.

USEPA has clarified t hat “some States may conclude that control strategies specifically for protec tion 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 se ts a reasonable progress goal all of the following four fa ctors are weig hed together:

• Cost of compliance;

• Time necessary for compliance;

• Energy and nonair quality impacts;

• Remaining useful life of existing sources

USEPA does not set any “presumpti ve targets” and gives states the “flexibility in determining thei r 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 th is amount of progress during the first long-term strategy, and to de termine whether those measures
are reasonable based on the statutory factors” and then consults
with other states that area antici pated 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 determi nes 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 t he 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 incl ude the four factors identified above as a requirement for the long- term strategy because they are included as part of the r easonable 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 progre ss 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 Goal s 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 Br ook, 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 M ANE-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-V U 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, elect ric generating facilities, and includes a general reduction target for SO 2 

### emissions from all point sources. The MANE-VU re quest acknowledges that their request could be met using a co mbination 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 th an 2% contribution from Ohio on New Hampshire’s Class I areas. The modeling shows that 62% of Vermont’s visibility impact co mes from MANE-VU states in 2018 with an additional 8% from Pennsylv ania. 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. Oh io participated, along with other MRPO states, in consultations and discussions with MANE-VU and was provided a consultation summa ry by MANE-VU on August 6, 2007. Ohio EPA provided a response on October 3, 2007. In this response, Ohio reques ted additional informat ion 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 Availabl e Retrofit Technology (BART)

• 90% (or greater) reduction in SO 2 

### 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 contribut e 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 (poi nt, area, on-road, and off-road) SO 2 

### emissions relative to on-the-books, on-the-way 2018 projections

• Continued evaluation of other measures, in cluding measures to reduce SO 2 

### and NO x 

### emissions from coal-b urning facilities and promulgation of new source per formance standards for wood
combustion

• Further reduction in power plant SO 2 

### (and NO x 

### ) 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 a nd exceeded at all MANE-VU Class
I sites."

In MANE-VU’s May 13, 2008 2018 Visi bility 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 incl uded control measures and
emission reductions that went beyond currently existing regulations. Commenters sugges ted that since the CAIR program and other “on the books” or “on the way” measures are projected to achieve un iform rates of progress as previously modeled, additional reductions to both EGU and non-EGU sectors were unnece ssary. As described below, there are two reasons why MA NE-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 additi onal measures beyond implementation of CAIR. This re sult is due, in part, to our assumptions about the effectiveness of CAIR. We believe that it is appropriate for MA NE-VU to take a conservative approach to estimating the potential for emissions reductions under the CAIR program. Th erefore MANE-VU added EGU

### Page | 17 emissions to estimate the impact of banking and trading under CAIR. Additional EGU re ductions 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 in corporated into MANE-VU’s Ask results in an additional 0.55 deciview, or 2%, c hange. Important to note; in all cases, including on-the-books c ontrol, the uniform rate of improvement is met at Arcadia as depicted graphically below in
MANE-VU’s document:

The same results are seen in th is document for all MANE-VU Class
I areas.

Ohio EPA committed to continuing wo rk with MANE-VU states but continues to believe that on-the-books controls, for this first planning period, represents reasonabl e 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 tak en 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 “A sk” without providing the additional information reques ted by Ohio and others and continuing the consultation process.

To assist in addressing comment s regarding MANE-VU’s “Ask”, Ohio EPA will be adding additional discussions in the SIP.

### Page | 19 Comment 12: Reasonable Progress Goal s 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 (O hio SIP for Regional Haze p. 3-4, 36)

As part of the SIP and the stra tegy to implement the SIP, we request that Ohio express its in tent to improve consultation and coordination with all imp acted FLMs, including the Forest Service. For example, the For est 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 cl osely 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 curre nt SIP until forwarded by the same NPS colleague. We are disappointed by this lack of
coordination and consultation a nd are committed to improving this situation. (USDA Forest Service)

Coordination and Consultation (O hio SIP for Regional Haze p. 3-4, 36)

Given the withdraw of the previ ous (September 2008) draft and significant changes made to the current draft of the SIP the FLM has not had 60 days to comme nt prior to the hearing to be held on February 26, 2009. Addi tionally, 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 SI P 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 th at States consult with FLMs before adopting and submit ting 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) assessme nt of impairment of visibility in any Class I area; and, (i i) recommendations on the development of the RPG an d 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 imple mentation 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 procedur es is 40 CFR 51.308(i)(4). To satisfy this requirement, Stat es 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) comm unicating 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 th e 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 b est visibility days at Class I areas potentially affected by emissi ons from within the State. We request Ohio to recognize, in the regional haze SIP, the requirements of full consulta tion 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 wi ll consult with federal land managers, for all sources subject to NSR/PSD requirement, early in the permitting process.

We are also concerned that Oh io 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 proce dures 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 wh ich FLM notification should occur, including what informat ion should be submitted for FLM review, when this informat ion should be submitted, and when FLM concerns and agency responses should appear in a public notice. The FLMs are ch arged with an “affirmative responsibility” under the Clean Ai r Act (CAA) to protect the air quality related values (AQRVs), in cluding 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 fo r 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 recen t 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 enab le, 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 coor dination requirements in Section 3 of Ohio’s SIP:

“Ohio will continue to coordi nate 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 Cla ss 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 wo rth 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 requirement s. Ohio EPA urges the FLMs to participate in the public comment pr ocess related to the rulemaking
action.

Ohio EPA apologizes for the conf usion regarding our first 2008 draft. Ohio EPA’s SIP Section has recently acquired several new staff and management. The Secti on’s new manager has ensured
that FLM coordination will occu r smoothly on all Regional Haze related matters in the future. Sign ificant 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 th is time in order to address comments. As a result of comment s, Ohio EPA provided a second, much improved draft, on Decem ber 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 st aff and Ohio requested any comments on the second draft qui ckly. However, FLM staff indicated they were currently re viewing a significant number of SIPs. Ohio committed that if t he FLM staff could not review and comment on Ohio’s second draft bef ore it was necessary for Ohio to submit its SIP, Ohio would commit to reviewing and addressing

### Page | 23 comments from the FLM staff dur ing the forthcoming public comment period. Ohio then submi tted its Regional Haze SIP on December 31, 2008. We underst and 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 obvious ly 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 impa ct 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 impact s when the permitting process for those new sources takes place. (Nachy Kanfer, representing Sierra Club)

Response 13: The modeling conducted by LADC O and other states’ RPOs does account for new sources. Projecti ng new source growth is a more challenging aspect for modeling fu ture emissions, especially when considering the lengthy planning periods being forecasted by the models. Additional informati on regarding growth factors incorporated into Ohio’s modeling for the various sectors, including EGUs can be found in EH Pech an’s “Development of 2005 Base Year Growth and Control Factors fo r Lake Michigan Air Directors Consortium (LADCO)” final report at: http://www.ladco.org/reports/tech nical_support_document/referenc es/ladco_2005_base_yr_growth_and_c ontrols_report_final.pdf

.

Ohio EPA, as part of new source review, does address impacts on Class I areas. Please refer to t he following Ohio Administrative Code rule applicable to attainment areas:

3745-31-17 – “Attainment provisions - additional im pact analysis” at http://www.epa.ohio.gov/portals/ 27/regs/3745-31/3745-31-17f.pdf

.

This rule requires that any new s ource being proposed in an area designated as attainment must pr ovide an analysis of all possible impairment to visibility.

Whereas for new sources in nonattain ment 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 – “Nonattainm ent 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 Goal s and Long Term Strategy (Ohio SIP for Regional Haze p. 26-35)

Page 27 states that ICI boiler c ontrols 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 t on 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 tabl e you can see that the cost per visibility improvement ($million/deci view) is greater for EGU control compared to ICI boiler control.

Comment 15: Reasonable Progress Goal s 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 r easonable 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 reduc tions to be accounted for in Ohio’s fair share of emission reductions. (USDA Forest Service)

Response 15: Ohio EPA will rephrase the statem ent. The intent was that
emission reductions that are being achieved, or will be achieved, by Ohio and other states consti tutes reasonable progress.

Comment 16: As another example, on page 35, right -- this document, this is the Regional Haze SIP by the wa y. 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 pr ogress. 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 impac ted 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 discu ssed previously in Ohio’s response to comments and as will be clarified in t he SIP document,
other than the MANE-VU “Ask”, other states with Class I areas are in agreement with Ohio EPA’s app roach 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 clarif ied in the SIP document.

USEPA’s RHR did not intend that states develop programs that achieve the 2064 goal within the fi rst 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 visibilit y 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 re visions of implementation plans as needed to continue progress toward the national visibility goal.”

### Page | 27 Ohio EPA, because of the lack of Cla ss I areas within the state, is not required to set “reasonable pr ogress 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 measur es will provide for reasonable progress during the 10 to 15 year period.”

USEPA has clarifie d that “some States may conclude that control strategies specifically for protec tion 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 Oh io EPA has made and believes it does provide for the necessary im provements for the first planning period. Upon a review of progress in the future, Ohio EPA may
determine additional measures ma y 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 visi bility 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 fo r 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 contro ls 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 a ddressing proposed sources as well, including the AMP-Ohio genera ting station. And that is in order -- if we really are to achieve all of the public health benefits, the air quality benefi ts, visibility benefits and obviously our national parks, th at 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 seeki ng to do the bare minimum here. For example, on page 20 there's a sentence while Ohio has made the decision that CAIR wi ll 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 esp ecially air emissions that reduce visibility in Class I ar eas. (Nachy Kanfer, representing Sierra Club)

Response 19: Ohio EPA disagrees t hat CAIR is a “bare minimum.” The CAIR program, and its impending replac ement (the Transport Rule) is projected to account for signific ant 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 emissi ons 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 clai ming 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, repre senting Sierra Club)

Response 20: In USEPA’s implementation guideli nes 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, CA IR will provide for greater reductions than if BART were required.

Additionally, as clarified in t he revised Regional Haze SIP, USEPA proposed a replacement to the CAIR program, the Transport Rule, on July 6, 2010. [75 FR 45210] U pon finalization, it will further assist states in addressing their obligations regarding regionally transported pollution by pr oviding 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 l ooking at various answers on pages 27 and 31, there are these statements, right, controlling EGUs beyond CAIR control levels wo uld have the most effect on visibility improvement. And again, modeling indicated that significant beyond-CAIR reductions from EGUs - especially for sulfur dioxide - would be th e 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 c ontrols on each one of these. (Nachy Kanfer, repre senting 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 pl anning 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 fi rst 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 ext ensive BART analysis or modeling because of Ohio’s decision to adopt USEPA’s option that CAIR will suffice for BART at EGUs. Ther efore, per the response above, additional justificati on is not required for why BART is not established for these sources.

Comment 22: Verification and Contingenc ies (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 locat ion 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 diff erent from those predicted?

We would also like Ohio to co nsider 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 Reaso nable Progress section of the December 2008 SIP is greatly improved from the previous draft. We appreciate the di scussion of EPA’s Clean Air Interstate Rule (CAIR) and unde rstand 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 em issions reductions to be implemented under that program. We request that ODAPC acknowledge this uncertainty regarding the emissions projections for its sources and th at the SIP commit the State to
re-examine actual and future em issions 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 strate gy. 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 comp rehensive review periods. Ohio EPA is currently beginning plann ing 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 impac t on Regional Haze and allow for greater improvements in the fu ture. 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 Ru le. Ohio EPA believes the Transport Rule, when finalized, wil l 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 nec essary, nor is it required, for contingency measures to be incor porated 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 pr ogram 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 inte rim and comprehensive review requirements in our SIP.

Comment 23: Coordination and Consultati on (Ohio SIP for Regional Haze p. 3-4, 36)

Also, coordination should o ccur during SIP revisions (including reasonable progr ess reports) and at steps necessary to address adequacy of the SIP. (USDA Forest Service)

The SIP should contain provis ions for ongoing coordination
and consultation with the Fede ral 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 Fe deral 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 addr essed the FLM coordination requirements in Section 3 of Ohio’s SIP:

“Ohio will continue to coordi nate and consult with the FLMs during the development of future progress reports and revisions of this plan , as well as during t he 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 in itial 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 t ons per year of SO 2 

### + NO x 

### + PM 10 

### + H 2 

### SO 4 

### ), but in fact a metric of L/D was used (where L = tons per year of SO 2 

### + NO x 

### ). 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. (U SDA Forest Service)

Through interaction with the MW RPO and the ODPAC over the last year, we have reviewed th e air quality modeling performed to assess sources subject to BART. We agree with ODAPC’s conclusion that only the P. H. Gla tfelter facility is subject to BART. (National Park Service a nd 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 substi tute for the application of BART controls per 40 CFR 51.308(e)(4). This does not mean EGUs are exempt for SO2 and NO x, only that CAIR satisfies the BART requirement for tho se pollutants. The remaining visibility pollutants to consider for determining BART-eligible sources are PM, and, using j udgment, VOCs, and ammonia. For PM, the July 6, 2005, fina l 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 di rection. (USDA Forest Service)

With respect to the decision to accept CAIR as Best Available Retrofit Technology (BART) for elec tric 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 Pa rk Service and U.S. Fish and Wildlife Service)

Response 24: PM was not included in the denominat or because of the relatively small quantities involved and t he lack of impact on visibility determined through modeling.

LADCO performed an analys is of 149 BART eligib le sources in the LADCO states’ area and found t hat PM emissions were insignificant and; t herefore, excluded PM from the analysis.

### Page | 34 This determination was made bas ed on the approach provided by USEPA in the BART Guidelines . Under a cumulative modeling approach, modeling of tota l visibility impacts from all BART-eligible sources in a given stat e can be used to show that they collectively
do not cause or contribute to visibi lity impairment in a Class I area. This approach was used to asse ss the likelihood t hat VOC and PM
emissions will not cause or contri bute 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 impairm ent. The model results show that these emissions do not contribute to visibility impairment (i.e., less than a 0.5 dv impact in any Clas s 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 additi on, ammonia emissions can be excluded from BART review, given that these emissions from the BART-eligible sources are relative ly 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 guid elines. Other than considering NOx, SO2 and PM, US EPA identified “states may use their best judgment to determine whether VOC or ammonia emissions are likely to have an impac t on visibility.” Ohio EPA and

### Page | 35 LADCO determined VOC and ammoni a 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 Stati on 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 abov e –listed quantities of SO2, NOx, and PM2.5, and it was disco vered 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 runswere 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 t he source, if it emitted PM2.5, only, would cause zero days above threshold. Reviewing the detailed results, we find zero da ys for all other Class 1 areas and all years (2002, 2003, 2004). Thus, th e exclusion of PM from BART consideration for the EG U category is a reasonable interpretation of the “cause or contribute” lang uage 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 int end 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 cont rol 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 pe rforming control options (90% removal) should not be consider ed BART as opposed to the 60% removal proposed by the co mpany. 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 de termination 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 a ll days of impact greater than five percent of extinction change while the minimal control, chosen by the ODAPC as BART, st ill results in multiple days at multiple Class I areas of imp acts 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 engin eering 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 th e non-EGU source, this Glatfelter facility, Ohio EPA has really fa iled to justify why they're not requiring maximum reduction of SO2 emissions. We have these three possibilities of cont rol technologies, and they are capable of 90 percent, 90 per cent 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 wr itten 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 t echnologies. (Nachy Kanfer, representing Sierra Club)

Response 25: USEPA recommended in the BART gu idelines that states “use CALPUFF as a screening applicati on in estimating the degree of visibility improvement that may r easonably 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 statut ory factors, to inform decisions related to BART.”

Upon further review, Ohio EPA c oncurs 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 wi ll 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 suffici ent to achieve greater than BART SO2 removal on boiler numbers B 002 and B003 or permanently shutting down the boiler(s). Cont rolling both boilers at 90 percent would have resulted in limiting SO 2 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 poste d 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 thr esholds 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 consid eration 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 source s in the LADCO
states’ area and found that PM emissions were insignificant and; therefore, excluded PM from the analysis. S pecifically, CAMx was run with all point source PM emissions eliminated (“zeroed-out”) to assess the contribution of these s pecies to visibility impairment.
The model results show that thes e emissions do not contribute to visibility impairment (i.e., less than a 0.5 dv impact in any Class I area). Because the PM emission s from just the BART-eligible
sources are much less than those from all point sources, the visibility impact of these emission s 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 c ondensable 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 Gl atfelter boilers are c ontrolled for particulate emissions by an electrostatic precipitator.

In addition, USEPA guidance does not require PM condensable input into modeling: “after the “s elected” 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 Ov erfire 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, Gla tfelter should be permitted to select alternative technologies or strategies that achieve emission levels equivalent or bette r than levels based on the control capabilities of OA SIS. (P.H. Glatfelter)

Response 27: Ohio EPA agrees and will amend the SIP to clar ify that a specific technology will not be required but rather a specific reduction.

Comment 28: The source can take vol untary emissions limits to reduce its impact below the threshold that triggers BART assessment. However, those emissions limits ar e not BART. In addition
those emissions limits should be met more quickly than the five year implementation period fo r a BART-determined limit. Such an approach also need s recognize that reasonable progress requirements would likely require review additional
emission reductions at that s ource, since such emissions reductions are likely very cost-e ffective compared with the alternatives. (National Park Se rvice 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 emi ssion limitation by December 31, 2012. On July 6, 2005, US EP A 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 ye ars after EPA approves the Regional Haze SIP. The Re gional 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 ti me than the SIP provides for electric generating units to meet BART requirements by complying with EPA’s Clean Ai r 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 cont rol technology. One such regulation is the vacated Industri al 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 th e 2018 timeframe set out for SIP reassessment. (P.H. Glatfelter)

Response 29: Oh io EPA has concern with the BART Guidelines and the potential for delay in USEPA appr oving Regional Haze SIPs for the various states. However, after considerat ion of the regulatory requirements and this comment Ohio EPA will revi se 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 cover ing 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 Fina ncial 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 rec ognizes the current economic conditions and how fluctuations in economic conditions can occur over time. Ohio EPA and P.H. Glatfelter have worked t ogether 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 imple 

## l11El nting 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.comMr. 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 8 th 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'L t.---

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 8 th 

### 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.govKathy 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.

.

Si nee re::,: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, DAPC3/7/ 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 8 th 

### Street
Chillicothe, OH 45601 Ross County
Permit #: P0103673, Administrative Modification
A public notice for the draft permit issuance was pub lished 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, conc erns about zoning issues are addressed at the local level. Ohio EPA may respond to those concerns in th is document by identifyi ng 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 te mporary federal CAIR program, currently in place, until the final revisions to the tempor ary 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 OA C 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 tr acking 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 in cinerator 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 t he 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: Administ rative 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 Cont rol 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 ........................................................................................................

................... 31Final 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 administrativ e 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 te rms 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 respons ible 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 c onstructed 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
DirectorFinal 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 administrativ e 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 te rms 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 ApplicableFinal 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 ConditionsFinal 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 right s 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 dev iations 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 measur es 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, Sout heast 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 syst em(s) shall be accompanied by the shutdown of the emission unit(s) that is (are) se rved 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 mo re 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 sc hedule 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 t hat must employ Best Available Technology (BAT) shall comply with the Applicable Emission Limita tions/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 re cordkeeping 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 permitteeFinal 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) quar terly, 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 emissi ons 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 affe cted 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). AllFinal 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 sha ll 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 Titl e 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 complie s 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 ConditionsFinal 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 Di rector 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 allowanc es 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 allow ance 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 NO x 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 unt il 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 emission s 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 oxi des 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 t he 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 tradi ng 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 attachm ents. 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 submitti ng 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 subm ission 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 applic ation 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 sha ll 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 NO x 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 incl udes 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 ConditionsFinal 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 fi re air compartment (Alstom Power).

a) The following emissions unit terms and condition s 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 equi pment 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 anFinal 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) concentri c 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 bynot later than December 31, 2014 by routinely employing the Alstom Power lowNOx concentric firing system and vane clos e-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 emergencyoutages. 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, emissi ons 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 magnit udes 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 temperat ure 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 composit e 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 thisFinal 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 t ank 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 provisi ons 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 includi ng, 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; andFinal 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 calibrati on 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 fr om 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 wasFinal 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 (hardc opy 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 excursi ons 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 emissi ons 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 pur suant to section d)(4) above indicates a
deviation from the allowable sulfur diox ide 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, Southeas t District Office in writing of any record
that shows a deviation of the allowable sulf ur dioxide emission limitation based upon the calculated sulfur dioxide emission rates fr om 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 OhioFinal 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 (i f 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 emissi ons 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 su bmitted 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 t he 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, sulf ur 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 maximu m heat input capacity of 505 million Btu perhour, capable of firing number 2 fuel oil as backup fuel, and is a backup control device for noncondensable gases (NCG) generated by other fac ility emissions units. The emissions unit is controlled with a cyclone/multi-clone, four low-NOx staged

- combustion burners (Advanced Combustion Technology), and an electrostatic pr ecipitator (Environmental Elements Dry Precipitator).

a) The following emissions unit terms and condition s 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 equi pment 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 heatFinal 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). TheFinal 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 emergencyoutages. 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, emissi ons 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 magnit udes 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 temperat ure 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 composit e 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 thisFinal 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 t ank 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 includi ng, 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; andFinal 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 calibrati on 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 fr om 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 andthe 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 wasFinal 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 (hardc opy 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 excursi ons 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 emissi ons 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 pur suant to section d)(4) above indicates a
deviation from the allowable sulfur diox ide 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, Southeas t District Office in writing of any record
that shows a deviation of the allowable sulf ur dioxide emission limitation based upon the calculated sulfur dioxide emission rates fr om 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 OhioFinal 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 (i f 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 emissi ons 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 su bmitted 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 t he 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, sulf ur 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.