101 S. Webster St.

Box 7921 

Madison, Wisconsin 53707-7921 

Telephone 608-266-2621 

FAX 608-267-3579 

TTY Access via relay - 711 

Jim Doyle, Governor

Scott Hassett, Secretary 

June 12, 2007 

Ms. Mary Gade 

USEPA-Region V 

77 West Jackson Boulevard 

Chicago, IL 60604-3608 

Subject: Submittal of Wisconsin's NOx RACT program and miscellaneous non-substantive 

changes for the ozone state implementation plan 

Dear Ms. Gade: 

On behalf of the Wisconsin Department of Natural Resources (WDNR), I am submitting a revision to its state 

implementation plan (SIP) regarding the control of nitrogen oxides per ch. NR 428, Wis. Adm. Code. The 

rules fulfill the CAA requirement for a Reasonably Available Control Technology (RACT) program 

applicable to major NOx sources in the moderate ozone non-attainment area. Also included are several 

miscellaneous non-substantive changes to existing SIP requirements. 

The sections of ch. NR 428, Wis. Adm. Code, comprising the RACT program and miscellaneous changes 

have been approved by the state Legislature and will become effective upon publication. We are now 

submitting these documents as a formal SIP revision by this letter and its attachments. The USEPARegion V checklist and the hearing documentation are included as attachments to this letter. 

If you have any questions regarding this submittal, please call Ralph Patterson of my staff at 608-267-

7546. 

Sincerely, 

/s/ 

Kevin Kessler, Director 

Bureau of Air Management 

cc: Stephan Rothblatt - USEPA Rgion V 

Douglas Aburano - USEPA-Region V 

 Bob Eckdale-AM/7 

 Ralph Patterson-AM/7 

 Larry Bruss-AM/7 

 

wisconsin.gov Printed on

Recycled

Pape

Quality Natural Resources Management 

Through Excellent Customer Service 

dnr.wi.gov 

r
Enclosures: 

Attachment 1 - NOx RACT Rules Greensheet Packages 

Attachment 2 - Adopted rule (to be replaced by published rule) 

Attachment 3 - Public hearing certification 

Attachment 4 - SIP Checklist 
Attachment 1 

NOx RACT Rules 

Green Sheet Packages 

1 
I. Summary of Rule Requirements

The RACT rule establishes NOx emission limitations for major sources in the moderate ozone 

nonattainment areas of Wisconsin which include the counties of Kenosha, Milwaukee, Ozaukee, 

Racine, Sheboygan, Washington, and Waukesha. Major sources in those counties must be in 

compliance with the NOx RACT program by May 1, 2009. The RACT rule has been adopted and 

passed by all necessary state law-making bodies and the rule will be effective upon publication 

expected prior to January 1, 2008. 

The RACT rule requires individual emission units at a major source to be in compliance with specific 

emission limitations defined by source category and fuel types. The NOx emission limitations are 

defined based on available control technologies and cost-effectiveness of up to $2,500 per ton of 

controlled NOx. However, the emission limits are not applicable if the unit operates below a ozone 

season threshold level that is related to cost-effectiveness of control. Once a unit exceeds the 

threshold during any ozone season after the effective date of the rule it is always subject to the RACT 

requirements. A phased compliance schedule is specified for electric utility coal fired boilers to 

account for installation and electric reliability needs. All emission limitations across the source 

categories are expressed on a 30-day rolling basis and are to be met on a year-round basis. 

The rule requires compliance monitoring, record keeping, and reporting specified for each source 

category. For units already required to do so emissions are to be measured according to Part 75 

CEMs monitoring requirements. Remaining units are specified by source category to either install 

and operate continuous NOx emission monitors according to 40 CFR Part 60 methods or perform 

stack testing every two years. The rule specifies the methods and calculations to tabulate emissions 

under each requirement. Units which may emit over 3 lbs. per hour or 15 lbs. per day of NOx are 

required to have a malfunction and abatement plan for the monitoring system. 

The rule establishes a number of default exemptions from the emission limits for units meeting 

certain conditions. The exemptions streamline compliance by identifying sources for which control 

cost-effectiveness is beyond that considered in the rule. These sources otherwise would likely apply 

for a variance to the RACT requirement. The rule identifies minimal recordkeeping requirements to 

ensure continued qualification under the applicable exemption. There are generally two basis for the 

exemptions: 1) unit types or applications with low operation levels; and 2) units which are meeting 

the emission limit and have sufficient monitoring requirements in place or are well controlled and for 

which the incremental control to meet the RACT emission limit is significantly more costly. 

Alternative compliance methods in the rule include emissions averaging, a case-by-case RACT 

determination, and a CAIR equivalency provision. These programs are structured to meet EPA's 

guidance for economic incentive programs, public notification and review, and EPA approval 

requirements. 

Lastly, to address utility reliability issues the rule allows an entity to request a temporary waiver to an 

emission limit. This provision establishes a process to evaluate an emission limit exceedance due to 

an uncontrollable or unforeseeable event during the course of which service must be maintained to 

un-interruptible customers. The request for a waiver is after the event and is subject 

The major provisions of the RACT rule are: 

NR 428.02 Definitions 

NR 428.20 Applicability and purpose. 

2 
NR 428.21 Emission unit exceptions. 

NR 428.22 Emission limitation requirements. 

NR 428.23 Demonstrating compliance with emission limitations. 

NR 428.24 Record keeping and reporting. 

NR 428.25 Alternative compliance methods and approaches. 

NR 428.26 Utility reliability waiver. 

Provisions related to the RACT rule are: 

NR 400 Air pollution control definitions 

NR 439 Reporting, recordkeeping, testing, inspection and determination of 

compliance requirements 

NR 484.04 Incorporation by reference 

Several non-substantive modifications are included in this package addressing the units of applicable 

emission limitations for reciprocating engines under existing NR 428 requirements. 

A description of the rules and supporting documentation attached in the two following sections. The 

first is the background memo to the DNR Board memos for the primary RACT rule adoption. The 

second section refers to a following adoption of a germane modification to the RACT rule. 

 

II. Green Sheet Memo to DNR Board of RACT Rules for Adoption

DATE: April 9, 2007 

 

TO: Members of the Natural Resources Board 

FROM: Scott Hassett, Secretary 

SUBJECT: Reasonably Available Control Technology (RACT) program for major sources of 

nitrogen oxides (NOx) in the moderate ozone nonattainment area and miscellaneous non-substantive 

corrections to current ch. NR 428 requirements. 

Introduction 

In June 2004, the US EPA designated ten Wisconsin counties as nonattainment for the 8-hour ozone 

ambient air quality standard. The counties of Kenosha, Racine, Milwaukee, Waukesha, Washington, 

Ozaukee, and Sheboygan are designated as “moderate” ozone nonattainment and the counties of 

Manitowoc, Kewaunee, and Door as “basic.” The designation triggered federal Clean Air Act 

requirements for adopting rules to reduce oxides of nitrogen (NOx) and volatile organic compound 

emissions sufficiently to demonstrate attainment of the ozone standard by 2009 in basic areas and 

2010 in moderate areas. 

3 
The federal Clean Air Act requires implementation of “reasonably available control technology” 

(RACT) for major stationary sources of NOx and volatile organic compounds (VOC) in the moderate 

ozone nonattainment area by May 1, 2009. The Department is proposing this rule package to meet 

the RACT requirement for major sources of NOx emissions. The Department previously adopted 

RACT rules for VOC to address the old 1-hour ozone standard. Under the 1-hour standard, the State 

had a waiver for implementing NOx RACT. No such waiver exists for the 8-hour standard. 

Therefore, the Department must proceed with developing NOx RACT rules. 

To develop the proposed rules, the Department used the flexibility that EPA allows in creating RACT 

rules. However, these proposed rules do not exceed federal Clean Air Act requirements. 

Potential NOx emission requirements for the basic nonattainment areas are not addressed in this rule 

package, since NOx RACT is required in basic areas only if attainment cannot be demonstrated by the 

2009 ozone season. 

One issue associated with RACT rule development warrants additional attention. EPA allows a state 

to determine if the Clean Air Interstate Rule (CAIR) satisfies NOx RACT requirements for major 

utility coal-fired boilers subject to CAIR. This is often referred to as the "CAIR = RACT" 

determination. This provision is based on EPA’s assessment that the CAIR program, on a national 

basis, achieves greater reductions than the total reductions from a surrogate RACT program only in 

the nonattainment areas. Department legal staff has identified significant legal issues associated with 

EPA’s assessment. In particular, RACT and CAIR are separate requirements in the Clean Air Act 

and implementation of CAIR cannot satisfy the RACT requirement. DNR legal staff indicates that 

both programs must be implemented. See Attachment C for more details. 

1. Why is this rule being proposed? 

The Department is proposing this rule to comply with the requirements of the federal Clean Air Act to 

implement a NOx RACT program for major sources in the moderate 8-hour ozone nonattainment 

areas. The resulting NOx emission reductions will directly contribute to achieving attainment of the 

8-hour ozone and PM2.5 standards and will aid in meeting future haze requirements. 

Additionally, the Department is proposing the rule to make a non-substantive change to ch. NR 428. 

Section NR 428.05(3)(e) currently sets forth emission limitations for reciprocating engines. The units 

for the emission limit currently read grams per brake-horsepower (gr /br-hp). The units are corrected 

in this rule package to read grams per brake-horsepower hour (gr / br-hp-hr). This proposed change 

in the current language is consistent with the ch. NR 428 rule package adopted by the Board in 2000. 

2. Summary of the rule 

The proposed rule establishes NOx RACT emission requirements for major sources in the moderate 

ozone nonattainment areas. The emission requirements apply to individual stationary combustion 

units at major sources and must be met by May 1, 2009. 

The emission requirements consist of NOx emission limitations which apply on a year-round basis. 

The emission limitations are established by source categories with an emission unit size threshold 

based on available control technologies and cost-effectiveness. The rule contains exemptions from 

RACT requirements for certain types of emission units demonstrating low operating levels during the 

ozone season. An additional exemption recognizes that certain smaller emission units are already 

well controlled under existing NR 428 provisions and no further action is needed in meeting the 

4 
RACT emission limit. Attachment A provides the technical assessment that supports the 

Department’s proposed rule. 

a. General Applicability 

The proposed rule affects facilities with the potential to emit 100 tons or more of NOx per year in the 

moderate ozone nonattainment areas, but the emission limits apply to individual emission units, such 

as a boiler or furnace, at the affected facilities. It is possible that an emission unit contributing to a 

major source's potential to emit may not be subject to a RACT requirement. Likewise, an emission 

unit identified by a RACT source category, but at a facility with a potential to emit less than 100 tons 

per year, will not be subject to a RACT requirement. 

b. Categorical Emission Limits 

The proposed rule establishes NOx emission rate limits by source category applicable to emission 

units operating above threshold levels during the ozone season. The proposed source categories, 

operating levels, and emission limitations are presented in Table 1. The emission limits contained in 

the proposed rule are a 30-day rolling average requirement applicable on a year-round basis. A unit 

subject to an emission limitation must demonstrate compliance on an individual basis by May 1, 

2009. 

5 
Table 1. Proposed NOx RACT Categorical Emission Limits1

. 

Source Category Capacity Threshold NOx Emission Limitation 

(30 day rolling average) 

=> 1000 mmBtu/hr 

 Tangential-fired.............................0.10 lbs/mmBtu 

 Wall-fired......................................0.10 lbs/mmBtu 

 Cyclone-fired ...............................0.10 lbs/mmBtu 

 Fluidized bed-fired........................0.10 lbs/mmBtu 

 Arch-fired..................................... 0.18 lbs/mmBtu 

=> 500 – 999 mmBtu/hr

 Tangential-fired.............................0.15 lbs/mmBtu 

 Wall-fired (low heat release).........0.15 lbs/mmBtu 

 Wall-fired (high heat release).........0.17 lbs/mmBtu 

 Cyclone-fired ................................0.15 lbs/mmBtu 

 Fluidized bed-fired.........................0.10 lbs/mmBtu 

 Arch-fired...................................... 0.18 lbs/mmBtu 

=> 250 – 495 mmBtu/hr 

 Tangential-fired.............................0.15 lbs/mmBtu 

 Wall-fired (low heat release).........0.15 lbs/mmBtu 

 Wall-fired (high heat release).........0.17 lbs/mmBtu 

 Cyclone-fired ................................0.15 lbs/mmBtu 

 Fluidized bed-fired.........................0.10 lbs/mmBtu 

 Arch-fired...................................... 0.18 lbs/mmBtu 

 Stoker-fired....................................0.20 lbs/mmBtu 

Solid Fuel-Fired Boiler 

50 - 249 mmBtu/hr 

 Tangential-fired.............................0.15 lbs/mmBtu 

 Wall-fired (low heat release).........0.15 lbs/mmBtu 

 Wall-fired (high heat release).........0.17 lbs/mmBtu 

 Cyclone-fired ................................0.15 lbs/mmBtu 

 Fluidized bed-fired.........................0.10 lbs/mmBtu 

 Arch-fired...................................... 0.18 lbs/mmBtu 

 Stoker-fired....................................0.25 lbs/mmBtu 

Gaseous or Liquid Fuel-Fired 

Boiler 

=> 100 mmBtu/hr...... 

=> 100 mmBtu/hr...... 

=> 65 mmBtu/hr........ 

Gaseous fuel.....................................0.08 lbs/mmBtu 

 Distillate oil....................................0.10 lbs/mmBtu 

 Residual or waste oil......................0.15 lbs/mmBtu 

Lime Kiln (manufacturing) => 50 mmBtu/hr 

 Gaseous fuel....................................0.10 lbs/mmBtu 

 Distillate oil...................................0.12 lbs/mmBtu 

 Residual oil.....................................0.15 lbs/mmBtu 

 Coal................................................0.60 lbs/mmBtu 

 Coke...............................................0.70 lbs/mmBtu 

Glass Furnace => 50 mmBtu/hr 2.0 lbs/ton of glass 

Metal Reheat, Galvanizing, and 

Annealing Furnace => 75 mmBtu/hr 0.08 lbs/mmBtu 

Asphalt Plants => 65 mmBtu/hr 

Gaseous fuel.....................................0.15 lbs/mmBtu 

 Distillate oil....................................0.20 lbs/mmBtu 

 Residual or waste oil.......................0.27 lbs/mmBtu 

Process Heating 

=> 100 mmBtu/hr...... 

=> 100 mmBtu/hr........ 

=> 65 mmBtu/hr........ 

Gaseous fuel.....................................0.10 lbs/mmBtu 

 Distillate oil.....................................0.12 lbs/mmBtu 

 Residual or waste oil.......................0.18 lbs/mmBtu 

Simple Cycle Combustion 

Turbine => 50 MW 

 Natural gas................................25 ppmdv @ 15% O2

 Distillate oil..............................65 ppmdv @ 15% O2

 Biologically derived fuel.......... 35 ppmdv @ 15% O2

6 
25 – 49 MW 

 Natural gas................................42 ppmdv @ 15% O2

 Distillate oil..............................96 ppmdv @ 15% O2

 Biologically derived fuel.......... 35 ppmdv @ 15% O2

Combined Cycle Turbine 

=> 25 MW........ 

10 – 24 MW......... 

=> 25 MW.......... 

Natural gas.................................9 ppmdv @ 15% O2

Distillate oil..............................42 ppmdv @ 15% O2 

Natural gas................................42 ppmdv @ 15% O2

Distillate oil...............................42 ppmdv @ 15% O2 

Biologically derived fuel.......... 35 ppmdv @ 15% O2

Reciprocating Engine => 500 horsepower 

 Rich-burn units..................................3.0 gr/bhp-hr 

 Lean-burn units..................................3.0 gr/bhp-hr 

 Distillate-fuel units............................3.0 gr/bhp-hr 

 Natural Gas / Dual fuel......................3.0 gr/bhp-hr 

 1) The compliance deadline for most sources is May 1, 2009. However, electric generating units have interim 

emission limits and extended compliance time frames. See Table 2.

1. Implemented on an annual basis 

The proposed rule implements the RACT requirements on an annual basis. This is the default 

approach for RACT as reflected in the current EPA 8-hour ozone Phase II Implementation 

Rule (70 FR 71611). Controls implemented for ozone purposes are cost-effective to operate 

year-round and yield continual air quality benefits related to fine-particles, haze, acid rain, 

and eutrophication of lakes. 

2. 30-day rolling average emission limit 

The 30-day rolling averaging time is a short term, rate-based approach to ensure full benefit 

of the installed control equipment. In this way, emissions are continuously controlled in the 

event conditions are conducive to forming ozone. This approach allows averaging of the 

typical variations in controlled emission levels from a single unit. 

3. Emission unit exceptions 

Emission units which operate at very low levels during the ozone season are exempt from 

RACT requirements. The rule also exempts units with low emission rates from installing 

additional controls to meet the RACT emission limits. 

4. Compliance monitoring and demonstration 

The proposed rule requires most sources subject to emission limitations to demonstrate 

compliance using continuous emissions monitoring. For electric utility (EGU) sources this 

monitoring is based on 40 CFR part 75 methods and for industrial source monitoring is based 

on 40 CFR part 60 methods. For a few source categories with low variability in operations or 

emission rates, compliance is demonstrated by periodic stack testing. The proposed emission 

monitoring requirements are consistent with existing state and EPA programs. The rule will 

also allow a source to request approval of an alternative monitoring method. 

5. Electric utility coal-fired boiler phased compliance schedule. 

For electric utility coal-fired boilers the rule sets a phased compliance schedule with interim 

emission limits for May 1, 2009 and final RACT emission limits by May 1, 2013. The 

purpose of the phased compliance schedule is to allow the electric utilities the necessary time 

to install post combustion controls while maintaining a reliable electric supply. Some control 

technologies, like selective catalytic reduction equipment, can take up to two years to install 

for an individual project. This is compounded by the fact that utilities are subject to limited 

installation windows which further restrict the installation schedule. On this basis, multiple 

installations cannot be fully accomplished on all electric utility boilers within the moderate 

7 
nonattainment area by 2009. The phased approach is also consistent with operating 

generating units on a system-wide basis and utilization of a multi-facility averaging program. 

The schedule of phased limitations is provided in Table 2. The interim emission limits for 

2009 is based on implementation of full combustion modifications and a limited number of 

selective non-catalytic reduction installations. In this manner, the proposed rule sets forth a 

RACT level of NOx control across electric utility boilers achieved on a schedule the 

Department has found to be as expeditious as practicable. Attachment B summarizes the 

expected emissions from electric utility coal fired boilers. 

Table 2. Compliance Schedule for Electric Utility Coal-Fired Boilers 

Emission Limits (lbs/mmbtu) Compliance 

Date Coal-fired Boilers > 1000 

mmbtu/hr 

Coal-fired Boilers >500 and 

<1000 mmbtu/hr 

May 1, 2009 

wall fired = 0.15 

tangential fired = 0.15 

cyclone = 0.15 

fluidized bed = 0.15 

arch fired = 0.18 

wall fired = 0.20 

tangential fired = 0.15 

cyclone = 0.20 

fluidized bed = 0.15 

arch fired = 0.18 

May 1, 2013 

wall fired = 0.10 

tangential fired = 0.10 

cyclone = 0.10 

fluidized bed = 0.10 

arch fired = 0.18 

wall fired = 0.17 

tangential fired = 0.15 

cyclone = 0.15 

fluidized bed =0.10 

arch fired = 0.18 

6. Alternative compliance methods. 

The proposed RACT rule provides several compliance options. 

1) Emissions from one or more units subject to a RACT emission limitation may be 

averaged with other similar units at an industrial or small utility facility. Under this 

approach all similar units at the facility must be included in the averaging program. 

This is to eliminate a potential shift in generation/ production to unit not subject to 

the RACT requirements. 

Emissions averaging applies the current applicable emission limit of each unit on a 

heat input weighted basis to determine an average facility or system emission limit. 

The EPA requires that averaging programs like the system averaging in the proposed 

rule have an additional emission reduction applied to the facility or system emission 

limit as an environmental benefit in lieu of the provided flexibility. (See Improving 

Air Quality with Economic Incentive Programs, EPA-452/R-01-001, Jan. 2001.) 

Under facility averaging the proposed environmental benefit is the implementation of 

an annual and ozone season mass cap. 

2) Emissions units may participate in an emission averaging program across multiple 

units and facilities. Each unit can only participate in one type of averaging program 

on an annual basis (facility or system-wide). The proposed environmental benefit is 

the EPA default of 10% reduction in the emission rate on an annual and an ozone 

season basis. 

3) An individual source may request an alternative emission limitation or compliance 

schedule, with a determination made on a case-by-case basis by the Department. An 

8 
alternative emission limit may be the result of an engineering assessment that 

demonstrates RACT controls are not economically or technically feasible for that 

unit. Any determination of an alternative limit or schedule must also account for a 

unit’s ability to participate in either a facility or system-wide emissions averaging 

program. 

7. Utility reliability waiver 

The proposed rule contains a provision that allows an electric or steam utility or natural gas 

transmission facilities to request a waiver from an applicable emission limit for a period of 

time due to reliability issues. This provision acknowledges that these facilities serve noninterruptible customers and uncontrollable events may occur which result in an increase in 

emissions. Facilities generating steam for process and manufacturing purposes are not 

eligible for the waiver. 

3. Hearing Summary and Comment Summary 

A public hearing was held on March 15 in Milwaukee. Twelve people attended the hearing. WE 

Energies, Alliant Energy, and Wisconsin Manufacturers and Commerce, testified opposing major 

portions of the rule. Sierra Club/Clean Wisconsin testified in support of the rule, but suggested 

changes to strengthen the emission limits in the rule. Additionally, written public comments were 

accepted through March 19th, 2007. The Department received written comments from: 

Alliant Energy 

ANR Pipeline 

David Bender 

Engine Manufacturers Association 

James McCarthy 

Sierra Club/Clean Wisconsin 

Solar Turbines 

US EPA 

Waste Management 

WE Energies 

Wisconsin Industrial Energy Group 

Wisconsin Legislative Council Rules Clearinghouse 

Wisconsin Paper Council 

Wisconsin Manufacturers and Commerce 

A list of comments and Department responses is found in Attachment C. 

4. Impact to Existing Policy 

This proposal is consistent with existing state statutory policy for ozone rules under s. 285.11(6), Wis. 

Stats., to revise and implement state implementation plans for the purpose of prevention, abatement 

and control of air pollution in Wisconsin. 

5. Has the Board dealt with these issues before? 

The Board authorized public hearings on this rule at its January, 2007 meeting. Most recently prior to 

that, the NRB adopted ch. NR 428 in 2000 for regulation of NOx emissions from stationary sources in 

the state. Those regulations were formulated to meet rate-of-progress and attainment requirements 

for the 1-Hour Ozone Attainment Demonstration in Southeastern Wisconsin. That rule established 

performance standards for existing electric utility and larger industrial sources in the area now 

9 
designated as moderate under the 8-Hour ozone standard. The sources subject to ch. NR 428 

requirements are also subject to the proposed RACT rules. In some cases, meeting the NR 428 limits 

exempts units based on lowering their potential to emit below 100 tons per year. 

6. What changes have been made to AM-17-05? 

a. Combustion Tuning 

The Department proposed that sources should participate in combustion tuning, since it 

provides energy and environmental benefits. However, the provisions of the proposed rule 

dealing with combustion tuning were controversial because they were viewed as overly 

prescriptive and requiring unnecessary recordkeeping. Considering the comments from the 

industrial sector in Wisconsin, the Department proposes to drop combustion tuning from the 

NOx RACT rule. This provision wouldn’t have accounted for very large emission reductions 

because it would have applied to smaller sources and some of the reductions will be achieved 

through voluntary combustion tuning. 

The Department may consider combustion tuning in future air quality related initiatives such 

as PM2.5 or ozone attainment demonstrations, reasonable progress for haze or climate change 

proposals. In these new initiatives, DNR will work with industrial representatives to address 

their concerns and streamline testing and reporting requirements. 

b. Exemptions.

General Exemptions – For purposes of clarity and streamlining of requirements, additional 

exemptions were included to define emergency, auxiliary, and backup units which would 

normally qualify under the low operating unit exception. Exceptions were added based on 

the periodic or intermittent nature of operation for peaking or reliability units. 

Low operating unit – The Department proposed the low operating unit exception based on a 

5% ozone season capacity factor for reciprocating engines and combustion turbines and a 

10% capacity factor for the remaining source categories. Based on comments concerning 

cost-effectiveness, the Department revised the capacity factor used in calculating the 

utilization threshold to 20% for all source categories. 

Other regulated unit – The rule exempts emission units that have been well controlled under 

existing NR 428 requirements and for which cost rapidly increases in meeting additional 

reductions under the RACT requirements. An exemption threshold based on potential 

emissions of 50 tons per year was proposed in the public hearing draft of rule. Based on 

comments the Department increased the threshold to 75 tons per year in the revised rule. 

c. Source Categories and Emission limits 

Solid fuel wall-fired boilers – The proposed rule provided a distinction between low and high 

heat release wall fired boilers based on achievable emission limitations. The basis for the 

distinction is being modified based on comments to reflect standard methods and terminology 

in the industry without affecting the applicability of the requirements. 

Boilers – The exemption threshold for residual fuel-fired boilers was originally proposed at 

60 mmBtu/hr and the Department revised the limit to 65 mmBtu/hr. 

10 
Process heating – Comments were received concerning the applicability threshold of 50 

mmBtu/hr for all process heaters. The thresholds have been revised based on fuel type and 

cost-effectiveness. Similar to other categories, natural gas, distillate oil, and residual fuel 

emit NOx at increasingly higher emission rates in that respective order. Therefore it is 

appropriate to distinguish lower unit size thresholds for the higher emitting fuels. The revised 

thresholds are natural gas = 100 mmBtu/hr, distillate fuel = 100 mmBtu/hr, and residual fuel 

= 65 mmBtu/hr. To address comments related to the distinction of process heaters and other 

gaseous and liquid fuel fired units such as dryers and ovens, the Department clarified the 

definition of process heaters 

Combustion turbines – After reviewing comments from industry and a turbine manufacturer, 

the Department adjusted source category thresholds and emission limits for combustion 

turbines. The Department created an exemption size threshold for simple cycle turbines at 25 

MW. The Department also adjusted emission limits for all combustion turbine categories to 

reflect available low NOx combustion techniques without the use of post-combustion control. 

Reciprocating engines – Based on comments concerning cost and technical issues, the 

Department raised exemption threshold for affected engines from 250 to 500 hp. 

Additionally, the Department revised the emission limits for natural gas fired engines to 3.0 

gr/bhp-hr. 

d. Monitoring requirements

Based on comments, the Department revised several monitoring requirements to streamline 

requirements without compromising the compliance demonstration. 

The public hearing draft rule allowed an alternative EPA monitoring method with written 

approval of the department. The revised rule will allow this alternative without approval for 

specific source categories. 

Other miscellaneous modifications have been made based on comments to address 

consistency in testing methods standard to certain source categories and clarification. 

e. Green Tier 

U.S. EPA commented that including the green tier provision in the draft rule would require 

that the green tier program be submitted to EPA for approval as part of a state 

implementation plan (SIP) revision. While the Department strongly supports the goals of the 

Green Tier program, we believe that the Green Tier program being a federally enforceable 

part of the SIP would delay promulgation of this rule and might be counter to the Green Tier 

program goals. Therefore, we’ve dropped the proposed Green Tier language in this rule that 

was only a general reference to the program anyway. The Department will continue to search 

for ways to take advantage of the Green Tier program to achieve superior environmental 

goals. 

f. Steam and Electric Reliability Waiver 

The reliability waiver establishes a process to address situations where facilities supplying 

electricity or steam for critical needs must continue to operate and exceed limitations due to 

uncontrollable or foreseeable events. The rule is revised to allow natural gas transmission 

facilities subject to reliability constraints by the Federal Regulatory and Energy Commission 

to access this provision. 

11 
g. Minor changes to address comments from Legislative Council Rules Clearinghouse and 

US EPA 

The Department made the necessary changes for clarity and to meet rule writing 

requirements. 

7. Who will be affected by the proposed rule? How will they be affected? 

The rule provides a significant public health benefit for the citizens of the state. Using an EPA health 

benefits model, COBRA, the Department estimated, when fully implemented, the NOx RACT rule 

would provide about $80,000,000/year in public health benefits compared to compliance costs of 

about $16,000,000 annually. 

The proposed rule affects emission units at major source facilities which have applicable emission 

limits specified in the rule. In the moderate nonattainment areas the affected emission units include 

electric utility generating units, industrial boilers, combustion turbines, glass and steel furnaces, 

asphalt plants, process heaters, and reciprocating engines. Refer to Attachment A for a summary of 

anticipated general control levels and range of cost-effectiveness represented by rule requirements. 

The affected electric utility generating units consist primarily of 13 large coal fired boilers. The 

proposed rule is likely to result in significant post-combustion controls achieving 50% to 90% 

reduction from uncontrolled emissions for most of these units, at a cost effectiveness ranging from 

$1,000 to $2,200 per ton of controlled NOx emissions. The rule also affects 3 coal-fired boilers which 

are smaller than typical electric generating units, but which are used for steam utility services. These 

boilers will require less intensive post-combustion controls, approximately a 50% reduction, at a costeffectiveness of $2,500 per ton. All of these coal-fired boilers are eligible to participate in multifacility trading allowing electric utilities maximum flexibility in meeting RACT requirements. 

The remaining source categories are primarily gaseous and oil-fired combustion processes. The 

prevalent method of control applied to these types of emission units is combustion modification 

consisting of over-fire air and low NOx burners. The Department expects combustion modifications 

to achieve a 30% to 60% reduction at individual sources burning gas and oil. The one exception is 

very large reciprocating engines, where it appears cost-effective controls may achieve an 80% - 90% 

reduction in emissions. The analysis of the rule identifies that up to 25 gaseous or oil fired emission 

units may have to take additional action to meet proposed RACT emission limits of the rule. This 

results in an estimated NOx reduction of 46% from a base emission level at a cost effectiveness 

ranging from $300 to $2,500 per ton. 

The RACT rule may also affect additional emission units in the future in two ways. First, emission 

units which currently operate at very low levels are currently exempt from the emission limitations. 

Once these units exceed a threshold utilization level they are subject to meeting the requirements. 

Secondly, the rule will affect any source which becomes a major source (PTE > 100 TPY) due to 

adding additional sources or modifying existing sources for additional capacity. At that time, a 

source would have to review their sources for applicability to the RACT requirements. This aspect of 

the rule serves to maintain emissions at RACT controlled levels equitably across emission sources in 

the area. 

8. What are other states doing? 

12 
States near Wisconsin with 8-hour ozone nonattainment areas are Illinois, Indiana, Michigan and 

Ohio. Illinois, Indiana and Ohio also have moderate non-attainment areas. All of the Michigan 

nonattainment areas are of a lower non-attainment designation of either "basic" or "marginal". 

 

Illinois: The state of Illinois has proposed a statewide RACT rule for industrial boilers and other 

sources with a potential to emit of 100 tons per year or greater. The Illinois rule affects smaller 

sources and implements equivalent or more stringent requirements than those in the Wisconsin rule. 

The Illinois proposed RACT emission limits are based on a cost-effectiveness ranging up to $2,500 

per ton of NOx removed. The rule proposes combustion tuning for boilers between 50 and 100 

mmbtu/hr and emission limits for units approximately equivalent to 50 mmbtu/hr across the source 

categories. Illinois EPA negotiated very stringent SO2 and NOx limitations with the utilities in 

Illinois that generate about 90% of the electric power in the state. The resulting emission limits for 

the Chicago area are more stringent than what the Department has proposed for NOx RACT in the 

Milwaukee area. 

Indiana: Indiana is not proceeding with NOx RACT rule development at this time. 

Michigan: The state of Michigan has made no determination regarding the need for developing 

RACT rules. A Michigan RACT rule is required only if attainment in the basic areas cannot be 

demonstrated by the state's SIP submittal deadline of June 2007. 

 

Ohio: Ohio is developing NOx RACT rules for industrial sources in the Cleveland nonattainment 

area. The rule affects smaller sources and implements equivalent or more stringent requirements than 

the Wisconsin rule for industrial sources. The proposed Ohio rule considers controls up to $5,000 per 

ton of controlled NOx. The proposal requires combustion tuning for boilers between 20 and 50 

mmBtu/hr. Emission units of approximately 50 mmbtu/hr and larger across source categories must 

meet emission limits. 

9. Information on environmental analysis 

An environmental analysis of the impact of the proposed rule revisions is not needed as these changes 

are considered to be a Type III action under s. NR 150.03(3), Wis. Adm. Code. A Type III action is 

one that normally does not have the potential to cause significant environmental effects, normally 

does not significantly affect energy usage and normally does not involve unresolved conflicts in the 

use of available resources.

10. Regulatory Flexibility Analysis 

 

There are no emission or performance requirements or compliance and reporting requirements 

proposed for small businesses and as such are not anticipated to directly affect small businesses. The 

proposed RACT rules are applicable to major industrial entities and electric utility facilities. 

Small business may experience electricity rate impacts related to RACT requirements for the electric 

generation sector. The cost of controls is estimated to be less than 1-3% of current electricity rates. 

13 
Attachment A. 

DATE: April 4, 2007 

TO: Larry Bruss 

FROM: Tom Karman 

SUBJECT: Technical Basis for RACT Determinations 

This document provides the technical basis for proposing Reasonably Available Control Technology 

(RACT) requirements for NOX emission units in Southeastern Wisconsin. The previous version of 

this document has been revised to incorporate new information that’s been submitted or become 

available during the public comment process for the proposed RACT rule. 

For several reasons it is necessary to perform an analysis of RACT requirements. In the mid-1990's, 

NOx RACT programs were implemented by other states to meet requirements under 1-hour ozone 

non-attainment designations. However, because NOx control technologies and costs have changed, 

we found it necessary to perform an up-to-date evaluation of RACT. And, although other state 

RACT rules are an important reference the associated supporting evaluations may not have addressed 

issues specific to emission units found in Wisconsin. Other states currently developing RACT rules 

are following a similar process of developing up-dated RACT requirements. The basis for RACT 

requirements is also a necessary component of submitting the proposed rule to EPA for approval as a 

SIP component. 

Definition of RACT 

The EPA defines RACT as "the lowest emission limitation that a particular source is capable of 

meeting by the application of control technology that is reasonably available considering 

technological and economic feasibility." (44 FR 53762, September 17, 1979.) 

Evaluating RACT 

According to the EPA definition, the determination of RACT is based on evaluating two primary 

criteria: 

• A review of available control technologies and applicable emission reductions for each type 

of emissions unit. 

• The cost-effectiveness, typically expressed in dollars per ton of controlled NOx, of applying 

the control technologies. 

We evaluated these two criteria following general approaches and methods established in EPA’s 1994 

series of Alternative Control Technology (ACT) documents for NOx source categories. The ACT 

documents were the primary reference for states in developing the 1990 vintage RACT requirements. 

However, we updated the information on control technology and costs based on more recent EPA 

information, equipment vendor information, actual installations, and information received during the 

public comment period. In some cases, we used applicable cost-effectiveness directly from reference 

resources utilizing the same or similar methodologies. All cost information is presented in 2000 or 

later dollars. We adjusted costs from historic documents based on the consumer price index. 

14 
The first step in the RACT evaluation process is to identify control technologies applicable to general 

emission source categories. Only those control technologies which are found to be readily available 

and have already been utilized in existing applications were used in the evaluation. The general types 

of control technology found applicable to controlling NOx emissions are shown in table A1. 

Table A1. General NOx Controls Applied in the RACT Evaluation. 

Category Technology Control Efficiency Compliance Margin 

Combustion Tuning 5 – 35% NA 

Combustion air 

staging: OFA, FGR 

25% - 50 

LNB 50 – 70% 

Gaseous & oil fired – 

10% 

Solid fuel fired – 15% 

CT Steam/water 

Injection 

60% - 90% 10% 

Combustion 

Modifications 

Engine combustion 

modifications 

30 – 90% 10% 

SNCR 35% - 60 20% Post Combustion SCR 75% - 90% 25% 

To determine potential RACT controlled emission rates we applied the control efficiencies of 

applicable technologies to baseline emission rates as was done in the 1994 vintage RACT 

determinations. These baseline emission rates for most source categories are from the ACT 

documents and represent a typical uncontrolled source for that source category. However, we used 

historic actual emission rates in the case of EGU boilers and combustion turbines as there are a 

limited number of individual units and their emissions are well quantified. The definitions of 

acronyms used for the control technologies can be found at the end of the memo. 

Also, for emission units which already have controls in place due to current state NOx requirements, 

we applied additional controls to the actual or the applicable emission limit (e.g. electric and 

industrial boilers, reciprocating engines,). This is a secondary test for the feasibility and cost of 

additional controls in meeting the proposed limits. 

Unless specifically stated for a technology, we assumed the reported control efficiencies are based on 

long-term averages of control technology performance. Therefore, in accounting for potential 

operational variability in estimating the emission limit for compliance we applied a compliance 

margin factor, as shown in Table A1, in proposing the RACT emission limits. Based on published 

evaluations, the control variability for post combustion control can be significant and therefore the 

compliance margin is set higher than for combustion modifications. 

To determine cost-effectiveness, we estimated the annual cost for each control technology and 

divided it by the amount of controlled NOx emissions. The annual control cost consists of the total 

capital and installation costs annualized over the life of the equipment plus annual operating costs of 

the equipment. The cost-effectiveness is then calculated as the annualized cost divided by the 

calculated reduction in each case. We tested the cost-effectiveness over a range of capacity factors 

and emission unit sizes. This is necessary as technology capital cost is usually relatively higher for a 

small unit than for a larger unit (economies of scale) and operational cost will vary over utilization of 

each individual unit. For the large electric utility boilers costing is based on actual operation of the 

existing units. The costing analysis of utility coal-fired boilers is presented in more detail in a 

separate section below. 

15 
The calculation of cost-effectives does not include the cost of compliance monitoring. The EPA 

references in discussing RACT cost-effectiveness (see discussion below) do not include the cost of 

compliance monitoring. This is a separate consideration in structuring rule requirements. 

The determination of RACT is an iterative process where the evaluations of technology and costeffectiveness further define sub-categories of emission units and applicable RACT requirements. For 

particular source categories the cost-effectiveness will define unit sizes and operational levels or 

capacity factors differentiating RACT requirements. We proposed the emission limits to reflect these 

considerations. 

 

Cost-effectiveness Basis for RACT 

For the evaluation, we assumed an upper limit of approximately $2,500 per ton of NOx controlled 

from uncontrolled emission rates in proposing NOx RACT emission limits. Other factors considered 

is where cost for additional control increase rapidly. This rate of increasing cost is evaluated versus 

the size and operational levels of the emission units and versus in evaluating incremental reductions 

for units subject to existing emission limits. 

The basis for assuming $2,500 per ton considers several factors as outlined below. 

In a 1994 memo, EPA indicated that RACT controls should, at a minimum, overlap the range of $160 

to $1,300 per ton. The memo also states, in discussing controls for utility boilers, that controls 

meeting EPA's presumptive NOx RACT levels show a range in cost effectiveness of about $160 to 

$5,100 per ton of NOx (based on 1991$). These cost ranges are based on controls from uncontrolled 

emission rates. In the recent 8-hour ozone Phase II Implementation rule, EPA referenced the $160 to 

$1,300 range as still applicable in evaluating RACT. However there are several considerations that 

indicate other levels of cost-effectiveness may be more appropriate in the current determination of 

RACT. 

• The $1,300 per ton cost-effectiveness from the 1994 is approximately $2,000 per ton in 2005 

dollars using the consumer price index. The normal EPA methodology is to normalize 

costing to current dollars. 

• The cost range referenced in EPA's 1994 memo was based on an analysis of controls 

available at that time. Since then, availability, control efficiencies, and cost of control 

equipment have changed. EPA’s original evaluation referenced in the memo a cost range of 

$320 to $5,200 per ton for SCR installations at 80 to 90% reduction which is very similar to 

the cost range stated for other technologies. However, EPA did not feel that the knowledge 

based for SCR control was sufficient to assume it as technically and reasonably available for 

RACT at that time. The installation of SCR is now common practice as referenced in current 

EPA documents. 

• EPA in their determination of NOx controls for the NOx SIP call determined $2,000 per ton 

to be "highly cost-effective". This cost was based on an average of controls predicted by a 

modeled trading program. The actual costs for the SIP program for individual units would be 

higher and lower in than the average. Therefore assuming $2,500 per ton of NOx appears to 

be a reasonable ceiling in estimating applicable RACT controls. 

• Other existing NOx RACT programs are based on higher cost-effectiveness ceilings. Staff 

from the Northeast Ozone Transport Commission region indicates the average cost16 
17 

effectiveness for already established NOx RACT programs ranged upwards to $3,500 per ton. 

A recent determination of RACT for the Charleston, South Carolina identified RACT 

reductions up to $3,500 per ton. And in 1990, the California Air Resources Board 

determined that a range of $2,000 to $10,000 (1990$) for cost-effectiveness as the average 

rate for installation of NOx controls. 

• Current development of RACT rules are based on levels higher than the minimum range 

presented in EPA's 1994 memo. For example, the state of Illinois is using a costeffectiveness of $2,500 per ton as a guideline in proposing RACT emission limits for 

industrial source categories. According to staff, Ohio is proposing RACT limits based on 

costs up to $5,000 per ton. 

Recommended RACT Control Levels 

Based on the methodology outlined above, we propose emission limits for emission units over 

specific size thresholds by fuel types to satisfy RACT requirements at major sources. And the 

emission limits are found cost-effective when units in a source category operate at a utilization level 

over 20% of the source categories capacity threshold operating at full load. The utilization threshold 

relates when controls are warranted versus actual emissions. 

In addition, we propose that an emission unit currently meeting one of the current state NOx emission 

limits (NR 428.04 and 0.05, excluding combustion optimization) be exempt from additional control in 

meeting the proposed RACT limits if the unit's emission potential is below 75 tons per year. This 

emission level identifies where additional controls would be cost-effective in meeting RACT limits 

based in context of parameters discussed for this evaluation. The units above the 75 ton threshold in 

Southeast Wisconsin include coal-fired utility boilers, large engines over 1000 hp and potentially 

residual fuel fired emission units. 

The emission limits are listed in detail for each source category in Table A2 along with an assumed 

control technology. This does not represent the full spectrum of technologies that are available in 

many cases to achieve the equivalent control. The results from the specific application of evaluated 

control technologies and assumptions for existing coal-fired boilers in Wisconsin are presented in a 

separate section below. 

I found combustion tuning to be an integral first step in reducing NOx emission for all for emission 

units equal to or greater than 50 mmBtu/hr in fuel consumption capability. Across the source 

categories the costs of combustion tuning for these units is largely offset by fuel savings. Below this 

level, combustion tuning may also be beneficial, but there was less information for all source 

categories (7). However, tuning is usually an integral portion of implementing combustion controls 

and there is not sufficient information available to determine the extent of tuning already occurring at 

Wisconsin sources. Also, the implementation approaches required across the different types of 

emission sources which capture the benefit of tuning requires further investigation. Therefore, since 

combustion tuning may already be occurring on a wide-spread basis and that specific requirements 

need further investigation there may not be sufficient basis to include in the RACT requirements at 

this time. 
Table A2. Summary of RACT Source Categories and RACT Controls 

Source Category 

Base 

Emission 

Rate (lbs/ 

mmBtu) 

Control Technology 

and Efficiency 

Control 

Ref. 

RACT 

Emission 

Limit (lbs/ 

mmBtu/hr) 

CostEffectiveness 

($/ton) 

Cost 

Ref. 

> 1000 mmBtu/hr 0.46 SCR – 86% 1, 2, 3 0.10 1,300 – 1,600 2, 5 500 - 1000 mmBtu/hr – HHR 0.47 LNB – 40% +OFA- 25% +SNCR - 35% 2, 4 0.17 1,300 – 1,400 2 500 - 1000 mmBtu/hr – LHH 0.46 LNB – 40% +OFA- 25% +SNCR - 40% 2, 4 0.15 1,300 – 1,400 2 < 500 mmBtu - HHR 0.47 LNB – 40% +OFA- 25% +SNCR - 35% 2, 4 0.17 1,800 – 2,100 6 

Wall-fired boilers 

< 500 mmBtu - LHR 0.46 LNB – 40% +OFA- 25% +SNCR - 40% 2, 4 0.15 1,800 – 2,100 6 

Tangential- > 1000 mmBtu/hr 0.46 SCR – 86% 1, 2, 3 0.10 1,200 – 1,900 2 fired boilers 

< 1000 mmBtu/hr 0.46 LNB – 40% +OFA- 25% +SNCR - 40% 2, 4 0.15 1,500 – 2,100 2,6 

> 1000 mmBtu/hr 0.79 OFA – 50% +SCR – 89% 1, 2, 3 0.10 700 -1,200 2 

Cyclone- fired boilers 

< 1000 mmBtu/hr 0.86 OFA – 50% +SCR – 75% 1, 2, 3 0.15 1,700 – 2,100 2, 5 

Arch-fired boilers 

all capacity sizes 0.24 Tertiary Air – 20% 3 0.18 1,200 – 1,500 2 

Fluidized bed boilers 

all capacity sizes 0.15 SNCR – 50 to 60% 4,6,7 0.10 6 

> 250 mmBtu/hr 0.50 OFA – 25% + SNCR – 

50 to 60% 

Stoker fired 4,6,7 0.20 <2,500 6 boilers 

< 250 mmBtu/hr 0.50 SNCR – 50 to 60% 4,6,7 0.25 <2,500 6 

18 
Table A2. Summary of RACT Source Categories and RACT Controls (continued) 

Source Category 

Base 

Emission 

Rate 

(lbs/mmBtu) 

Control Technology 

and Efficiency 

Control 

Ref. 

RACT 

Emission 

Limit (lbs/ 

mmBtu/hr) 

CostEffectiveness 

($/ton) 

Cost 

Ref. 

Gas fired boilers 

> 100 – 150 

mmBtu/hr 0.22 LNB/OFA/GR – 60% 6, 14 0.08 700 – 2,200 6 

Distillate oil fired boilers 

> 100 mmBtu/hr 0.21 LNB/OFA/GR – 50% 6, 14 0.10 700 - 2,300 6 

Residual oil fired boilers 

> 65 mmBtu/hr 0.38 LNB/OFA/GR – 50% 6, 14 0.15 700 – 2,400 

Gas fired process heater 

> 100 mmBtu/hr 0.26 LNB – 60% 7, 14 0.10 <2,300 6 

Distillate oil process heater 

> 75 mmBtu/hr 0.32 LNB/GR – 60 - 70% 7, 14 0.12 <2,500 6 

Residual oil process heater 

> 50 mmBtu/hr 0.54 LNB/GR 60 – 80% 7, 14 0.18 < 1,500 6 

Other process heating devices 

14 

Metal Furnaces > 100 mmBtu/hr 0.22 LNB/OFA/GR – 60% 6 0.08 700 – 2,200 6 

19 
Table A2. Summary of RACT Source Categories and RACT Controls (continued) 

Source Category 

Base 

Emission 

Rate (gr/bhphr) 

Control 

Technology and 

Efficiency 

Control 

Ref. 

RACT 

Emission 

Limit (gr/bhphr) 

CostEffectiveness 

($/ton) 

Cost 

Ref. 

Rich-burn 16.4 NSCR – 80 – 90% 9, 14 3.0 < 2,500 9 Lean-burn 18.6 LEC – 80 - 90% 9, 14 3.0 < 2,500 9 Distillate compression 

13 SCR – 80 – 90% 9, 14 3.0 < 2,500 9, 7 

Dual fuel compression 

10.7 LEC – 80 - 90% 9, 14 3.0 < 2,500 9 

Reciprocating Engines > 500 hp 

Biogas fired 1.8 NA 14 3.0 NA 

Source Category 

Base Emission 

Rate (ppm @ 

15% O2) 

Control Technology 

and Efficiency 

Control 

Ref. 

RACT Emission 

Limit (ppm @ 

15% O2) 

CostEffectiveness 

($/ton) 

Cost 

Ref. 

Distillate Oil 200 Steam/ Water Inj. – 60 - 70% 7, 14 65 < 2,500 7 

Simple CTs > 50 MW 

Natural Gas 99 – 430 DLN - 90%+ 7, 14 25 < 1,300 7 

Distillate Oil 200 Steam/Water Inj. – 50 - 60% 7, 14 110 < 2,100 7 Simple CTs 

25 - 50 MW Natural Gas 99 – 430 DLN – 80 - 90% 7, 14 42 < 1,300 7 

Distillate Oil 200 Steam/Water Inj. - 60 - 80% 7, 14 42 < 2,500 7 Combined Cycle CT > 

10 MW Natural Gas 99 – 430 DLN 80- 90% 7, 10 < 25 MW = 42 > 25 MW = 9 < 2,500 7 Biogas fired combustion turbines 

Biogas 25 – 35 NA 10, 14 35 

Table A2. Summary of RACT Source Categories and RACT Controls (continued) 

20 
21 

Source Category 

Base 

Emission 

Rate 

Control Technology 

and Efficiency 

Control 

Ref. 

RACT Emission 

Limit 

CostEffectiveness 

($/ton) 

Cost 

Ref. 

Glass Furnace > 50 mmBtu/hr 

10 

lbs/ton of 

glass 

Oxy-firing 7 2.0 lbs/ ton of glass <2,500 7 

Natural Gas U.D. 10 0.10 700 – 2,200 7 

distillate oil U.D. 10 0.12 lbs/mmBtu < 2,300 7 

residual oil U.D. 

LNB 

10 0.15 lbs/mmBtu < 1,600 7 

coal U.D. 10 0.60 lbs/mmBtu 7 

Lime Kiln > 50 mmBtu/hr 

coke U.D. 

mid-kiln firing 

11 0.70 lbs/mmBtu 

< 1,000 

7 

Natural Gas 0.26 LNB – 50% 10 0.15 lbs/mmBtu <2,300 7 

distillate oil 0.32 LNB – 50% 10 0.20 lbs/mmBtu <2,500 7 

Asphalt Plants > 65 mmBtu/hr residual oil 0.54 LNB – 50% 10 0.27 lbs/mmBtu < 1,500 7 U.D - undetermined 
22 

Evaluation of Coal-fired Boilers 

Large coal-fired boilers represent more than 90% of the stationary source NOx emission in 

Southeastern Wisconsin. These boilers include 13 very large units used for electricity generation and 

3 smaller units used to generate steam for industrial processes or space conditioning. 

In the RACT evaluation for these boilers, we considered the following control technologies: 

• Over-fire Air 

• Low NOx Burners 

• Selective Non-Catalytic Reduction (SNCR) 

• Selective Catalytic Reduction (SCR) 

I evaluated these control technologies singularly and in various combinations. There are also a 

number of factors which affected the application and effectiveness of these technologies to the coal 

boilers including unit size, fuel type and firing configuration. The technologies and control 

assumptions evaluated for each type of boiler is illustrated in Table A5. 

For boilers greater than 500 mmBtu/hr, we used, control costs and control effectiveness from EPA's 

base data used for running the Integrated Planning Model (1). However, this size class of boilers in 

Wisconsin is comprised totally of electric utility boilers which in some case have already 

implemented the same or similar controls to those being evaluated. Therefore, where available, we 

incorporated information for cost submitted to the Public Service Commission in certificates of 

authorization and effective emission rates reported to the department. In cases where there is a 

significant difference, uncontrolled emission rates are included for both the general category and for 

the specific unit based on historic reported rates. 

For boilers less than 500 mmBtu/hr, the application of technology is based primarily on EPA's recent 

compilation of control options for industrial boilers (6). Other sources were utilized as reference in 

applying the control information (4) (7). 

Along with the average cost of control from an uncontrolled basis, we calculated the marginal cost of 

control for each option. This demonstrates the relationship of combining technologies as well as 

testing the incremental cost for emission units with existing controls. The incremental or marginal 

cost of installing additional control did not appear excessive for any option where the average cost of 

total control was less than the $2,500 per ton ceiling. 
Table A5. Summary of the Evaluation of Control Technologies for Wisconsin Specific and Typical Source Categor

Boiler Size 

Class 

(mmBtu/hr)

Firing 

Configuration Facility Unit

 Firing 

Capacity 

(mmBtu/hr) 

Megawatts Base Emission Scenario

Base 

Emission 

Rate (lbs/ 

mmbtu) Technology

Control 

Efficiency

Annual Cost 

($M)

Controlled 

Emission 

Rate (lbs/ 

mmBtu)

C

> 1000 wall-fired Pleasant Prairie 1 580 6,158 AU 0.46 *SCR 85% 14,695,949 0.07 

> 1000 wall-fired Pleasant Prairie 2 580 6,158 AU 0.46 *SCR 85% 12,710,697 0.07 

> 1000 arch-fired South Oak Creek 5 258 2,298 AU 0.24 *Tertiary Air 25% 525,076 0.18 

AU + tertiary air 0.18 SCR 61% 4,689,040 0.07 

> 1000 arch-fired South Oak Creek 6 260 2,283 AU 0.23 Tertiary Air 20% 531,528 0.18 

AU + tertiary air 0.18 SCR 61% 4,772,827 0.07 

> 1000 tangential Edgewater 5 380 4,366 AU 0.22 LNC3 40% 929,753 0.13 

AU + LNC3 0.13 SNCR 35% 3,248,796 0.08 

AU + LNC3 0.13 SCR 46% 7,279,567 0.07 

CU 0.46 SCR 85% 7,279,567 0.07 

> 1000 tangential South Oak Creek 7 / 8 2,608 280 AU 0.39 *LNC2 64% 912,749 0.14 

AU 0.39 SCR 82% 5,381,213 0.07 

AU + LNC2 0.14 SNCR 35% 2,420,571 0.09 

CU 0.46 SCR 85% 5,381,213 0.07 

> 1000 cyclone Edgewater 4 330 3,529 AU 0.79 *OFA + SB 67% 2,533,848 0.26 

AU 0.79 SCR 90% 6,102,790 0.08 

AU + OFA + SB 0.26 SCR 73% 6,102,790 0.07 

500 - 1000 wall-fired (HHR) Valley 1 - 4 64 846 AU 0.47 *LNB 23% 283,705 0.36 

AU 0.47 LNB + upgrade 40% 317,490 0.28 

AU + LNB w/ upgrade 0.28 OFA 26% 113,816 0.21 

AU + LNB w/ upgrade 0.28 SNCR 36% 576,763 0.18 

AU + LNB w/ upgrade 0.28 OFA + SNCR 52% 690,579 0.13 

500 - 1000 cyclone Edgewater 3 60 844 AU 0.79 *OFA / SB 62% 1,044,356 0.30 

AU + OFA 0.30 SNCR 40% 878,133 0.18 AU + OFA 0.30 SCR 75% 2,061,858.81 0.08 

CU 0.86 OFA 50% 1,044,355.59 0.43 

CU + OFA 0.43 SNCR 40% 662,400.00 0.26 

CU + OFA 0.43 SCR 75% 2,061,858.81 0.11 

< 250 mmBtu/hstoker Milwaukee County 1 - 3 140 AU + OFA 0.45 SNCR - Urea 60% see note (4) 0.18 

CU 0.53 SNCR - Urea 60% see note (4) 0.21 

Control Technology Evaluations

Base Emission Scenario – This is the emission basis for applying control technologies. AU = actual uncontrolled emissions of the unit based on historuncontrolled emission rate for emission units in that source category. Technology definitions – OFA = overfire air, LNB = low NOx burners, LNC = low NOx burners with coupled overfire air, SB = smart burn (patented SNCR = selective non-catalytic reduction, SCR = selective catalytic reduction * These are existing controls with demonstrated control efficiency and emission rates. The shaded areas illustrate a technology that was not considered to be cost-effective for the RACT determination. 

23 
24 

1) C.M. is the compliance margin account for variability of controls in meeting an emission limit. The emission rate with CM is the actual demonstracontrols the assumed CM is: 15% for combustion controls, 20% for SNCR, 25% for SCR. 2) This represents the cost-effectiveness of the measure incremental to the base emission scenario controls. 3) This represents the cost-effectiveness of all measures included in the base emission scenario and the additionally applied measure versus the actual emission rate. 4) The cost-effectiveness of the measure is that estimated by EPA for a coal fired boiler operating at 50% capacity converted to 2004$ (6) 
25 

Impact to Wisconsin Sources 

The impact of the proposed RACT requirements in Southeast Wisconsin is summarized by general 

levels of control effort in Table A3 and by specific source category in Table A4. 

The affected sources are identified and impacts calculated based on existing emission limitations in 

2005 applied to historic operating levels or the unit's 2002 air emissions. We calculated the emission 

reductions by applying the proposed RACT emission limit or representative control efficiency. For 

asphalt plants, reciprocating engines, process heater, and metal furnaces, source categories units are 

screened by comparing reported emissions to the potential emissions of an uncontrolled source. 

The RACT emission limitations represent a 30% to 90% reduction (from uncontrolled emission rates) 

with an estimated cost-effectiveness ranging from $500 to $2,500 per ton of reduction. The emission 

limitations represent an estimated reduction of approximately 14,919 tons per year of from the 

estimated base NOx emission levels. 

Table A3. Proposed RACT Control Levels, Cost Effectiveness, and Estimated Wisconsin 

Source Reductions. 

Control Categories 

(1) 

Base 

 NOx

Emissions 

(tons/year) 

(2) 

Reduction from 

uncontrolled emission 

rates (3) 

Estimated 

RACT CostEffectiveness 

($/ton) (4) 

Estimated NOx 

Reduction w/ 

RACT Limits 

(tons/year) 

EGU coal fired 

boilers (5) 

26,864 tpy 

(13 units) 

50 - 90% 

Comb. Mods, SNCR, 

SCR 

1,000 – 2,200 14,277 tpy 

(47% reduction) 

Coal fired boilers < 

500 mmBtu/hr 

277 tpy 

(3 units) 

50% 

Comb. Mods, SNCR 2,000 – 2,500 138 tpy (50% reduction) 

Gas and oil fired 

source categories 

(gas and oil fired)b

1,138 tpy 

(60/25 

units) (5)

30 - 90% 

Comb. Mods. / NSCR 300 – 2,500 504tpy (44% reduction) 

Total 28,279 tpy 

(41 units) 300 - 2500 14,919 (53%) 

1) Solid fuel boilers greater than 500 mmBtu/hr are large electric utility coal-fired boilers. Solid fuel boilers smaller than

500 mmBtu/hr include smaller electric utility and industrial sized solid fuel boilers. “Other Source Categories” include 

gas and oil boilers, combustion turbines, furnaces, asphalt plants, lime kilns, reciprocating engines, and heating 

processes. 

2) EGU coal boiler emissions represent 2005 ozone season emission rates multiplied by an average of the highest 3 years 

of heat input for each unit between 2000 and 2004. Coal boiler < 500 mmBtu/hr and gas and oil fired source category 

emissions are based on 2002 primary combusted fuels, ozone season utilization levels, and emissions adjusted for NR 

428 emission limits which became effective in 2003. 

3) Percent reductions are from an uncontrolled basis. Combustion modifications = overfire air and low NOx burners. 

SCR = Selective catalytic reduction. SNCR = Selective non-catalytic reduction. 

4) The presented cost-effectiveness represents the calculated “average” cost of reduction from an uncontrolled or initial 

emissions level as defined for each source category. 

5) 60 units equals total number in source categories / 26 units equals number of units expected to subject to emission 

limits and require additional control.

Note: The estimate of affected units and emissions is based on emission units estimated to be in a RACT source category. 

The actual number of affected units in the "Others Source Categories" is expected to be lower due to units being at 

facilities with a PTE < 100 TPY or being classified as low operating units. 
26 

Table A4. Estimated Impact of RACT applied to Wisconsin Sources. 

No. of Units

Est. NOx 

Emissions 

(tons) (2)

Emission 

Intensity 

(tons/unit)

No. of units 

adding 

controls 

under RACT 

(3)

Est. NOx 

reduction 

from Base emissions 

(tons)

Percent 

reduction 

from Base emissions

RACT Contr

Technologie

Source Categories subject to Emission Limits:Solid Fuel Boilers > 1000 mmbtu/hr 8 22,685 2,836 8 12,354 54% SCR, CM + SNC

Solid Fuel Boilers > 500 mmbtu/hr 5 4,179 836 5 1,923 46% C.M. + SNCR Solid Fuel Boilers > 250 mmbtu/hr 0 C.M. + SNCRSolid Fuel Boilers < 250 mmbtu/hr 3 277 92 3 138 50% C.M. + SNCR 

Gaseous and Oil Boilers 16 131 8 0 0 0% LNB, LNB + GR 

EGU Combustion Turbines 9 262 29 4 74 28% DLNB, S.I.+ W.I. 

Industrial Combustion Turbines 6 75 13 2 63 84% DLNB 

Lime Kilns 0 C.M. 

Glass Furnaces (4) 2 97 49 0 0 0% Oxy-Fire 

Furnaces 5 135 27 5 81 60% LNB 

Asphalt Plants (5) 7 65 9 0 0 0% LNB 

Process Heating 3 107 36 3 64 60% LNB 

Reciprocating Engines 12 266 22 11 222 83% LEC, NSCR,SCR 

Total for Units Affected by 

Emission L:imits 76 28,279 41 14,919 53%

Notes:

1) No. of units reflect total number of units in the identified RACT source category regardless of major source status and not considering exemptions.2) EGU coal boiler emissions represent emission rates in 2005 in meeting current NR 428 requirements and an average heat input. Industrial emissions represe2002 emissions adjust according to NR 428 emission limitations effective in 2005.3) Emission units which are not expected to meet exemptions which do not already controled to the RACT emission limit level.4) Glass Furnaces emitted over 700 tons per year prior to 2001. However, St. Gobain converted to oxy-fire to upgrade furnaces and reduce fuel cost by 2005. Tconsistent with oxy-fire operation.

5) The owners and operators of most asphalt plants are entering into a general permit which restricts the facility PTE to less than 25 TPY.a) Oxy-firing is a significant rebuilding which extends plant life. Cost attributable to NOx reduction < 2,000. (7)

Sources in RACT Category (1) Impact of RACT Requirements Propos

RACT Source Category
Attachment C 

Summary of Public Comments and Department Responses 

The Natural Resource Board approved the draft RACT rule for public hearing and comments at its 

January, 2007 Board meeting. A public hearing was on March 15, 2007 in Milwaukee. Twelve people 

attended the hearing. WE Energies, Alliant Energy, and Wisconsin Manufacturers and Commerce, 

testified opposing major portions of the rule. Sierra Club/Clean Wisconsin testified in support of the rule, 

but suggested changes to strengthen the emission limits in the rule. Additionally, written public comments 

were accepted through March 19th, 2007. The Department received 14 sets of written comments. This 

document summarizes the public comments and the Department’s responses to comments. 

 

1. Implementation of the Clean Air Interstate Rule Satisfies the NOx RACT Requirement.

Comments: 

WMC, WE Energies, and Alliant indicated that implementation of the Clean Air Interstate Rules for 

EGUs was enough to satisfy the NOx RACT requirement. The commentors quoted several EPA 

documents making a similar statement. 

Response: 

The Department disagrees with this position for the following reasons. 

• The NOx RACT requirement and the CAIR program are developed to address 2 distinct provisions 

of the Clean Air Act. NOx RACT is a direct requirement of the §§ 172(c) and 182(b)(1)(A) and (2) 

and (f) of the Act [42 USC 7502(c) and 7511a(b)(1)(A) and (2) and (f)] which require that major 

sources of NOx (and VOCs) in ozone nonattainment areas be subject to emission limits that 

represent Reasonably Available Control Technology (RACT) . CAIR is an EPA program developed 

by federal rule to assist states in meeting the SIP requirements of § 110(a)(2)(D) of the Act [42 USC 

7410(a)(2)(D)]. That provision requires a state SIP to include provisions prohibiting emission 

sources in the state from interfering with another state’s ability to attain and maintain ambient air 

quality standards. 

• EPA issued its conclusion that CAIR=RACT for electric generating units (EGUs), as part of EPA 

guidance for implementation of the 8-hour ozone standard (“Phase 2” of the Final Rule to Implement 

the 8-Hour Ozone National Ambient Air Quality Standard) in November 2005 (70 Federal Register 

61611, November 29, 2005). EPA subsequently requested additional public comment of its 

CAIR=RACT conclusion in December, 2006 (71 Federal Register 75902, December 19, 2006). 

EPA has not yet responded to the additional public comments on its conclusion that CAIR=RACT 

for EGUs. 

• EPA’s Phase 2 guidance allows, but does not require, states to conclude those EGUs subject to and 

complying with CAIR meet NOx RACT requirements for EGUs. 

• EPA’s conclusion that CAIR=RACT for EGUs is based on EPA’s analysis that the application of the 

CAIR NOx budget in the 28-state region in the eastern part of the country will result in more 

emission reductions in that region than the reductions accomplished by applying NOx RACT to 

those EGUs located just in the nonattainment areas in the same region. 

• The CAIR rules are based on establishing a NOx emissions budget for each state calculated by 

allocating NOx emission allowances for EGUs within the state. The focus of the CAIR rules is a 

regional cap and trade program which allows an EGU to meet its CAIR emissions cap by installing 

controls or by purchasing allowances from another EGU within the 28-state region that has over 

complies with its emissions cap. Under the CAIR program, there is no assurance that a specific 

27 
EGU will install NOx controls to comply with its emissions cap. Instead, an EGU could achieve 

compliance with CAIR through the purchase of allowances from an over complying EGU. 

• EPA’s guidance does not address the issue of how its conclusion that CAIR=RACT for EGUs 

complies with (or overrides) the specific Clean Air Act requirement that a state’s SIP require NOx 

RACT emission limits for all major sources within an ozone nonattainment area. Federal courts 

have repeatedly held that EPA’s guidance cannot override a specific CAA requirement. For 

example, on December 22, 2006, the D.C. Circuit Court of Appeals vacated EPA’s April 2004 rule 

(“Final Phase 1 Rule to Implement the 8-Hour Ozone National Ambient Air Quality Standard”) 

because of the Court’s finding that provisions of the rule were contrary to the anti-backsliding 

provision (§ 172(e)) [42 USC 7502(e)]of the Clean Air Act. South Coast Air Quality Management 

District v. EPA, 472 F.3d 882 (D.C. Cir. 2006). 

• Because EPA’s conclusion that CAIR=RACT for EGUs is not consistent with a specific Clean Air 

Act requirement (i.e., that all major sources of NOx emissions in an ozone nonattainment area are 

subject to NOx RACT), a state’s reliance on EPA’s conclusion could subject the state’s SIP to a 

legal challenge. 

For these reasons, the Department has included NOx RACT emission limits for all major NOx sources, 

including EGUs, in the ozone nonattainment areas in the proposed rule, in compliance with the Clean 

Air Act requirements for ozone SIPs. In addition, the Department has included a specific provision in 

the proposed NOx RACT rule which allows an EGU to demonstrate that the emission reductions that the 

EGU achieves in complying with the CAIR requirements constitute compliance with the NOx RACT 

emission limitation requirements of the proposed rule. 

Specifically, section NR 428.26(2) of the proposed rule provides: 

“CAIR EMISSIONS UNITS. The owner or operator of an emission unit which is subject to the 

emission reduction requirements of the clean air interstate rule (CAIR) under 40 CFR part 97 may 

demonstrate that the NOX emission reductions achieved by the emissions unit in complying with the 

CAIR requirements constitute compliance with the NOx RACT emission limitation requirements of 

this subchapter.” 

This provision balances the specific requirement of the Clean Air Act to set NOx RACT emission limits 

for all major NOx sources in an ozone nonattainment area with the recognition that individual EGUs 

may meet both their CAIR requirements and their NOx RACT requirements through the installation of 

NOx emission controls which are designed and operated to meet both regulatory requirements. This 

provision contrasts with the opportunity provided by EPA guidance that allows states to rely on EPA’s 

“generic” finding that CAIR=RACT for EGUs, an option which is in direct contradiction of the Clean 

Air Act requirement that NOx RACT be applied to all major sources in an ozone nonattainment area.. 

2. Cost for RACT Controls.

Comments: 

Alliant, WIEG, WMC commented that DNR’s $2,500/ton upper limit for RACT controls was too high. 

The commentors cite a 1994 EPA document that they claim establishes a $1,300/ton limit on the 

application of NOx RACT. They cite additional documentation included in EPA guidance, including the 

Phase 2 Implementation plan for the 8-hour ozone standard and the NOx SIP Call. WMC further claims 

that the DNR’s application of the consumer price index to adjust to current year dollars is inaccurate. 

WMC claims that calculation of the maximum control costs should be based on the incremental costs 

and not calculated from an uncontrolled level. 

ANR Pipeline indicates, “The costs and stringency associated with compliance approaches that may be 

appropriate for electric generating units (EGUs) are not appropriate for smaller industrial 

facilities...[B]ased on ANR’s experience, requirements related to issues such as applicability thresholds, 

28 
emission limits, and compliance monitoring and testing are more stringent and costly for the Proposed 

Rule than typical NOx RACT rules or EPA’s NOx SIP Call.” ANR also indicates that the control costs 

are underestimated. 

Clean Wisconsin and Sierra Club commented that the $2,500/ton limit is too low. They cite data from 

other states where RACT was established in other states including the Ozone Transport Commission, 

South Carolina and California. In these states NOx control was found reasonable in ranges at $3,500/ton 

to as much as $10,000 in California. 

Response: 

DNR reviewed the comments and affirms its original analysis and determination that an upper limit of 

RACT should be calculated from a level of $2,500/ton based on reductions from an uncontrolled level. 

The basis for EPA’s 1994 document is even older documents that are quite dated. The technology of 

NOx control and costs has change considerably since then. DNR believes that the strongest argument 

for establishing a $2,500/ton limit is EPA’s NOx SIP Call. Quoting from EPA’s NOx SIP Call rule: 

“The NOx controls for this rulemaking were considered highly cost effective for the purposes of 

reducing ozone transport to the extent they achieve the greatest feasible emissions reduction but still cost 

no more than $2,000 per ton of ozone season NOx emissions removed (in 1990 dollars), on average, for 

each subcategory.” DNR believes that if EPA determined that $2,000/ton was highly cost effective that 

DNR could reasonably determine that $2,500/ton meets the reasonable test for NOx RACT in 

Wisconsin. 

3. Intra-Facility and Multi-Facility Averaging.

Comments: 

Sierra Club and Clean Wisconsin object to inclusion of multi-facility averaging. They cite EPA’s 

definition of RACT as “the lowest emission limit that a particular source is capable of meeting by 

application of control technology that is reasonably available...” Additionally they cite environmental 

justice concerns if RACT level of controls are not applied at WE Energies Valley Plant in downtown 

Milwaukee. 

Although not specifically addressed in Alliant’s or WE Energies’ comments, it was apparent to DNR 

staff during initial rule development that multi-facility averaging is a critical compliance component for 

electric generating units in the rule. 

Response: 

Multi-facility averaging is a compliance option in the rule. In order to take advantage of the compliance 

option sources must obtain an additional 10% emission reduction beyond the source specific 

requirements. EPA’s guidance document, Improving Air Quality with Economic Incentive Programs,

provides the basis for application of an economic incentive program as the justification for the 10% 

additional emission reduction needed to implement an economic incentive program. Additionally, ozone 

is a regional pollutant. The production of ozone resulting from NOx emissions at power plants occurs 

far downwind from the source of NOx. The DNR is concerned about environmental justice, but in this 

case, people living in the vicinity of the smoke stacks are not exposed to higher concentrations of ozone 

than people living at greater distances. 

4. Application of a Compliance Margin to Calculate RACT Emission Limits.

Comment: 

Sierra Club and Clean Wisconsin argue that there is no need for a compliance margin in the rule, since 

they feel a compliance margin is already built into the proposed emission limits and the multi-facility 

averaging provides an additional compliance margin. 

29 
Response: 

A compliance margin accommodates unforeseen circumstances such as control equipment that does not 

operate as efficiently as planned. Therefore, the Department affirms that inclusion of the compliance 

margin is appropriate in determining a RACT emission limit. 

5. Definition of RACT Existing, NR428 meets RACT

Comment: 

WMC argues that the existing NR428 meets the NOx RACT requirement. 

Response: 

The Department disagrees with WMC’s conclusion. Existing NR428 was created to meet rate of 

progress requirements for the 1-hour ozone standard. In the 1-hour attainment demonstration, the 

Department determined that additional emission reductions, enough to accelerate attainment by at least 

one ozone season, were not economically feasible. To accelerate attainment, a very large amount of NOx 

emissions would need to be reduced over a short time. Given the limited number of opportunities for 

cheap, fast emission reductions in the Milwaukee area, Department staff found accelerating attainment 

infeasible when they developed the attainment demonstration for the 1-hour standard. 

6. Combustion Tuning

Comments: 

Clean Wisconsin supports the inclusion of combustion tuning in the rule, citing energy efficiency and 

cost effectiveness concerns. 

Alliant, ANR Pipeline, Engine Manufacturers Association, WE Energies, Wisconsin Industrial Energy 

Group, Wisconsin Paper Council, and WMC cite numerous problems with the combustion tuning 

requirements. These commentors indicate, due to fuel prices, most sources already tune their boilers and 

therefore the requirement is unnecessary. These commentors also cite the modest emission reductions, 

stack testing and reporting requirements as problematic. ANR Pipeline indicated that combustion tuning 

should be eliminated for IC engines and turbines. 

EPA indicated that alternative methods for combustion tuning that are approved by the Department must 

also be approved by EPA. 

Response: 

The Department proposes to drop combustion tuning from the NOx RACT rule. This provision 

wouldn’t have accounted for very large emission reductions because it would have applied to smaller 

sources and some of the reductions will be achieved through voluntary combustion tuning. 

The Department may consider combustion tuning in future air quality related initiatives such as PM2.5 

or ozone attainment demonstrations, reasonable progress for haze or climate change proposals. In these 

new initiatives, DNR will work with industrial representatives to address their concerns and streamline 

testing and reporting requirements. 

7. Emission Limits for EGUs

Comments: 

Sierra Club and Clean Wisconsin indicate that the 2009 emission limits for power plants are too lenient. 

David Bender provided data for power plants in Kentucky and Texas showing that a continuous NOx 

emission limit at 0.04 lbs/mmBtu is not unreasonable. 

Response: 

DNR developed 2009 emission limits for power plants considering the time frame needed to permit and 

install operating equipment by 2009. Given that there are only two years before the May 1, 2009 

30 
compliance data, it is simply not possible to acquire funding, permit and install major pieces of control 

equipment such as SCR. Additionally, DNR developed emission limits capped at $2,500/ton. While it 

is true that NOx emission limits in the 0.04 lbs/mmBtu range can be achieved for various control 

equipment configurations, those control configurations are more costly than $2,500/ton. 

8. Emission Unit Exemptions

Comments: 

EPA indicates that any exemptions must be for sources where application of RACT is technologically or 

economically unreasonable. EPA goes on to indicate that the once in always in policy applies for 

sources that are required to install RACT controls. EPA also suggests language changes to clarify 

sources exempted due to federally enforceable limits. 

James McCarthy, suggests creating a cut-off for combustion turbines, below which the sources would be 

exempt. WMC suggests increasing the exemption for low capacity units during the ozone season. Solar 

Turbine suggests exempting combustion turbines less than 25 MW 

Response: 

The Department modified the proposed exemptions to define emergency, auxiliary, and backup units 

which would normally qualify under the low operating unit exception. In addition, the Department has 

revised the capacity factor used in calculating the utilization threshold to 20% for all source categories, 

increased the threshold to 75 tons per year in the revised rule, and created an exemption size threshold 

for simple cycle turbines at 25 MW. 

9. In Attainment – No RACT Is Justified. 

Comment: 

WMC argues that RACT is not justified, since the area has already or will attain the 8-hour ozone 

standard in the near future. 

Response: 

Any regulatory requirement that should have been on the books at the time a re-designation request is 

submitted must still be adopted for the re-designation request to be complete. The NOx RACT submittal 

was due to EPA in September 2006. As such it is a past due requirement of the nonattainment areas and 

is necessary for EPA to consider approving our redesignation requests that will be submitted later this 

year. Notwithstanding the need to submit NOx RACT rules to support the redesignation requests, there 

are other reasons to develop and submit NOx RACT rules. 

a. Sheboygan County remains in nonattainment status. A statistical analysis prepared by 

the DNR indicates that Sheboygan County has less than a 10% chance of attaining the 8-

hour ozone standard after the 2007 ozone season. 

b. EPA promulgated a new fine-particle standard in October 2006. Monitoring data from 

the most recent three years indicates that the Milwaukee/Waukesha area is violating that 

new fine-particle standard. NOx RACT will be a necessary part of any attainment plan 

for the fine-particles in Milwaukee/Waukesha nonattainment area. 

c. EPA is in the process of promulgating a new ozone standard. They are under court 

order to finalize the standard by March 2008. The Clean Air Science Advisory 

Committee (CASAC), EPA’s advisory group on air quality standards indicates, “There 

is no scientific justification for retaining the current primary 8-hr NAAQS of 0.08 parts 

per million (ppm), and ... Therefore, the CASAC unanimously recommends a range of 

0.060 to 0.070 ppm for the primary ozone NAAQS.” If the standard is revised as 

CASAC recommends, it is very likely that the Milwaukee area will once again violate 

the ozone standard. RACT will once again be a requirement. Since there is a significant 

31 
public health benefit to the NOx RACT rules, it is prudent to continue with RACT rules 

now instead of waiting for requirements from implementing a new standard. 

d. NOx RACT rules will provide a significant public health benefit. Based on EPA’s 

COBRA benefits model, the costs savings in public health benefit will be approximately 

$80,000,000/year, or about twice the cost of compliance. 

10. Temporary Waivers for Outages 

Comment: 

Alliant suggested adding temporary waivers from emission limits to accommodate outages. 

Response: 

The Department believes that there is a need for a waiver for unforeseen circumstances that affect the 

reliability of the electric grid. That need for unforeseen circumstances is adequately covered in the rule. 

The Department does not agree that there is a need to provide such a waiver for planned outages. 

11. Competitive Disadvantage

Comment: 

WMC indicates that application of RACT in the Wisconsin’s non-attainment area will put Wisconsin 

sources at a competitive disadvantage.

Response: 

Application of RACT is required by federal law. Further, for example, the Chicago 8-hour ozone 

nonattainment area is immediately adjacent to the Milwaukee nonattainment. Illinois is in the process of 

developing NOx RACT rules as well. Illinois current proposal includes a statewide NOx RACT with 

emission limits commensurate with those in Wisconsin’s proposed rule. Additionally, Illinois has 

negotiated multi-pollutant agreements with their major power producers, representing about 90% of the 

generating capacity in the state. Those emission limits are more stringent than the ones proposed in our 

rule. Therefore, application of NOx RACT in Wisconsin does not appear to put our sources at a 

competitive disadvantage, at least, with a state that shares a border and has similar air quality 

circumstances to our own. 

12. Compliance Schedule, Move Phase 2 Limits to 2015

Comment: 

WIEG commented that the second phase of the RACT compliance should be moved to 2015 to make it 

consistent with the second phase of the Clean Air Interstate Rule. 

Response: 

The compliance date for RACT is May 1, 2009, but the Department is allowing a later final compliance 

date, May 1, 2013, for electric utilities to come into compliance. Because the Department believes that 

final compliance for large installations at power plants cannot occur within two years, the Department 

proposed the 2013 date in the public hearing draft. EPA must approve our SIP. From discussions with 

that agency, we do not believe that a later compliance date would be allowed under federal regulations 

and guidance. In addition, the Department did not receive any data to support the extension of the final 

compliance date to beyond 2013. Therefore, extending the compliance date beyond 2013 is not justified. 

13. RACT Limit for Combustion Turbines 

Comments: 

Solar Turbine suggests: Breaking the combustion turbine category into subcategories; smaller 

combustion turbines cannot meet the emission limits without expensive add-on controls; simple-cycle 

gas turbines could not meet a 9 ppm limit for retrofitted equipment and recommended specific emission 

limits for these turbines; different limits for liquid-fired turbines; other parameters to determine 

compliance. 

32 
Waste Management suggested that contaminants in land-fill gas can render SCR and SNCR ineffective. 

Additionally, the requirements for combustion turbines make the beneficial use of land-fill gas 

uneconomical. Waste Management argues that there is a net reduction of using land-fill gas in 

combustion turbines versus flaring the gas. 

Response: 

In response to comments, the Department created an exemption size threshold for simple cycle turbines 

at 25 MW. The Department also adjusted emission limits for all combustion turbine categories to 

reflect available low NOx combustion techniques without the use of post-combustion control. 

14. Definition of Wall-Fired Boiler with Maximum Heat Rate between 500 to1000 mmBtu/hr.

Comments: 

WE Energies suggested that DNR change the language in the rule that describes wall-fired boilers in the 

500 to1000 mmBtu/hr range to language that reflects industry standards for such boilers. The issue is 

large heat release for some wall-fired boilers compared to the physical size of the boiler. 

Response: 

DNR agrees with the comment and has made the suggested change. 

15. Green Tier

Comment: 

EPA indicates that inclusion of the Green Tier program as a compliance strategy will necessitate 

submitting the Green Tier program as part of Wisconsin’s federal enforceable state implementation plan 

(SIP). 

Response: 

While the Department strongly supports the goals of the Green Tier program, we believe that the 

Green Tier program being a federally enforceable part of the SIP would delay promulgation of this 

rule and might be counter to the Green Tier program goals. Therefore, we’ve dropped the proposed 

Green Tier language in this rule that was only a general reference to the program anyway. The 

Department will continue to search for ways to take advantage of the Green Tier program to achieve 

superior environmental goals. 

16. Alternative Monitoring Strategies

Comment: 

EPA indicates that any alternative monitoring strategy approved by the Department must also be 

approved by EPA. 

Response: 

DNR has made the change to insure EPA approval. 

17. Monitoring, Recordkeeping and Reporting

Comment: 

EPA indicates that the Department’s rule should clarify how records are to be kept. ANR Pipeline 

objected to CEMs for turbines and periodic testing for IC engines. The Engine Manufacturers 

Association indicates that IC engines almost always operate at full load so, only testing at 100% load is 

necessary. Waste Management indicates that periodic testing for IC engines burning land-fill gas is not 

cost effective. 

Response: 

33 
The Department revised the rule to streamline monitoring requirements without compromising the 

compliance demonstration. The public hearing draft rule allowed an alternative EPA monitoring method 

with written approval of the department. The revised rule will allow this alternative without approval for 

specific source categories. Other miscellaneous modifications have been made based on comments to 

address consistency in test method standards and for certain source categories and to clarify portions of 

the rule. 

18. Alternative Compliance Methods

Comment: 

EPA indicates that averaging times longer than 30 days rolling averages need to meet requirements of a 

1993 guidance memo, “Fuel Switching to Meet the Reasonably Available Control Technology 

Requirements for Nitrogen Oxides.” 

Response: 

After subsequent discussions, EPA concluded that the compliance averaging times in the public hearing 

draft of the rule were approvable. 

19. Electric Reliability Waiver

Comment: 

EPA states that the rule should be clarified so that it is clear the intent is not to delay the May 1, 2009 

compliance date. EPA indicates that this type of enforcement discretion has been used in the past, for 

instance, to allow non-spec gasoline after a refinery explosion. 

Response: 

DNR revised the rule to add EPA’s approval as well as the Department’s approval for the waiver. 

20. No Environmental Benefit for Controlling Small IC Engines and Turbines

Comment: 

ANR Pipeline indicates that there is no environmental benefit for controlling small units and that the 

minimum size threshold for internal combustion engines and for combustion turbines should be 

increased. 

Response: 

The Department raised exemption threshold for affected engines from 250 to 500 hp. Additionally, the 

Department revised emission limits for natural gas fired engines to 3.0 gr/bhp-hr. 

21. Control Technology for Gas Transmission Sources

Comments: 

ANR Pipeline indicate that natural gas transmission stations are designed with excess capacity that 

results in low utilization, so emission reductions are costly compared to the actual amount of reduction. 

ANR further comments that the proposed rule is not consistent with recent EPA action and that DNR 

inappropriately identified control technology for rich-burn IC engines. 

Response: 

The Department included natural gas transmission stations among the source types eligible for the 

reliability waiver. The Department does not agree that including this category is inappropriate. 

22. Waiver for Natural Gas Transmission Stations from RACT Controls

Comment: 

ANR Pipeline indicates that natural gas transmission stations should get a waiver from NOx RACT 

controls. 

Response: 

No such waiver is allowed under the federal Clean Air Act. 

34 
23. Emission Limits for Lean-Burn IC Engines

Comment: 

The Engine Manufacturers Association commented that the emission factor and cost analysis for leanburn IC engines was inaccurate and needs to be revised. 

Response: 

In response to this comment, the Department raised the exemption threshold for affected engines to 500 

hp. Additionally, the Department revised emission limits for natural gas fired engines to 3.0 gr/bhp-hr. 

III. Green Sheet Memo to DNR Board of RACT Rule Germane Modification

DATE: May 16, 2007 

 

TO: Members of the Natural Resources Board 

FROM: Scott Hassett, Secretary 

SUBJECT: Order AM-17-05, Adoption of germane modifications to the NOx RACT rules in Chap. NR 

428 pursuant to s. 227.19(4)(b)3., Stats.

In April of 2007 the Board adopted RACT rules under Board Order AM-17-05 for control of NOx from 

major sources in the ozone non-attainment area. After further review the Department recommends two 

germane modifications to the adopted rule. Neither modification will significantly affect emission 

reductions achieved by the rule. The specific modifications are: 

• An exemption for certain newer reciprocating engines that are manufactured and certified to meet 

EPA emission standards for newly manufactured engines. The recommended modification is 

proposed in Attachment A.

 

• A restructuring of the "Other Regulated Unit" provision which establishes an exemption from 

RACT requirements for well-controlled emissions units. The modification is for clarity to eliminate 

criteria which are not pertinent to a unit's qualification for the exemption. The recommended 

modification is proposed in Attachment B. 

The changes would be transmitted to the standing committees of the Legislature as "germane modifications" 

pursuant to s. 227.19(4)(b)3., Stats. A "clean copy" version with incorporated germane modifications is 

provided in Attachment C.

I. Analysis of reciprocating engine requirements. 

Stakeholder testimony during adoption highlighted concerns that the NOx RACT rules unduly regulate newly 

manufactured reciprocating engines meeting Federal Tier emission standards. The EPA Tier 1 emission 

standards came into effect by year 2000 (phased in from 1996 to 2000) for all of the engine classes falling 

35 
under RACT source categories. More stringent standards, Tier 2, 3, 4, etc..., are being phased in through 

2015 on an ongoing basis for newly manufactured engines. These federal standards do not apply to 

previously installed or manufactured engines unless the engines undergo a major modification. 

After further review the department has concluded that further regulation of most of the recently 

manufactured engines under the RACT rule is unnecessary. A comparison of Tier emission standards and 

the RACT emission limits is provided in Table 1. The Department has concluded that for certain of these 

engine classes and sizes, the incremental control (if any) necessary in meeting the RACT limit is beyond the 

cost levels considered in establishing the applicable limits of this rule. The adopted RACT rule allows 

exemption of existing well controlled units in other source categories under the provision in s. NR 428.21(3) 

"Other Regulated Units". However, due to the current rule structure, the Tier certified engines do not 

currently qualify for the exemption. 

For these reasons the Department recommends creating a specific exemption in the rule for certain EPA 

certified engines. This action is consistent with the intent of providing an exemption under s. NR 428.21(3) 

"Other Regulated Units" for well-controlled units. This change will result in no significant increased 

emissions. This modification will streamline implementation and compliance requirements for both the 

sources and the Department Requested modifications to Board Order AM-17-05 related to exempting EPA 

certified engines are shown in Attachment A. 

Table 1. Comparision of RACT and EPA Tier Requirements for Compression Ignition Engines 

Regulation Effective Date Engine Size Emission Limit 

(grams/bhp-hr) 

Comment 

Adopted RACT limit 

for existing and new 

engines 

2009 => 500 hp 3.0 NOx 

Federal Standards for 

newly manufactured 

engines: 

Tier 1 

1996-2000 by class* => 500 hp 6.9 NOx + 

NMHC 

Incr. control to meet 

RACT is cost-effective 

=> 2000 hp 

Tier 2 2001-2006 by class* => 500 hp 4.8 NOx + 

NMHC 

Incr. control is not costeffective 

Tier 3 2006 => 500 hp 3.0 NOx + 

NMHC Meets RACT limit 

Tier 4 2009 – 2011 => 500 hp 0.3 – 2.6 NOx Meets RACT limit 

II. Clarification of the Provision in Section NR 428.21(3) "Other Regulated Units". 

The adopted rule contains a provision, s. NR 428.21(3) "Other Regulated Units", to exempt units from 

RACT requirements which are already well-controlled. The exemption qualifications are that the emissions 

unit must be subject to a current s. NR 428 requirement and the unit is subject to federally enforceable 

provisions which limit the unit’s emissions to less than 75 tons per year. 

Stakeholder discussions have demonstrated that the current language of this provision is confusing and 

problematic to the stakeholders. After additional review, the Department has concluded that the language 

should be clarified to accomplish its intent. Therefore, the Department recommends modifying the current 

provision of s. NR 428.21(3) "Other Regulated Units" to restructure the subsection. The requested 

36 
modification does not change the original intent of this subsection. The modification to Board Order AM17-05 related to NR 428.21(3) is shown in Attachment B. 

37 
Attachment A 

Modifications Related to the Exemption of 

Certain Reciprocating Engines Meeting Federal Emission Standards. 

NR 428.21(intro.) is amended to read: 

NR 428.21(intro.) Emissions unit exceptions. The emissions units described in subs. (1), (2) and 

(3) this section are exempt from the emission limitation requirements of s. NR 428.22, but shall comply with 

applicable record keeping requirements under s. NR 428.24. Once an emissions unit no longer qualifies for 

an exemption, the owner or operator of the emissions unit shall comply with the requirements of s. NR 

428.22 by December 31 of the following calendar year, unless an alternate date is approved in writing by the 

department and the administrator. 

NR 428.21(2m) is created to read: 

NR 428.21(2m) RECIPROCATING ENGINES. Any reciprocating engine that is certified to meet 

the applicable federal non-road engine emission standards specified in this subsection is exempt from the 

emission limitations of s. NR 428.22(1)(i): 

(a) A reciprocating compression ignition engine that is certified as meeting Tier 1 requirements as 

specified in 40 CFR part 89, if one of the following applies: 

1. The engine has a maximum design power output of less than 2,000 horsepower. 

2. The engine has a maximum design power output equal to or greater than 2,000 horsepower and 

has a total utilization during each ozone season of less than 1.5 million horsepower-hours, based on actual 

measured output. 

(b) A reciprocating compression ignition engine that is certified as meeting the Tier 2 standard, as 

specified in 40 CFR part 89, or a reciprocating compression ignition engine that is certified as meeting the 

requirements of a more stringent Tier standard, as specified in 40 CFR part 89 or 1039. 

38 
(c) A reciprocating spark ignition engine that is certified as meeting the Tier 1 standard or a 

reciprocating spark ignition engine that is certified as meeting a more stringent Tier standard, as specified in 

40 CFR part 1048. 

NR 428.24(2m) is created to read: 

NR 428.24(2m) RECIPROCATING ENGINES. The owner or operator of an emissions unit 

claiming exemption under s. NR 428.21(2m)(a)2., shall maintain a record of horsepower-hours of operation 

for each ozone season. Measurement of horsepower-hours may be determined using recorded data which 

can be directly related to actual horsepower-hours of operation of the engine including actual total operating 

hours, fuel consumption, or load and duration measurements. 

39 
Attachment B 

Modifications Related to Clarification of "Other Regulated Unit" Provision. 

 

NR 428.21 (3) is amended to read: 

NR 428.21(3) OTHER REGULATED UNIT. An emissions unit which is subject to and meeting an 

emission limitation in s. NR 428.04 or 428.05(3) and which is subject to a federally enforceable condition in 

an air permit issued prior to January 1, 2006 which limits emissions to no more than 75 tons of NOX per year

is exempt from the emission limitations in s. NR 428.22. , if one of the following applies:

(a) The emissions unit is subject to a federally enforceable condition in an air permit which limits its 

emissions to no more than 75 tons of NOX per year.

(b) The emissions unit, because of a physical operating constraint, cannot emit more than 75 tons of 

NOX per year.

40 
Attachment C 

"Clean Copy" with incorporated Germane Modifications

NR 428.21(intro.) Emissions unit exceptions. The emissions units described in this section are 

exempt from the emission limitation requirements of s. NR 428.22, but shall comply with applicable record 

keeping requirements under s. NR 428.24. Once an emissions unit no longer qualifies for an exemption, the 

owner or operator of the emissions unit shall comply with the requirements of s. NR 428.22 by December 31 

of the following calendar year, unless an alternate date is approved in writing by the department and the 

administrator. 

NR 428.21(2m) RECIPROCATING ENGINES. Any reciprocating engine that is certified to meet 

the applicable federal non-road engine emission standards specified in this subsection is exempt from the 

emission limitations of s. NR 428.22(1)(i): 

(a) A reciprocating compression ignition engine that is certified as meeting Tier 1 requirements as 

specified in 40 CFR part 89, if one of the following applies: 

1. The engine has a maximum design power output of less than 2,000 horsepower. 

2. The engine has a maximum design power output equal to or greater than 2,000 horsepower and 

has a total utilization during each ozone season of less than 1.5 million horsepower-hours, based on actual 

measured output. 

(b) A reciprocating compression ignition engine that is certified as meeting the Tier 2 standard, as 

specified in 40 CFR part 89, or a reciprocating compression ignition engine that is certified as meeting the 

requirements of a more stringent Tier standard, as specified in 40 CFR part 89 or 1039. 

(c) A reciprocating spark ignition engine that is certified as meeting the Tier 1 standard or a 

reciprocating spark ignition engine that is certified as meeting a more stringent Tier standard, as specified in 

40 CFR part 1048. 

41 
NR 428.24(2m) RECIPROCATING ENGINES. The owner or operator of an emissions unit 

claiming exemption under s. NR 428.21(2m)(a)2., shall maintain a record of horsepower-hours of operation 

for each ozone season. Measurement of horsepower-hours may be determined using recorded data which 

can be directly related to actual horsepower-hours of operation of the engine including actual total operating 

hours, fuel consumption, or load and duration measurements. 

NR 428.21(3) OTHER REGULATED UNIT. An emissions unit which is subject to and meeting an 

emission limitation in s. NR 428.04 or 428.05(3) is exempt from the emission limitations in s. NR 428.22, if 

one of the following applies: 

(a) The emissions unit is subject to a federally enforceable condition in an air permit which limits its 

emissions to no more than 75 tons of NOX per year. 

(b) The emissions unit, because of a physical operating constraint, cannot emit more than 75 tons of 

NOX per year. 

42 
Attachment 2 

Adopted Rule 

(to be replaced by published rule) 
2

ORDER OF THE STATE OF WISCONSIN 

NATURAL RESOURCES BOARD 

AMENDING AND CREATING RULES 

The Wisconsin Natural Resources Board proposes an order to amend 428.04(2)(h)1. and 

2., 428.05(3)(e)1. to 4. and 484.04(13), (21m), (26m)(d), and (27) and create NR 

428.02(7m), 428 subch. IV and 484.04 (15m),(16m) and (26m)(bm) relating to 

implementation of Reasonably Available Control Technology (RACT) NOx emission 

limitations applicable to major sources in the 8-Hour ozone non-attainment area in 

southeastern Wisconsin. 

 AM-17-05 

Summary Prepared by the Department of Natural Resources

1. Statute interpreted: s. 285.11(6), Stats. The State Implementation Plan developed under s. 285.11(6), 

Stats., is revised. 

2. Statutory authority: s. 227.11(2)(a) and 285.11(1) and (6), Stats. 

3. Explanation of agency authority: Section 227.11(2)(a), Stats., gives state agencies general rulemaking authority. Section 285.11(1) Stats., gives the Department the authority to promulgate rules 

consistent with ch. 285, Stats. Section 285.11(6), Stats., authorizes the Department to develop and revise 

a state implementation plan for the prevention, abatement and control of air pollution. 

4. Related statute or rule: The current provisions of ch. NR 428 established nitrogen oxide emission 

limits for new and existing facilities which are located in the 1-hour ozone nonattainment counties. The 

primary intent in creating these past provisions of ch. NR 428 was to fulfill Clean Air Act (CAA) 

requirements for demonstrating rate-of-progress towards attaining the 1-hour ozone standard. The 

proposed rule will create a new subchapter in ch. NR 428 for purposes of establishing Reasonably 

Available Control Technology (RACT) emission limitations for major sources of nitrogen oxide 

emissions in counties designated as nonattainment under the 8-hour ozone standard. Modifications are 

also proposed to existing portions of ch. NR 428 in relation to the creation of the new subchapter and in s. 

NR 484.04 to reflect incorporation by reference of standards. 

 

5. Plain language analysis: The Clean Air Act requires states to adopt and implement a control program 

of reasonably available control technology (RACT) for major NOx stationary sources in the moderate 

ozone nonattainment area. To meet this requirement, the proposed rule establishes emission limits and 

compliance requirements for emission units at facilities with a total potential to emit of 100 tons/year of 

NOx. The proposed RACT rules conform to the federal Clean Air Act. 

The Department determined that $2,500/ton of NOx removed, from an uncontrolled baseline, is an 

appropriate upper limit for application of RACT at an affected facility. The Department’s proposed 

emission limits for electric utility generating units and larger industrial emission units are based on that 

upper limit. The source categories affected by the rule include industrial boilers, combustion turbines, 

glass and steel furnaces, reciprocating engines, and other miscellaneous large combustion processes. 

The emission limits are designated by source category and fuel type as necessary, but are not applicable 

unless the unit is operated over an utilization threshold during the ozone season as specified in the rule for 
3

each source category. The operating threshold for exemption is based on 20% of the source category's 

unit size threshold for defining the smallest unit subject to the emission limit. The proposed rule also 

exempts emission units from further control if the unit is already meeting an existing NOx emission limit 

under ch. NR. 428 and emits less than 75 tons per year of NOx. And the rule lists specific units such as 

emergency generators, fire-fighting water pumps, peaking units, etc.. which also are exempt from the 

emissions limits. However, once an emissions unit no longer qualifies for one of the exemptions, it is 

subject to the emission limitations on an ongoing basis. 

The rule provides compliance flexibility by providing phased implementation for electric generation units 

subject to CAIR, emissions averaging programs, alternative RACT determinations, demonstration of 

CAIR actions satisfying RACT emission limits, and a reliability waiver option. 

Sources demonstrate compliance with the emission rate limits by 1) Installing and operating continuous 

emissions monitoring systems (CEMs) consistent with 40 CFR part 60 requirements for units with 

considerable variability in operation, 2) Performance stack testing every 2 years for units with less 

variability in operation or emissions, or 3) Continuous parametric monitoring of combustion parameters 

with stack testing every 5 years for all gaseous and oil fired units. The rule allows an owner to request an 

alternative to any of the emissions monitoring requirements. 

6. Summary of, and comparison with, existing or proposed federal regulation: In 2004, the federal 

NOx SIP Call became effective in 21 eastern states requiring control of NOx emissions. However, the 

NOx SIP call did not apply to Wisconsin. The sources affected by the SIP call include electric utility 

generating units greater than 25 megawatts and very large industrial emission units. The USEPA 

estimated the cost of meeting the NOx SIP call requirements to be approximately $2,000/ton of controlled 

NOx emissions and described this as “highly cost-effective.” The Wisconsin NOx RACT rule is based on 

considering controls with a cost ceiling of $2,500 per ton of NOx. 

The EPA is requiring implementation of best available retrofit technology (BART) control by 2013 to 

reduce NOx emissions from certain large emission sources which have visibility impacts in scenic Class I 

areas. The BART requirement is a case-by-case determination and, therefore, cannot be accurately 

represented for this discussion. However, EPA assumes default BART controls resulting in 

approximately 50% to 90% reduction in NOx emissions. The proposed emission limits in the Wisconsin 

rule are similar and do not exceed an anticipated 90% reduction for similar sources. 

The proposed RACT rule proposes emission limits for the type of industrial sources that would be 

affected by federal NOx SIP Call or BART requirements. The proposed emission limits for industrial 

sources reflect a control cost range of approximately $500 to $2,500 per ton of NOx removed. The 

proposed controls for electric utility generating sources reflect a cost range of approximately $1,000 to 

$2,200 per ton of NOx. The proposed emission limits in the Wisconsin rule are similar to default BART 

levels and do not exceed an anticipated 90% reduction for similar sources. It should be noted that both 

the NOx SIP Call and BART regulations primarily affect larger sources and that the proposed RACT rule 

establishes emission limits for additional sources based on the CAA definition of a major sources and the 

level of cost-effectiveness considered for this rule. 

7. Comparison with rules in adjacent states: States near Wisconsin with 8-hour ozone nonattainment 

areas are Illinois, Indiana, Michigan and Ohio. Illinois, Indiana and Ohio also have moderate nonattainment areas. All of the Michigan nonattainment areas are of a lower non-attainment designation of 

either "basic" or "marginal". 

 
4

Illinois: The state of Illinois has proposed a statewide RACT rule for industrial boilers and other sources 

with a potential to emit of 100 tons per year or greater. The Illinois rule affects smaller sources and 

implements equivalent or more stringent requirements than those in the Wisconsin rule. The Illinois 

proposed RACT emission limits are based on a cost-effectiveness ranging up to $2,500 per ton of NOx

removed. The rule proposes combustion tuning for boilers between 50 and 100 mmbtu/hr and emission 

limits for units approximately equivalent to 50 mmbtu/hr across the source categories. Illinois EPA 

negotiated very stringent SO2 and NOx limitations with the utilities in Illinois that generate about 90% of 

the electric power in the state. The resulting emission limits for the Chicago area are more stringent than 

what the Department has proposed for NOx RACT in the Milwaukee area. 

Indiana: Indiana is not proceeding with NOx RACT rule development at this time. 

Michigan: The state of Michigan has made no determination regarding the need for developing RACT 

rules. A Michigan RACT rule is required only if attainment in the basic areas cannot be demonstrated by 

the state's SIP submittal deadline of June 2007. 

 

Ohio: Ohio is developing NOx RACT rules for industrial sources in the Cleveland nonattainment area. 

The rule affects smaller sources and implements equivalent or more stringent requirements than the 

Wisconsin rule for industrial sources. The proposed Ohio rule considers controls up to $5,000 per ton of 

controlled NOx. The proposal requires combustion tuning for boilers between 20 and 50 mmBtu/hr. 

Emission units approximately 50 mmbtu/hr and larger across source categories must meet emission limits. 

8. Summary of factual data and analytical methodologies: 

Department staff identified potentially affected units and source categories based on information 

contained in the air emissions inventory and source permits. A review of available emission control 

technologies and options was conducted based on available EPA resources, industry information, and 

other technical resources. General control assumptions and cost factors for each source category were 

used in evaluating appropriate emission limits and applicability. The proposed emission limitations were 

also compared to both existing and proposed RACT emission limits or NOx emission control programs in 

other states. The department considered technical information obtained through the public comment 

period as applicable to each source category. 

9. Analysis and supporting documents used to determine effect on small business or in preparation 

of economic impact report:

The proposed rule is expected to affect only large industrial sources and therefore it is not anticipated to 

have an impact on small businesses. 

10. Effect on small business: 

The proposed rule is expected to affect only large industrial sources and therefore it is not anticipated to 

have an impact on small businesses. 

11. Agency contact person: 

Thomas Karman 

Thomas.karman@dnr.state.wi.us
5

(608) 264-8856 

The consent of the Attorney General and the Revisor of Statutes will be requested for the incorporation by 

reference of new test methods in ch. NR 484. 

____________________________________________________________________________________ 

SECTION 1. NR 428.02(7m) is created to read: 

 NR 428.02(7m) "Process heater" means an enclosed device using controlled flame, that is not a 

boiler, and that has a primary purpose to transfer heat indirectly to a process material or to a heat transfer 

material for use in a process unit, instead of generating steam. Process heaters may not include 

combustion equipment where the material being heated is in direct contact with the products of 

combustion, such as furnaces or kilns, any unfired waste heat recovery heater or units used for comfort 

heat or space heat, food preparation for onsite consumption, or autoclaves. 

SECTION 2. NR 428.04(2)(h)1. and 2. are amended to read: 

 NR 428.04(2)(h)1. 6.9 grams per brake horsepower-hour for a compression ignition unit with a 

maximum design power output of 1000 hp or greater. 

 2. 4.0 grams per brake horsepower-hour for a spark ignition unit with a maximum design power 

output of 1000 hp or greater. 

SECTION 3. NR 428.05(3)(e)1. to 4. are amended to read: 

NR 428.05(3)(e)1. 9.5 grams per brake horsepower-hour for rich-burn units. 

2. 10.0 grams per brake horsepower-hour for lean-burn units. 

3. 8.5 grams per brake horsepower-hour for distillate fuel oil-fired units. 

 4. 6.0 grams per brake horsepower-hour for dual-fuel units. 
6

SECTION 4. NR 428 subch. IV to follow NR 428.11 is created to read: 

SUBCHAPTER IV 

NOX REASONABLY AVAILABLE CONTROL TECHNOLOGY REQUIREMENTS 

NR 428.20 Applicability and purpose. (1) APPLICABILITY. The requirements of this 

subchapter apply to the owner or operator of an NOX emissions unit which is in a source category 

identified in s. NR 428.22 and which is located at a facility with a combined total potential to emit for all 

NOX emissions units of 100 tons per year or more of NOX and which is in the county of Kenosha, 

Milwaukee, Ozaukee, Racine, Sheboygan, Washington or Waukesha. 

(2) PURPOSE. The purpose of this subchapter is to establish reasonably available control 

technology requirements for NOX emissions units in the ozone nonattainment area consisting of the 

counties of Kenosha, Milwaukee, Ozaukee, Racine, Sheboygan, Washington and Waukesha to comply 

with sections 172(c) and 182(f) of the Act (42 USC 7502(c) and 7511a(f)). 

NR 428.21 Emissions unit exceptions. The emissions units described in this section are exempt 

from the emission limitation requirements of s. NR 428.22, but shall comply with applicable record 

keeping requirements under s. NR 428.24. Once an emissions unit no longer qualifies for an exemption, 

the owner or operator of the emission unit shall comply with the requirements of s. NR 428.22 by 

December 31 of the following calendar year, unless an alternate date is approved in writing by the 

department and the administrator. 

(1) GENERAL EXEMPTIONS. The following emissions units and processes are exempt from 

the emission limitations in s. NR 428.22: 

(a) Any emissions unit operated only to restart electric generation in the event of a complete loss 

of facility power. 
7

(b) Any emissions unit which is operated no more than 500 hours per year and no more than 200 

hours during the ozone season and whose only purpose is to provide electricity to a facility if normal 

electricity service is interrupted or to replace normal critical operations at a facility. 

(c) Any emissions unit whose only function is to pump water in the case of a fire emergency. 

(d) Any emissions unit whose utilization is less than 10% of its capacity factor on an annual 

average basis over a 3-year rolling period and less than 20% of its capacity factor in any year of the 3-

year rolling period and which is owned or operated by an electric generation utility or gas transmission 

utility. 

(e) A research or development unit. 

(f) An engine testing operation or process line. 

(g) Any gaseous fuel fired unit used to control VOC emissions from a commercial or industrial 

process. 

(2) LOW OPERATING UNIT. An emissions unit described in s. NR 428.20 is exempt from the 

emission limitations of s. NR 428.22 if, during each ozone season, the emissions unit's utilization based 

on actual measured heat input or output is less than the utilization threshold for the source category 

according to the following equation: 

UUi < (Category capacity ) x (3,672 hours / Ozone Season ) x Capacity Factor Equation 1 

where: 

UUi is the unit's actual fuel consumption or output in measurement units consistent with the 

calculated utilization threshold for the source category in s. NR 428.22 

Category capacity is the lower value in the range of unit capacity or design output used to 

describe the unit’s source category i in s. NR 428.22 

Capacity factor is 0.20 for all source categories in s. NR 428.22 

(2m) RECIPROCATING ENGINES. Any reciprocating engine that is certified to meet the 
8

applicable federal non-road engine emission standards specified in this subsection is exempt from the 

emission limitations of s. NR 428.22(1)(i): 

(a) A reciprocating compression ignition engine that is certified as meeting Tier 1 requirements as 

specified in 40 CFR part 89, if one of the following applies: 

1. The engine has a maximum design power output of less than 2,000 horsepower. 

2. The engine has a maximum design power output equal to or greater than 2,000 horsepower and 

has a total utilization during each ozone season of less than 1.5 million horsepower-hours, based on actual 

measured output. 

(b) A reciprocating compression ignition engine that is certified as meeting the Tier 2 standard, as 

specified in 40 CFR part 89, or a reciprocating compression ignition engine that is certified as meeting the 

requirements of a more stringent Tier standard, as specified in 40 CFR part 89 or 1039. 

(c) A reciprocating spark ignition engine that is certified as meeting the Tier 1 standard or a 

reciprocating spark ignition engine that is certified as meeting a more stringent Tier standard, as specified 

in 40 CFR part 1048. 

(3) OTHER REGULATED UNIT. An emissions unit which is subject to and meeting an emission 

limitation in s. NR 428.04 or 428.05(3) is exempt from the emission limitations in s. NR 428.22, if one of 

the following applies: 

(a) The emissions unit is subject to a federally enforceable condition in an air permit which limits 

its emissions to no more than 75 tons of NOX per year. 

(b) The emissions unit, because of a physical operating constraint, cannot emit more than 75 tons 

of NOX per year. 

NR 428.22 Emission limitation requirements. (1) EMISSION LIMITS. Except as provided in 

sub. (2), on or after May 1, 2009, no person may cause, allow or permit NOX to be emitted in excess of 

the following emission limitations on a 30-day rolling average basis: 
9

(a) Boilers. 1. For a solid fuel-fired boiler with a maximum heat input capacity equal to or greater 

than 1,000 mmBtu per hour, one of the following, as applicable: 

a. If tangential, wall, cyclone or fluidized bed-fired, 0.10 pound per mmBtu of heat input. 

b. If arch-fired, 0.18 pound per mmBtu of heat input. 

2. For a solid fuel-fired boiler with a maximum heat input capacity equal to or greater than 500 

mmBtu per hour and less than 1,000 mmBtu per hour, one of the following, as applicable: 

a. If tangential-fired, 0.15 pound per mmBtu of heat input. 

b. If wall-fired with a heat release rate equal to or greater than 17,000 Btu per cubic feet per hour, 

0.17 pound per mmBtu of heat input. 

c. If wall-fired with a heat release rate less than 17,000 Btu per cubic feet per hour, 0.15 pound 

per mmBtu of heat input. 

d. If cyclone-fired, 0.15 pound per mmBtu of heat input. 

e. If arch-fired, 0.18 pound per mmBtu of heat input. 

g. If fluidized bed-fired, 0.10 pound per mmBtu of heat input. 

3. For a solid fuel-fired boiler with a maximum heat input capacity equal to or greater than 250 

mmBtu per hour and less than 500 mmBtu per hour, one of the following, as applicable: 

a. If tangential-fired, 0.15 pound per mmBtu of heat input. 

b. If wall-fired with a heat release rate equal to or greater than 17,000 Btu per cubic feet per hour, 

0.17 pound per mmBtu of heat input. 

c. If wall-fired with a heat release rate less than 17,000 Btu per cubic feet per hour, 0.15 pound 

per mmBtu of heat input. 

d. If cyclone-fired, 0.15 pound per mmBtu of heat input. 

f. If arch-fired, 0.18 pound per mmBtu of heat input. 

g. If fluidized bed-fired, 0.10 pound per mmBtu of heat input. 

h. If stoker-fired, 0.20 pound per mmBtu of heat input. 
10

4. For a solid fuel-fired boiler with a maximum heat input capacity equal to or greater than 50 

mmBtu per hour and less than 250 mmBtu per hour, one of the following, as applicable: 

a. If tangential-fired, 0.15 pound per mmBtu of heat input. 

b. If wall-fired with a heat release rate equal to or greater than 17,000 Btu per cubic feet per hour, 

0.17 pound per mmBtu of heat input. 

c. If wall-fired with a heat release rate less than 17,000 Btu per cubic feet per hour, 0.15 pound 

per mmBtu of heat input. 

d. If cyclone-fired, 0.15 pound per mmBtu of heat input. 

e. If fluidized bed-fired, 0.10 pound per mmBtu of heat input. 

f. If stoker-fired, 0.25 pound per mmBtu of heat input. 

5. For a gaseous fuel-fired boiler with a maximum heat input capacity equal to or greater than 100 

mmBtu per hour, 0.08 pound per mmBtu of heat input. 

6. For a distillate fuel oil-fired boiler with a maximum heat input capacity equal to or greater than 

100 mmBtu per hour, 0.10 pound per mmBtu of heat input. 

7. For a residual fuel oil-fired boiler with a maximum heat input capacity equal to or greater than 

65 mmBtu per hour, 0.15 pound per mmBtu of heat input. 

(b) Lime kilns. For a lime kiln with a maximum heat input capacity equal to or greater than 50 

mmBtu per hour, one of the following as applicable: 

1. For a gaseous fuel-fired unit, 0.10 pound per mmBtu of heat input. 

2. For a distillate oil-fired unit, 0.12 pound per mmBtu of heat input. 

3. For a residual oil-fired unit, 0.15 pound per mmBtu of heat input. 

4. For a coal-fired unit, 0.60 pound per mmBtu of heat input. 

5. For a coke-fired unit, 0.70 pound per mmBtu of heat input. 
11

(c) Reheat, annealing or galvanizing furnaces. For a reheat, annealing or galvanizing furnace 

with a maximum heat input capacity equal to or greater than 75 mmBtu per hour, 0.08 pounds per million 

Btu of heat input. 

(d) Glass furnaces. For a glass manufacturing furnace with a maximum heat input capacity equal 

to or greater than 50 mmBtu per hour, 2.0 pounds per ton of produced glass. 

(e) Asphalt plants. For an asphalt plant with a maximum heat input capacity equal to or greater 

than 65 mmBtu per hour, one of the following as applicable: 

1. For a gaseous fuel-fired unit, 0.15 pound per million Btu of heat input. 

2. For a distillate fuel oil-fired unit, 0.20 pound per million Btu of heat input. 

3. For a residual fuel oil-fired or waste oil-fired unit, 0.27 pound per million Btu of heat input. 

(f) Process heating. For a process heater, dryer, oven or other process heating device, one of the 

following as applicable: 

1. For a gaseous fuel-fired unit with a maximum heat input capacity equal to or greater than 100 

mmBtu per hour, 0.10 pound per mmBtu of heat input. 

2. For a distillate oil-fired unit with a maximum heat input capacity equal to or greater than 100 

mmBtu per hour, 0.12 pound per mmBtu of heat input. 

3. For a residual oil-fired unit with a maximum heat input capacity equal to or greater than 65 

mmBtu per hour, 0.18 pound per mmBtu of heat input. 

(g) Simple cycle combustion turbines. For a simple cycle combustion turbine, one of the 

following exhaust outlet concentrations, corrected to 15% O2 and at ambient temperatures greater than 

0o

F, as applicable: 

1. For a unit with a maximum design power output equal to or greater than 50 megawatts, one of 

the following, as applicable: 

a. If natural gas-fired, 25 parts per million dry volume. 

b. If distillate oil fuel-fired, 65 parts per million dry volume. 
12

c. If biologically derived gaseous fuel-fired, 35 parts per million dry volume. 

2. For a unit with a maximum design power output equal to or greater than 25 megawatts and less 

than 50 megawatts, one of the following as applicable: 

a. If natural gas-fired, 42 parts per million dry volume. 

b. If distillate oil fuel-fired, 96 parts per million dry volume. 

c. If biologically derived gaseous fuel-fired, 35 parts per million dry volume. 

(h) Combined cycle combustion turbines. For a combined cycle combustion turbine, one of the 

following exhaust outlet concentrations, corrected to 15% O2 and at ambient temperatures greater than 

0o

F, as applicable: 

1. For a natural gas-fired unit with a maximum design power output equal to or greater than 25 

megawatts, 9 parts per million dry volume. 

2. For a natural gas-fired unit with a maximum design power output equal to or greater than 10 

megawatts and less than 25 megawatts, 42 parts per million dry volume. 

3. For a distillate oil fuel-fired unit with a maximum design power output equal to or greater than 

10 megawatts, 42 parts per million dry volume. 

4. For a biologically derived gaseous fuel-fired unit with a maximum design power output equal 

to or greater than 10 megawatts, 35 parts per million dry volume. 

(i) Reciprocating engines. For a reciprocating engine with a maximum design power output equal 

to or greater than 500 horsepower, one of the following as applicable: 

1. For a rich-burn spark ignition unit, 3.0 grams per brake horsepower-hour. 

2. For a lean-burn spark ignition unit, 3.0 grams per brake horsepower-hour. 

3. For a diesel fuel-fired compression unit, 3.0 grams per brake horsepower-hour. 

4. For a dual fuel-fired compression unit, 3.0 grams per brake horsepower-hour. 

(2) ELECTRIC UTILITY BOILER COMPLIANCE SCHEDULE. The owner or operator of an 

electric utility boiler subject to the provisions of 40 CFR part 97 shall demonstrate compliance with the 
13

following interim NOx emission limitations, as applicable, on a 30-day rolling average by May 1, 2009 

and with the emission limitations in sub. (1)(a) on and after May 1, 2013: 

(a) For a solid fuel-fired boiler with a maximum heat input capacity equal to or greater than 1,000 

mmBtu per hour, one of the following, as applicable: 

1 If tangential, wall, cyclone or fluidized bed-fired, 0.15 pound per mmBtu of heat input. 

2. If arch-fired, 0.18 pound per mmBtu of heat input. 

(b) For a solid fuel-fired boiler with a maximum heat input capacity equal to or greater than 500 

mmBtu per hour and less than 1,000 mmBtu per hour, one of the following, as applicable: 

1. If tangential-fired, 0.15 pound per mmBtu of heat input. 

2. If wall-fired, 0.20 pound per mmBtu of heat input. 

3. If cyclone-fired, 0.20 pound per mmBtu of heat input. 

4. If arch-fired, 0.18 pound per mmBtu of heat input. 

5. If fluidized bed-fired, 0.15 pound per mmBtu of heat input. 

NR 428.23 Demonstrating compliance with emission limitations. The owner or operator of an 

emissions unit shall determine the emissions unit's NOX emissions and shall determine compliance with 

the emission limitations in s. NR 428.22 according to the applicable methods in this section. 

(1) EMISSIONS MONITORING REQUIREMENTS. (a) Installation and operation. No later 

than April 1, 2009 or April 1 of the year an emissions unit first becomes subject to an emission limitation 

in s. NR. 428.22, the owner or operator of the emissions unit shall do the following: 

1. Submit to the department in writing, a certification of the installation and operation of all 

monitoring systems or a certification of the completion of initial emission performance tests required 

under par. (b). 

2. Begin and continue to monitor, measure and record all data necessary to determine emissions 

in the measurement units of the applicable emission limitation according to the methods of this section. 
14

(b) Monitoring systems and procedures. 1. 'Part 75 continuous emissions monitoring.' The owner 

or operator of an affected unit as defined under s. NR 400.02(11), or an emissions unit subject to 40 CFR 

part 97 shall monitor NOX emissions for requirements of this subsection by installing and operating 

monitoring equipment and measuring and recording NOX emissions data according to methods and 

specifications of 40 CFR part 75 and 40 CFR part 75, Appendices A to I, incorporated by reference in s. 

NR 484.04(27), as required of an affected unit or an emissions unit subject to 40 CFR part 97. 

2. 'Continuous emissions monitoring.' Except as provided in subd. 1., the owner or operator of an 

emissions unit subject to an emissions limitation in s. NR 428.22(1)(a) to (d) shall monitor NOx emissions 

for requirements of this subsection according to the following specifications, as applicable: 

a. The owner or operator shall install and operate a continuous emissions monitoring system that 

measures the hourly average NOX emission rate. 

b. The emissions monitoring system shall consist of an NOX diluent continuous emissions 

analyzer and, as applicable, an O2 or CO2 diluent continuous emissions analyzer to correct all emissions 

data and heat rate values for the emissions unit to the same moisture and diluent gas basis, as required in 

subd. 6.b. 

c. The owner or operator shall calibrate, maintain and operate the emissions monitoring system 

according to the requirements of s. NR 439.09(9), the applicable operating requirements of 40 CFR 60.13, 

the performance specifications in 40 CFR part 60, Appendix B, incorporated by reference in s. NR 

484.04(21) and the quality assurance procedures of 40 CFR part 60, Appendix F, incorporated by 

reference in s. NR 484.04(21m). 

d. For an emissions unit subject to an NOX emission limit on a pound per million Btu basis, the 

emissions shall be determined using the F-factor method according to methods in Method 19 of 40 CFR 

part 60, Appendix A, incorporated by reference in s. NR 484.04(16m). 

e. Except for an emissions unit subject to subd. 1. or an emissions unit subject to an emission 

limitation in s. NR 428.22(1)(a)1. to 4., an owner or operator of an emissions unit may measure NOx
15

emissions for compliance determination purposes using continuous parametric monitoring methods 

meeting emissions monitoring specifications in 40 CFR part 75, Appendix E, incorporated by reference in 

s. NR 484.04(26m)(cm). 

3. 'Periodic emissions performance test.' Except as provided in subd. 1., the owner or operator of 

an emissions unit subject to s. NR 428.22(1)(e) to (i) shall conduct an initial performance test and a 

subsequent performance test every 2 years thereafter, according to the following requirements, as 

applicable, to determine the emissions unit's NOX emission rate for each fuel fired in the emissions unit. A 

performance test is not required for a fuel used only for startup or for a fuel constituting less than 1% of 

the unit’s annual fuel consumption. 

a. The emissions performance test shall be conducted according to one of the following methods 

as applicable: Method 7, 7A, 7B, 7C, 7D or 7E in 40 CFR part 60, Appendix A, incorporated by reference 

in s. NR 484.04(15m). 

b. Except for units specified in this subd. 3.c., the initial emissions performance test shall include 

a determination of the capacity load point of the unit’s maximum NOX emissions rate based on one 30 

minute test run at each capacity load point for which the unit is operated, other than for startup and 

shutdown, in the load ranges of 20 to 30%, 45 to 55%, 70 to 80% and 90 to 100%. 

c. The emissions performance tests for emissions units subject to s. NR 428.22(1)(g) or (h) shall 

be conducted within 10% of full load operation. 

d. The emissions performance test shall determine compliance based on the average of 3 60-

minute test runs performed at the capacity load specified in this subd. 3.b. or c. 

e. An additional performance test shall be conducted according to this subd. 3.b. or c. within 90 

days of completing an equipment modification or change in fuel which has the potential to increase the 

NOX emissions concentration or rate. 
16

4. 'Continuous monitoring for an output based standard.' In addition to applicable monitoring and 

measuring requirements under subd. 2., the owner or operator of an emissions unit subject to an output 

emission limitation in s. NR 428.22(1)(d) shall do the following: 

a. Install, maintain and operate monitoring equipment for measuring and recording the output on 

an hourly basis with plus or minus 5% accuracy, in units consistent with the applicable emission 

limitation. 

b. Calculate on an hourly basis, the output based emission rate as the hourly mass of NOX

emissions determined according to subd. 5. divided by the emissions unit's total output for that hour. 

5. 'Continuous monitoring of total heat input and mass emissions.' The owner or operator of an 

emissions unit required to measure total heat input or mass NOx emissions for requirements of subd. 4., 

sub. (2)(c) and s. NR 428.25(1)(b) or (c) shall perform the applicable measurements according to 

following: 

a. Except as allowed in subd. 5.d., install, calibrate, maintain and operate a volumetric flue gas 

flow monitoring system meeting specifications in subd. 2.c. The hourly heat input shall be determined 

using the F-factor and the as fired fuel heat content according to Method 19 of 40 CFR part 60, Appendix 

A , incorporated by reference in s. NR 484.04(16m). 

b. Unless specified in Method 19 of 40 CFR part 60, Appendix A, incorporated by reference in s. 

NR 484.04(16m), the heat content value for each fuel shall be based on a heat content analysis. 

c. The mass of NOX emissions shall be determined on an hourly basis by either multiplying the 

NOX concentration by the flue gas flow rate corrected for diluent gas and moisture or, by multiplying the 

monitored hourly average emission rate in mass per mmBtu by the total heat input as determined under 

subd. 5.a. or b. The calculations of mass emissions are to be performed according to conversion 

procedures in 40 CFR part 75, Appendix F, incorporated by reference in s. NR 484.04(26m)(d). 

d. For a liquid or gaseous fuel fired system, the total heat input and mass of NOx emissions may 

be determined using a fuel flow monitoring system capable of determining the hourly flow with plus or 
17

minus 5% accurancy and using continuous parametric monitoring as specified under subd. 8. The total 

heat input shall be calculated as the total fuel flow multiplied by the fuel heat content. 

6. 'General monitoring requirements.' Unless otherwise specified in this subsection, an owner or 

operator shall meet the following requirements: 

a. All certification tests or emissions performance tests shall be performed according to 

procedures of s. NR 439.07. 

b. The determination of emission rates, mass emissions and total heat input shall be calculated 

and corrected to the same basis for flue gas moisture and diluent gases according to Method 19 of 40 CFR 

part 60, Appendix A, incorporated by reference in s. NR 484.04 (16m), or 40 CFR part 75, Appendix F, 

incorporated by reference in s. NR 484.04(26m)(d). 

c. For emissions units with a common flue gas stack system, all sampling locations and 

apportionment of emissions to an individual emissions unit shall conform to applicable procedures and 

methods in 40 CFR part 75, Appendix F, incorporated by reference in s. NR 484.04(26m)(d). 

7. 'Malfunction and abatement.' An owner or operator of an emissions unit subject to the 

malfunction and abatement plan requirement of s. NR 439.11 shall include a malfunction plan for the 

emissions monitoring system and a monitoring and operating plan for continuing operation of the 

emissions unit in a manner consistent with meeting all applicable emission limitations during any period 

when the monitoring system malfunctions or is inoperable other than for scheduled maintenance. 

8. 'Alternate emissions monitoring.' An owner or operator of an emissions unit may request and 

monitor NOx emissions for compliance determination purposes using an equivalent alternative method to 

any requirement of this subsection with written approval of the department and the administrator. 

(2) COMPILATION OF EMISSIONS. An owner or operator shall compile the measured 

emissions data in measurement units consistent with the units of the applicable emission limitation 

according to the following applicable calculation and tabulation methods for purposes of demonstrating 

compliance: 
(a) Continuous emissions monitoring. When measuring emissions according to requirements in 

sub. (1)(b)1. or 2.: 

1. The average emission rate shall be the average of the hourly average emissions obtained from 

the continuous emissions monitoring system for the hours the emissions unit operated during the 

averaging period. The calculation is as follows: 

∑= ⎟

⎟

⎟

⎠

⎞

⎜

⎜

⎜

⎝

⎛

=

n

1j

A E jH, n

1 E Equation 2 

where: 

EA is the average emission rate for the compliance period in units consistent with units of the 

applicable emission limit 

EH, j is the hourly average emission rate for each hour, j, for which the emissions unit is operating 

during the compliance period in units consistent with units of the applicable emission limit 

n is the total number of hours the emissions unit operated during the compliance period 

2. The 30-day rolling period shall consist of the day of monitoring and the previous 29 

consecutive calendar days. A new 30-day rolling average emission rate (EA) shall be calculated and 

recorded at the end of each day. 

(b) Emissions performance testing. When measuring emissions according to performance testing 

requirements of sub. (1)(b)3., the 30-day rolling average emission rate or concentration shall be the 

emissions determined in sub. (1)(b)3.d. for the most recent performance test. 

(c) Multiple fuel-fired emissions units. When measuring emissions for an emissions unit firing 

multiple fuels, compliance shall be determined according to one of the following methods: 

1. The unit's emissions shall be monitored and compiled according to applicable methods in par. 

(a) or (b) for each individual fuel and compliance demonstrated with the emission limitation for each fuel. 

18
2. The unit's emissions and a multiple fuel emission limit shall be determined on a total heat input 

fuel weighted basis according to equation 3. A fuel representing less than 1% of the unit's annual fuel 

consumption on a heat input basis may be excluded in determining the multiple fuel emission limit. 

∑

∑

=

= = n

1 f

f

n

1 f

ff

HIWieghted

HI

HIE

 E Equation 3 

where: 

EHIWeighted is the heat input weighted multiple fuel emission rate or emission limitation for the 

compliance period in units consistent with the units of the emission limitation 

Ef is the emission rate or emission limit for fuel F during the compliance period in units 

consistent with the units of the emission limitation 

HIf is the total heat input for fuel f during the compliance period 

n is the number of different fuels used during the compliance period 

(d) Total heat input and mass emissions. When measuring hourly heat input or mass of NOX

emissions according to sub. (1)(b)5., the totals over a period of time shall be compiled according to the 

following procedures: 

1. The total hourly heat input shall be summed for the hours the emissions unit operated during 

the applicable period of time according to equation 4. 

∑=

=

n

1h

total HI HI h Equation 4 

where: 

HItotal is the total heat input by fuel over the period of time 

HIh is the heat input by fuel for hour h 

19
n is the number of hours over which the specific fuel was burned 

2. The total hourly mass of NOX emissions shall be summed for the hours the emissions unit 

operated during the applicable period of time according to equation 5. 

∑=

=

n

1h

x total Mass Mass NO h Equation 5 

where: 

NOX Masstotal is the total mass of NOX emissions over the period of time 

Massh is the mass of NOX emissions for hour h 

n is the number of hours the emissions unit is operating during the specified period of time 

NR 428.24 Recordkeeping and reporting. (1) EMISSION LIMITATIONS. The owner or 

operator of an emissions unit subject to an emission limitation in s. NR 428.22 shall meet the 

recordkeeping and reporting requirements of this subsection. 

(a) Recordkeeping. In addition to the recordkeeping requirements of ss. NR 439.04(1) and (2) and 

439.05, the owner or operator shall maintain records of all of the following: 

1. The applicable emission limit and calculated heat input weighted emission limit for an 

emissions unit demonstrating compliance for multiple fuels. 

2. The 30-day rolling average emission rate on a daily basis determined according to s. NR 

428.23. 

3. The total monthly heat input for each fuel or the emissions unit output, as applicable, in 

measurement units consistent with the units of the applicable emission limitation. 

4. The emissions unit's annual and ozone season capacity utilization in measurement units 

consistent with the units of the applicable emission limitation. 

20
21

5. For the emissions monitoring system required in s. NR 428.23(1)(b) on an annual and on an 

ozone season basis, records of performed maintenance, hours of malfunction and necessary repairs, and 

the percent of hours the monitoring system operated during the emissions unit's operating hours. 

(b) Reporting. In the reports to the department required under s. NR 439.03(1)(b), the owner or 

operator shall submit the following information: 

1. A certification of compliance with the applicable emission limitation in s. NR 428.22 or 

identification of the periods of non-compliance, with a quantification of the excess emission rate and the 

excess mass emissions. 

2. For each calendar month, the highest 30-day rolling average emission rate. The emissions data 

shall be reported in the measurement units of the applicable emission limitation. 

3. The emissions unit's annual and ozone season total operating hours, capacity utilization, and 

the percent operation of any required continuous emissions or combustion monitoring systems during the 

hours the emissions unit was operating. 

(2) GENERAL EXEMPTION UNIT. The owner or operator of an emissions unit claiming 

exemption under s. NR 428.21(1), shall record operational parameters necessary to demonstrate the unit’s 

qualification for the exemption status. 

(2m) RECIPROCATING ENGINES. The owner or operator of an emissions unit claiming 

exemption under s. NR 428.21(2m)(a)2., shall maintain a record of horsepower-hours of operation for 

each ozone season. Measurement of horsepower-hours may be determined using recorded data which can 

be directly related to actual horsepower-hours of operation of the engine including actual total operating 

hours, fuel consumption, or load and duration measurements. 

(3) LOW OPERATING UNIT. The owner or operator claiming a low operating unit exemption 

for an emissions unit under s. NR 428.21(2), shall maintain a record of the unit's applicable fuel heat input 

or production output, as applicable, the unit's total capacity utilization on an ozone season and on an 
22

annual basis for each calendar year and calculations demonstrating the unit’s qualification for the 

exemption. 

(4) OTHER REGULATED UNIT. The owner or operator claiming a regulated emissions unit 

exemption for an emissions unit under s. NR 428.21(3), shall maintain a record of all performance tests, 

calculations, assumptions and methods used to determine the emissions unit's potential emissions. 

NR 428.25 Alternative compliance methods and approaches. (1) EMISSIONS AVERAGING. 

The owner or operator of an emissions unit may demonstrate compliance with an NOX emission limitation 

in s. NR 428.22 by participating in an emissions rate averaging program according to the general 

provisions of par. (a) and either the specifications for facility wide averaging in par. (b) or for multifacility averaging in par. (c). 

(a) General provisions. 1. 'Participating units.' a. The participation of an emissions unit in an 

emissions averaging program shall be designated for a full calendar year. Individual emissions units may 

not be withdrawn from an averaging program, during a year, unless each emissions unit in the averaging 

program meets its applicable emission limit in s. NR 428.22. 

b. If an emissions unit at a facility participates in an averaging program, all similar units at the 

facility shall be included in the averaging program unless the unit is complying with an emission limit in 

s. NR 428.22 or is participating in another emissions averaging program under this subsection. Similar 

units at a facility are those which serve a similar process or purpose and which are described by the same 

general source category under s. NR 428.22 without regard to fuel type or unit size threshold. 

c. An emissions unit for which the department has approved an alternative emission limit or 

compliance schedule under sub. (3) may not participate in an emissions averaging program under this 

subsection. 

2. 'Monitoring requirement.' The owner or operator of an emissions unit participating in an 

emissions averaging program shall monitor all necessary NOX emissions, as applicable, according to 
23

requirements of s. NR 428.23(1)(b)1. or 2. The total heat input and NOX mass emissions shall be 

monitored and measured according to s. NR 428.23(1)(b)5. and compiled according to s. NR 

428.23(2)(d). 

3. 'New units'. An emissions unit which begins operation on or after the effective date of this 

section... [revisor insert date] may not participate in an emissions averaging program under this 

subsection. 

4. 'Emission reductions.' For purposes of this subsection, only emission reductions which go 

beyond all state and federal requirements are considered excess emission reductions. 

(b) Facility averaging. An owner or operator may average emissions from emissions units at one 

facility by complying with the following procedures for demonstrating compliance on an annual and on 

an ozone season basis with an aggregate NOX emission limit and mass emissions cap: 

1. 'Notification.' The owner or operator shall submit to the department a notification of an NOX

emissions averaging program by October 1 of the year prior to the emissions averaging year. The 

notification shall include the following information: 

a. The participating emissions units. 

b. The owner or operator of each emissions unit. 

c. For a unit subject to s. NR 428.22, the applicable emission limitation. 

d. For a participating emissions unit not subject to s. NR 428.22, the average emission rate by fuel 

type over the unit's normal operating range determined according to methods of s. NR 428.23(1)(b)3. The 

tested average emission rate may be adjusted based on a heat input weighted average of the emissions 

unit's annual percent operation at different load points in the previous calendar year. 

e. For averaging programs effective on or after January 1, 2013, for each emissions unit, the 

annual and ozone season heat input for 2000 to 2005, and the annual and ozone season average of the 3 

years of highest annual heat input for 2000 to 2005. 
f. For averaging programs effective on or after January 1, 2013, an annual and ozone season NOx

mass emissions cap in aggregate for the emissions units in the averaging program. The mass emissions 

caps shall be the summation of the products for each emissions unit of the emission limitation in subd. 

1.c. or the average emission rate in subd. 1.d. and the 3-year average annual or ozone season heat input. 

The mass emission cap shall be calculated as follows: 

i

n

1i

k

1j

MC ∑ ∑ HIE jj

= =

⎥

⎦

⎤ ⎢

⎣

⎡ = Equation 6 

 where: 

 MC is either the annual mass emissions cap or the ozone season mass emissions cap in tons of 

NOx for all units participating in the averaging program 

 Ej is the applicable emission limitation for fuel j submitted in subd. 1.c. or the average emission 

rate in subd. 1.d. 

 HIj is either the average annual or ozone season heat input for fuel j, submitted in subd. 1.e., for 

the 3 years of highest heat input from 2000 to 2005 

 k is the number of fuels fired by a unit either during the year or during the ozone season 

 n is the number of units participating in the averaging program 

2. 'Implementation.' The department shall review the proposed averaging program provided in the 

notification and unless the department, within 30 days of receiving the proposed averaging program, 

requests additional information or revisions to the program, the owner or operator shall comply with the 

submitted emissions averaging program. 

3. 'Compliance demonstration.' The owner or operator of emissions units participating in the 

averaging program shall submit a compliance report containing the following information by March 1 of 

the calendar year following the averaging program year: 

24
a. The annual and ozone season actual heat input by fuel type for each emissions unit in the 

averaging program. 

b. The annual and ozone season actual NOX mass emissions for each emissions unit. 

c. The annual and ozone season actual average NOX emission rate for each emissions unit 

calculated as follows: 

∑=

= n

1 j

j

x

avg

HI

Mass NO ER Equation 7 

where: 

ERavg is the annual or ozone season average emission rate for each emissions unit 

NOX Mass is the total NOX mass emissions for the averaging period 

HIj is the heat input for fuel type j for the averaging period 

n is the number of fuels fired during the averaging period 

d. The annual and ozone season actual NOX mass emissions and heat input in aggregate for all 

emissions units. 

e. The annual and ozone season actual aggregate NOX emission rate for all emissions units. This 

emission rate is the summation of the total mass of NOX emissions for all emissions units divided by the 

total heat input for all emissions units and is calculated as follows: 

∑

∑

=

= = n

1 u 

u

n

1 u 

x u

aggr

HI

Mass NO

 ER Equation 8 

where: 

ERaggr is the emission rate in aggregate for all emissions units on an annual or ozone season basis 

NOx Massu is the total NOx mass emissions for emissions unit u, for the averaging period 

25
HIu is the total heat input for each emissions unit u, for the averaging period 

n is the number of emissions units participating in averaging 

f. The annual and ozone season aggregate emission limitation for all emissions units. These 

emission limitations are the summation of the product of each unit's actual heat input and emission 

limitation by fuel type divided by the summation of the actual heat input for all emissions units. The 

aggregate emission limitations shall be calculated as follows: 

∑

∑∑

=

==

⎟

⎟

⎠

⎞

⎜

⎜

⎝

⎛

= n

1 u 

u

j

1 f

ff

n

1 u 

aggr

HI

ELHI

 EL Equation 9 

where: 

ELaggr is the aggregate emission limit for all emissions units on an annual or ozone season basis 

HIf is the heat input for fuel f, for unit u 

ELf is the emission limit for fuel f, for unit u 

HIu is the total heat input for emissions unit u, for the averaging period 

n is the number of emissions units participating in averaging 

j is the number of fuels for unit u 

g. Compliance on an annual and ozone season basis is demonstrated if the aggregate emission rate 

required in subd. 3.e. is less than the aggregate emission limit required in subd. 3.f., and the NOx mass 

emissions required in subd. 3.b. is less than the mass emissions cap required in subd. 1.f. 

4. 'Heat input conversion.' For an emissions unit subject to emission limitations expressed in units 

other than heat input, the emission limitation shall be converted to a heat input basis. All required 

calculations shall be on a common basis with necessary conversions performed according to the methods 

26
27

in 40 CFR part 60, Appendices A and B, incorporated by reference in s. NR 484.04(13) and (21). 

5. 'Mass emissions cap exceedance.' If the total NOx emissions from the emissions units in the 

averaging program exceed either the annual or ozone season emissions caps determined in subd. 1.f., the 

owner or operator shall achieve additional NOX reductions to compensate for the excess emissions within 

3 calendar years after the averaging year with the exceedance. 

(c) Multi-facility average. An owner or operator may average emissions from emissions units at 

multiple facilities by complying with the following procedures for demonstrating compliance on an 

annual and ozone season basis with an aggregate NOX emission limitation: 

1. 'Notification.' The owner or operator shall submit to the department a notification of an NOx 

emissions averaging program by October 1 of the year prior to the emissions averaging year. The 

notification shall include the following information:

a. The participating emissions units. 

b. The owner or operator of each emissions unit. 

c. The applicable emission limitation in s. NR 428.22 for each emissions unit. 

d. The projected heat input, capacity utilization, NOX emission rate and total NOX mass emissions 

for each emissions unit on an annual and ozone season basis. 

e. The projected heat input, capacity utilization, NOX emission rate and total NOX mass emissions 

in aggregate for all emissions units participating in the averaging program. 

2. 'Implementation.' The department shall review the proposed averaging program provided in the 

notification and unless the department, within 30 days of receiving the proposed averaging program, 

requests additional information or revisions to the program, the owner or operator shall comply with the 

submitted emissions averaging program. 

3. 'Public notice.' a. The owner or operator proposing to average emissions units at multiple 

facilities shall provide public notice 60 days prior to the calendar year of the averaging program in 

newspapers of general circulation for the areas of the emissions units. 
28

b. The public notice shall describe the proposed averaging program, the participating emissions 

units and how to obtain a copy of the averaging program information required in subd. 1. 

c. In addition to the information required in subd. 1., the averaging program information provided 

to the public upon request shall indicate whether any of the emissions units identified in the proposed 

averaging program participated in prior averaging programs under this subsection and whether that 

participation resulted in a violation of the emission limits. 

4. 'Compliance demonstration.' The owner or operator participating in an averaging program shall 

submit a compliance report containing the following information by March 1 of the calendar year 

following the averaging program year: 

a. The annual and ozone season actual heat input for each emissions unit. 

b. The annual and ozone season actual NOX mass emissions for each emissions unit. 

c. The annual and ozone season actual average NOX emission rate for each emissions unit 

calculated using Equation 7 in par. (b)3.c. 

d. The annual and ozone season actual NOX mass emissions and heat input in aggregate for all 

emissions units. 

e. The annual and ozone season aggregate NOX emission rate for all emissions units calculated 

using Equation 8 in par. (b)3.e. 

f. The annual and ozone season aggregate emission limitation for all emissions units. These 

emission limitations are the summation of the product of the each unit's actual heat input and emission 

limitation divided by the summed actual heat input for all emissions units less an averaging program 

environmental benefit factor. The aggregate emission limitations are calculated as follows: 
( EBF1

HI

ELHI

 EL n

1 u 

u

n

1 u 

uu

aggr = −×

∑

∑

=

= ) Equation 10 

where: 

ELaggr is the aggregate emission limit in aggregate for all emissions units on an annual or ozone 

season basis 

HIu is the heat input for each emissions unit, u, for the specified period of time 

ELu is the emission limit for each emissions unit, u. For emission limitations in units other than 

heat input, the emission limitations shall be converted to a heat input basis according to par. (b)4. 

EBF is the environmental benefit factor. For averaging programs effective on or after January 1, 

2013, the EBF is 10% for the annual emission limit and 10% for the ozone season emission limit. Prior to 

this date the EBF is 0%. 

g. A demonstration of compliance on an annual and ozone season basis consisting of the 

aggregate emission rates under subd. 4.e. compared to the aggregate emission limitations calculated in 

subd. 4.f. 

(d) Violations and penalties. 1. All emissions units participating in an emissions averaging 

program are considered out of compliance if emissions exceed any of the averaging program emission 

limitations on either an annual or ozone season basis. 

2. Each emissions unit participating in the averaging program shall be considered in violation for 

each day of non-compliance until corrective action is taken to achieve compliance. 

3. Except for those periods of time for which the department grants an electric or steam utility 

reliability waiver under s. NR 428.28 to the emissions units exceeding the applicable aggregate average 

emission limitation, the department shall require the owners or operators of the emissions units in the 

29
30

program to achieve reductions equivalent to the amount of the exceedance. The additional emission 

reductions shall be achieved within the subsequent 3 years on an annual or ozone season basis, consistent 

with the period of the exceedance. 

4. All owners or operators of emissions units considered out of compliance with an averaging 

program emission limitation are liable for each violation and subject to enforcement and penalty 

provisions under ss. 285.83 and 285.87, Stats. The owners or operators of the emissions units in the 

averaging plan shall evaluate the emissions and operating data for any period of non-compliance to 

determine which units are responsible for the non-compliance event. The information used in this 

evaluation shall be made available to the department within 30 days of the discovery of a non-compliance 

event. 

5. The parameters required in the notice under par. (c) 1.d. shall constitute annual and ozone 

season alternative compliance limits for each unit participating in a multi-facility averaging program 

under par. (c). If compliance is demonstrated under par. (c)4.g., all emissions units in the averaging 

program shall be deemed to be in compliance with the alternative compliance limits. 

(2) CAIR EMISSIONS UNITS. The owner or operator of an emissions unit which is subject to 

the emission reduction requirements of the clean air interstate rule (CAIR) under 40 CFR part 97 may 

demonstrate that the NOx emission reductions achieved by the emissions unit in complying with the 

CAIR requirements constitute compliance with the NOx RACT emission limitation requirements of this 

subchapter. 

(3) ALTERNATIVE RACT REQUIREMENT. (a) The owner or operator of an emissions unit 

may request that the department establish an alternative emission limitation or alternative compliance 

deadline to the requirements in s. NR 428.22 if the owner or operator demonstrates that it is economically 

or technically infeasible to meet the requirement. 

(b) The owner or operator of the emissions unit shall submit the request with the demonstration 

for an alternative RACT requirement by the later of May 1, 2008 or by May 1 following the calendar year 
31

in which an emissions unit first becomes subject to an emission limitation in s. NR 428.22. 

(c) Any request for an alternative RACT requirement made under this subsection shall be subject 

to the requirements and procedures of s. NR 436.05 and written approval of the administrator. 

NR 428.26 Utility reliability waiver. The owner or operator of an emissions unit used for 

purposes of electric or steam utility generation or natural gas utility transmission and subject to an 

emission limitation in s. NR 428.22 may request that the department grant a waiver from meeting the 

emission limitation for a specific period of time based on the following criteria and procedures: 

(1) The waiver request is due to the utility's need to maintain a supply of electricity, steam, or 

natural gas to non-interruptible customers. 

(2) A waiver request may only be based on an unavoidable or unforeseeable event including: 

(a) A major electric supply event affecting the utility. 

(b) A major fuel supply disruption affecting the utility. 

(c) A disruption in the operation of a generating unit or pollution control equipment. 

(3) The owner or operator of a utility shall submit a written request for a waiver that provides 

information sufficient to demonstrate to the department’s satisfaction that granting the waiver is 

warranted. The request shall include the following: 

(a) The duration of the conditions warranting the waiver. 

(b) The specific measures taken to mitigate emissions during the duration for which the waiver is 

requested. 

(c) The reasons why the utility was unable to achieve compliance with the emission requirement. 

(4) The department may grant a waiver under this section if, in consultation with the public 

service commission and written approval by the administrator, the department determines that the owner 

or operator's failure to meet a requirement under s. NR 428.22 is consistent with criteria of sub. (2). 

(5) Within 60 days after the receipt of a complete request, the department shall publish a public 
32

notice of the receipt of the waiver request and the department’s preliminary determination to approve, 

partially approve, or deny the request. The department shall provide an opportunity for public comments 

on the request and the department's preliminary determination. The department shall hold a public 

hearing on the request if a hearing is requested by a person affected by the waiver request. 

(6) Following the public comment period, the department shall notify the applicant in writing of 

the final determination to approve, conditionally approve or deny the waiver request. 

SECTION 5. NR 484.04(13) is amended to read: 

CFR Appendix Referenced Title 

Incorporated by 

Reference For 

NR 484.04 

(13) 40 CFR part 60 Appendix A Test Methods NR 400.02(131) 

NR 428.25(1)(b)4.

NR 439 

NR 460 to 469 

SECTION 6. NR 484.04(15m) and (16m) are created to read: 

CFR Appendix Referenced Title Incorporated by 

Reference For 

NR 484.04 

(15m) 40 CFR part 60 Appendix A, 

Method 7, 7A, 7B, 7C, 7D 

and 7E 

Determination of nitrogen oxide emissions 

from stationary sources 

NR 428.23(1)(b)3.a. 

(16m) 40 CFR part 60 Appendix A, 

Method 19 

Determination of sulfur dioxide removal 

efficiency and particulate, sulfur dioxide 

and nitrogen oxides emission rates 

NR 428.23(1)(b)2.d., 

5.a. and b. and 6.b. 

SECTION 7. NR 484.04(21m) is amended to read: 

CFR Appendix Referenced Title 

Incorporated by 

Reference For 

NR 484.04 

(21m) 40 CFR part 60 Appendix F Quality Assurance Procedures NR 428.23(1)(b)2.c.

NR 466.10(2) 
33

SECTION 8. NR 484.04(26m)(bm) is created to read: 

CFR Appendix Referenced Title 

Incorporated by 

Reference For 

NR 484.04 

(26m)(bm) 40 CFR part 75 Appendix E Optional NOx Emissions Estimation 

Protocol for Gas-Fired Peaking Units and 

Oil-Fired Peaking Units 

NR 428.23(1)(b)2.e. 

 

SECTION 9. NR 484.04(26m)(d) and (27) are amended to read: 

CFR Appendix Referenced Title 

Incorporated by 

Reference For 

NR 484.04 

(26m)(d) 40 CFR part 75 Appendix F Conversion Procedures NR 428.23(1)(b)5.c. and 

6.b. and c.

NR 446.04(3) 

NR 446.09(1)(a) 

(27) 40 CFR part 75 Appendices A 

to I 

NR 428 

NR 439 

NR 428.23(1)(b)1.

SECTION 10. EFFECTIVE DATE. This rule shall take effect on the first day of the month following 

publication in the Wisconsin administrative register as provided in s. 227.22 (2) (intro.), Stats. 
34

SECTION 11. BOARD ADOPTION. This rule was approved and adopted by the State of Wisconsin 

Natural Resources Board on on April 25, 2006 and May 23, 2007. 

Dated at Madison, Wisconsin _________________________________. 

STATE OF WISCONSIN 

DEPARTMENT OF NATURAL RESOURCES 

By__________________________________ 

 Scott Hassett, Secretary 

(SEAL)
Attachment 3 

Public Hearing Certification 



Reasonable accommodation, including the provision of informational material in an alternative format, will be

provided for qualified individuals with disabilities upon request. http://www.madison.com

03

•fore

m.

BEFORE THE DEPARTMENT OF NATURAL

RESOURCES

NOTICE OF PUBLIC HEARING - AM-04-06

NOTICE IS HEREBY GIVEN that pursuant to ss.

227.11(2)(a), 227.14 (1m) and 285.11(1) and (6),

Stats., interpreting s. 285.11(6), Stats., the

Department of Natural Resources will hold a

public hearing on the creation of ch, NR 433

and s. NR 484.04(11 m) Wis. Adm. Code, relating to the best available retrofit technology

(BART) requirements for visibility protection.

The Department is proposing a rule to address

BART related State Implementation Plan (SIP)

revisions which are required by the federal

regional haze rule. The Federal regulations

require all states, including Wisconsin, to

develop State Implementation Plans to address

visibility impairment in mandatory Class I

Federal Areas (Class I Areas) by December

2007. One of the provisions o( the federal regulations is the application of BART requirements to major stationary sources that meet

certain criteria relating to amount and type of

emissions, installation date and source category. The proposed rule requires that the affected facilities perform an engineering analysis for

the BART determination which shall be based

on an analysis of the best systems of continuous emission control technology available and

associated emission reductions achievable (or

each source subject to BART, This analysis is

to be performed on a source-by-source basis

taking into account the criteria provided by the

federal regulation. The net effect of the proposed rule would be to examine potential emission control technologies for SO2, NOx and

particulate matter from approximately 10

power plants and 4 pulp and paper mills that

meet the criteria in the federal regulations and

to determine BART for those emission sources.

NOTICE IS HEREBY FURTHER GIVEN that pursuant to s. 227.114, Stats., it is not anticipated

that the proposed rule will have a direct economic impact on small businesses. The

requirements to emission units owned and

operated by electric utilities and paper manufacturers may increase the cost of their products and therefore may have an indirect impact

on small businesses through higher electricity

costs or the costs of paper products.

NOTICE iS HEREBY FURTHER GIVEN that the

Department has made a preliminary determination that this action does not involve significant

adverse environmental effects and does not

need an environmental analysis under ch. NR

150, Wis. Adm, Code. However, based on the

comments received, the Department may prepare an environmental analysis before proceeding with the proposal. This environ rnenta I

review document would summarize tha

Department's consideration of the impacts of

the proposal and reasonable alternatives.

NOTICE IS HEREBY FURTHER GIVEN that the

hearings will be held on:

Tuesday, March 13,2007 Marathon County

Public Library, Wausau Room, 300 N. First

Street, Wausau, Wl at 1:00 p.m.

Thursday, March 15, 2007 Roo m

140-141, DNR Southeast Region Headquarters,

2300 North Dr. Martin Luther King Jr. Dr.,

Milwaukee, Wl at 1:00 p.m.

NOTICE IS HEREBY FURTHER GIVEN that pursuant to the Americans with Disabilities Act,

reasonable accommodations, including the

provision of informational material in an alternative format, will be provided for qualified

individuals with disabilities upon request.

Please call Robert Eckdale at (608) 266-2856 or

by e-mail to Robert.Eckdale@wisconsin.gov

with specific information on your request at

least 10 days before the date of the scheduled

hearing.

The proposed rule and supporting documents,

including the fiscal estimate may be reviewed

and downloaded and comments electronically

submitted at the following Internet site:

http://adminrules.wisconsin.gov. (Search this

Web site using the Natural Resources Board

Order No, AM-C4-Q6.) Written comments on

the proposed rule may be submitted via U.S.

mail to Mr. Farrokh Ghoreishi, Bureau of Air

Management, P.O. Box 7921, Madison, Wl

63707 or by e-mail to Mr. Ghoreishi at

Farrokh.Qhoreishi@wisconsin.gov. Comments

may be submitted until March 19, 2007.

Written comments whether submitted electronically or by U.S. mail will have the same

weight and effect as oral statements presented

at the public hearings, if you do not have

Internet access, a personal copy of the proposed rule and supporting documents, including the fiscal estimate may be obtained from

Robert Eckdale, Bureau of Air Management,

P.O. Box 7921, Madison, Wl 53707 or by calling

(608) 266-2856.

Dated at Madison, Wisconsin February 2, 2007.

STATE OF WISCONSIN

DEPARTMENT OF NATURAL RESOURCES

By; Scott Hsssett, Secretary

PUB. WSJ: February 9, 2007

(#6711305) WNAXLP

BEFORE THE DEPARTMENT OF NATURAL

RESOURCES

NOTICE OF PUBLIC HEARING AM-17-05

NOTICE IS HEREBY GIVEN that pursuant to ss.

227.11(2)(a), 227.14 (1m) and 285.11(1) and (6),

Stats,, interpreting s. 285.11(6), Stats., the

Department of Natural Resources will hold a

public hearing on the creation of ss. NR 423.20

to 428.28, Wis. Adm. Code, and amendments

io ss. NR 423.04(2)(h} and 428.05(3)(e) and

484,04, Wis. Adm. Code, relating to the establishment of rules for reasonable available control technology (PACT) emission requirements

for major sources of NOx emissions in the

southeast 8-hour ozone nonatttainment counties of Kenosha, Racine, Milwaukee, Waukesha,

Washington, Qzaukee, and Sheboygan.

In June 2004, the US EPA designated the

Wisconsin counties addressed by the rule as

"moderate" nonattamrnent areas for the 8-hour

ozone ambient air quality standard. The designation triggered federal Clean Air Act requirements for implementation of "reasonably available control technology" (RACT) for major stationary sources of NOx and volatile organic

compounds (VOC) by May 1, 2009. The

Department is proposing this rule package to

meet the RACT requirement for major sources

of NOx emissions. The Department previously

adopted RACT rules for VOC sources to

address the previous 1-hour ozone standard.

The proposed rule affects facilities with the

potential to emit 100 tons or more of NOx per

year in the moderate ozone nonattainment

areas. However, the emission requirements

apply to individual emission units, such as a

boiler or furnace, at the affected facilities. It is

possible that an emission'unit contributing to a

major source's potential to emit may not be

subject to a RACT requirement. Likewise, an

emission unit identified by a RACT source category, but at a facility with a potential to emit

less than 100 tons per year, will not be subject

to a RACT requirement.

The emission requirements proposed in the

rule consist of NOx emission limitations and

combustion tuning requirements applicable on

a year-round basis. The emission limitations

are established by source categories with an

emission unit size threshold based on available

control technologies and cost-effectiveness.

Combustion tuning requirements apply to the

emission units subject to emission limitations,

as well as to smaller emission units. The emission limit and combustion tuning requirements

are established based on a cost-effectiveness

of $2,500 or less per ton of controlled NOx

emissions. The rule contains exemptions from

both RACT requirements for certain types of

emission units demonstrating low operating

levels during the ozone season. An additional

exemption recognizes that the NOx emissions

of certain smaller emission units are already

well controlled under existing ch. NR 428 provisions and no further action is cost-effective in

meeting a NOx RACT emission limit.

The proposed rula contains several provisions

to address technical issues and provide compliance flexibility. The rule proposes a specific

phased schedule applicable to large coal boilers owned or operated by electric utilities in

order to maintain electric reliability, with final

compliance by May 1, 2013. For compliance

flexibility, the rule allows facility-wide and

multi-facility emission averaging between

emission units at the affected facilities. An

affected entity may also request an alternate

RACT requirement for an emission unit based

on a technical and economic demonstration.

NOTICE IS HEREBY FURTHER GIVEN that pursuant to s. 227,114, Stats., it is not anticipated

that the proposed rule will have a direct economic impact on small businesses. The proposed RACT rules impose no reporting, compliance or performance standards on small

businesses. The requirements to emission

units owned and operated by electric utilities

may increase the cost of electricity and therefore may have an indirect impact on small businesses through higher electricity costs.

NOTICE IS HEREBY FURTHER GIVEN that the

Department has made a preliminary determination that this action does not involve significant

adverse environmental effects and does not

need an environmental analysis under ch. NR

150, Wis. Adm. Code, However, based on the

comments received, the Department may prepare an environmental analysis before proceeding with the proposal. This environmental

review document would summarize the

Department's consideration of the impacts of

the proposal and reasonable alternatives.

NOTICE IS HEREBY FURTHER GIVEN that the

hearing will be held on:

Thursday, March 15, 2007 Roo m

140-141, DNR Southeast Region Headquarters,

2300 North Dr. Martin Lulher King Jr. Dr.,

Milwaukee, Wl at 2:00 p.m.

NOTICE IS HEREBY FURTHER GIVEN that pursuant to the Americans with Disabilities Act,

reasonable accommodations, including tha

provision of informational material in an alternative format, will be provided for qualified

individuals with disabilities upon request.

Please call Robert Eckdale at (308) 266-2856 or

by e-rnail to Robert.Eckdale ©Wisconsin.gov.

with specific information on your request at

least 10 days before the date of the scheduled

hearing.

The proposed rule and supporting documents,

including the fiscal estimate may be reviewed

and downloaded and comments electronically

submitted at the following internet site:

http://adminrules.wisconsin.gov. (Search this

Web site using the Natural Resources Board

Order No. AM-17-05.) Written comments on

the proposed rule may be submitted via U.S.

mail to Mr. Tom Karman, Bureau of Air

Management, P.O. Box 7921, Madison, Wl

53707 or by e-mail to Mr. Karman at

Thomas.Karman@wisconsin.gov. Comments

may be submitted until March 19, 2007.

Written comments whether submitted electronically or by U.S. mail will have the same

weight and effect as oral statements presented

at the public hearings. If you do not have

Internet access, a personal copy of the proposed rule and supporting documents, including the fiscal estimate may be obtained from

Robert Eckdale, Bureau of Air Management,

P.O. Box 7921, Madison, Wl 53707 or by calling

(60S) 266-2856,

Dated at Madison, Wisconsin February 2, 2007

STATE OF WISCONSIN

DEPARTMENT OF NATURAL RESOURCES

By: Scott Hassett, Secretary

PUB. WSJ: February 9, 2007

(#6711310) WNAXLP

Notice is hereby given that a meeting of the

Executive Committee of the Law Enforcement

Standards Board of the Wisconsin Department

of Justice will be held Tuesday, February 13,

2007 at 10:00 a.m., at the Risser Justice Center,

17 West Main Street, Room 884, Madison, Wl

to conduct the following business:

1) Introductions

2) Requests to Waive Basic Law Enforcement

Training, Basic Jail Officer Training, Contingency Officer Training, Instructor Development

Course and College Credits

3) Requests to Certify/Recertify Law Enforcement Officers, Jail Officers, Secure Detention

Officers and Instructors

4) Requests to Certify Academies (Northeast

Wisconsin Technical College and Western

Technical College)

5) Amendment to Minutes of June 6, 2006 Law

Enforcement Standards Board Regarding

Lapsed Instructor Status

6) Instructor Certification Requirements—3-Year

Full-Time v. 3-Year Part-Time Employment

7) Certification Track Program

8) Standardized Field Sobriety Testing Memo

of Understanding Update

9) Standardized Field Sobriety Testing Master

Instructor Trainer Course and Instructor Course

Certification

10) Principles of Subject Control Instructor

Update

11) Cost Analysis for Basic Jail Training

12) Defensive and Arrest Tactics & Crisis Intervention-Motion Process

13) March Board Elections of Chairperson/

Vice-Chairperson

14) Proposed Schedule for Quarterly Executive

Committee Meetings

15) Adjournment

For further information, contact the Training

and Standards Bureau, Wisconsin Department

of Justice .at 6p8/266-8SQO: TTY Users 1-800-

947-3529

i - PUB. WSJ: February 9,2007.

J l#«aU8PL ..i

L
Attachment 4 

SIP Checklist 
2

EPA Region V 

Wisconsin SIP Submittal 

Completeness Review

Submittal Letter 

1. Signed by Governor’s Designee? Yes _X_ No ___ 

2. Date of Submittal _June 12, 2007__ 

3. WDNR Person in charge of SIP submittal. 

Name _Ralph Patterson Telephone _(608)267-7546 

 FAX Number _(608)267-0560____ 

E-MAIL Address___Ralph.Patterson@dnr.state.wi.us 

4. WDNR Technical Person in charge of answering questions on SIP Submittal 

Name _Tom Karman_ Telephone _(608) 264-8856 

FAX Number _(608)267-0560____ 

E-MAIL Address___Thomas.Karman@dnr.state.wi.us 

Incorporation Into Wisconsin Administrative Code

5. Is evidence that the State incorporated the revision into the Wisconsin Administrative Code 

supplied in this SIP package? 

 Yes __

No_X_ The attached rule language has been adopted but has not been published as yet. A copy 

of the rule published in the Wisconsin Code will be forwarded to EPA. 

6. The effective date of the regulation is or was _Upon Publication. Publication is approximately 

three months after final adoption by the legislative bodies which occurred in May, 2007 

7. Are test methods/rules incorporated by reference correctly? (Has approval been obtained from the 

state Attorney General 

 Yes_X_ 

 No_______ 

 Not applicable _______ 

 For No and Not applicable explain answer. 

8. Has WDNR provided evidence that it has necessary legal authority under State law to adopt and 

implement the revision? 

 Yes __X___ 

 No _______ 

 Additional Explanation (if necessary). 

9. Did the State include a copy of the actual regulation or document for USEPA review? 
3

 Yes _X___ 

 No_____ 

 Additional Explanation (if necessary). 

10. Did the State provide evidence that it followed all of the requirements of its Administrative 

Procedures Act (ch. 227, Wis. Stats., Administrative Procedure and Review) in conducting and 

completing adoption/issuance of the revision? 

 Yes__X__

 No______ 

 Additional Explanation (if necessary) 

11. Did the State include evidence that Public Notice was given of the revision, including date of 

publication? 

 Yes_X__ 

 No ____ 

 Additional Explanation (if necessary) 

12. Did the State provide a copy of the certification that public hearings were held in accordance wit 

the information provided in the public notice (copy of notarized Class I paper proof). 

 Yes_X__ 

 No___ 

 Additional Explanation (if necessary). 

13. Does the submittal contain a compilation of public comments and the State’s response? 

 Yes_X___ 

 No____ 

 Additional Explanation (if necessary). 

Technical Issues 

14. Name the all the regulated pollutants affected by the revision? _Emissions of nitrogen oxide__ 

15. Does the submittal identify the designation, status of the attainment plan and attainment date for 

the area(s) 

 Yes__X__ 

 No_____ 

 Additional Explanation (if necessary) 

16. Does the submittal identify the location and types of affected sources? 

 Yes__X___ 

 No_____ 
4

 Additional Explanation (if necessary) 
5

17. Does the submittal quantify the changes in SIP-allowable emissions and estimate or quantify the 

changes in actual emissions from affected sources? 

 Yes_X__ 

 No____ 

 Additional explanation (if necessary) 

18. Has the State demonstrated that the NAAQS/PSD Increment/RFP demonstration/visibility will be 

protected if the revision is approved and implemented? 

 Yes_X___ 

 No____ 

Additional explanation (if necessary) - These rules implement additional emission reductions 

which contributes to and protects emission levels associated with fulfilling NAAQS/PSD 

Increment/RFP demonstration/visibility requirements. 

19. Has the State provided modeling information to support the revision. 

 Yes___ 

 No____ 

 Unnecessary__X__ 

20. Has the State provided evidence that emission limitations are based on continuous emission 

reduction technology? 

 Yes_X___ 

 No____ 

 Additional explanation (if necessary). See technical support analysis provided in the attached 

Green Sheet background memo's to the DNR Board. 

21. Has the State provided evidence that the revision contains emission limitations, work practice 

standards and record keeping/reporting requirements where necessary, to ensure emission levels? 

 Yes_X__ 

 No____ 

 Additional explanation (if necessary). 

22. Does the submittal contain enforcement/compliance strategies including how compliance will be 

determined in practice, and at what frequency? 

 Yes_X__ 

 No___ 

 Additional explanation (if necessary). 
6

STATE APPROVABILITY CHECKLISTENFORCEABILITY 

USEPA USE ONLY 

SIP Package Number ___________ 

Date Received by USEPA ________________ 

Date Due_____________________________ 

State: WISCONSIN 
7

WDNR Information 

Subject Matter: Submittal for SIP approval of: 

1) Adopted NOx RACT rules for major sources in the moderate nonattainment areas 

2) Non-substantive changes to units of emission limits for reciprocating engines under existing 

NR 428.04 and 05 NOx control requirements. 

Applicability 

USEPA Question USEPA Requirement State Response 

What sources are being regulated? CAA NOx RACT Major sources in the moderate 

nonattainment areas of Wisconsin. Major 

sources are facilities with a potential to emit 

of 100 tons per year or more. 

What are criteria for exemption? - Low operating levels: Exemptionsar are 

consistent with cost-effectiveness of RACT 

control. The state cost-effectiveness is up to 

$2,500 per ton from an uncontrolled basis. 

- Units meeting existing NOx emission 

limits with potential emissions < 75 tons per 

year. Marginal cost of control increases 

significantly for well controlled smaller 

units. 

- Specific unit applications consistent with 

low operating levels. 

Is calculation procedure for 

exemption clearly specified? 

Supply example calculation or clear 

explanation of how to determine 

exemption (line by line, etc.) 

The exemptions have record keeping 

requirements which must clearly 

demonstrate all necessary measurements 

and calculations for exemption. 

Is emission inventory listed in the 

background document of the 

attainment demonstration? 

Inventory including allowable and 

actual emissions in source category 

should be included, for enforcement 

purposes and independent of any 

Clean Air Act requirements, in the 

attainment demonstration if such 

data is necessary for determining 

baselines in regulations. 

The sources listed in the inventory as 

potentially affected are all units in the 

nonattainment area falling in the RACT 

emission limit categories. 

Is the averaging time(s) used in 

the rule different from that of the 

ambient standard? 

The averaging time in the rule must 

be consistent with protecting the 

ambient standard in question. 

Normally, it should be equal to or 

shorter than the time associated with 

the standard. Longer term 

averaging is available only in 

limited instances provided that the 

The averaging time is consistent with the 

Phase II implementation rule and EPA 

guidance. 
8

ambient standard is not 

compromised. 

What are the units of compliance 

(lbs VOC per gallon of solids 

applied less water, grains per 

standard cubic foot?) 

Clearly stated in the rule. Units for emission limitation are different 

for each source category. 

Is bubbling or averaging of any 

type allowed? If yes, state 

criteria. Could a USEPA 

inspector independently determine 

if the criteria were met?? Does 

USEPA have to approve each 

case? 

Explicit description of how 

averaging, bubbling, or equivalency 

is to be determined. VOC 

equivalency must be on a “solids 

applied” basis. Any method must 

be independently reproducible. 

Provision must be explicit as to 

whether USEPA case-by-case 

approval is required. If provision 

intended to be “generic” then 

USEPA bubble policy must be met. 

Yes, averaging is allowed. The averaging 

programs have clear criteria specified for 

participating in an averaging program. EPA 

will be approving the criteria for 

participation. Emissions monitoring and 

compliance submittals are required specific 

to the averaging programs. 

If there is a redesignation, will 

this change the emission 

limitations? If yes, which ones 

and how? 

Regulation may not automatically 

allow for self nullification upon 

redesignation of area to attainment. 

New maintenance demonstration 

required to order to drop regulation. 

No, These RACT limitations are to fulfill a 

separate CAA requirement and independent 

of demonstrating attainment. 

Compliance Dates 

USEPA Question USEPA Requirement State Response 

What is the compliance date? The compliance date must not 

be later than the approved or 

about to be approved date of 

attainment unless emission 

reductions are not necessary for 

attainment. In some cases, it 

will be necessary for the 

regulation to specify dates in 

compliance schedules that are 

required to be submitted by 

source to state. 

Emission limitations are applicable May 1, 

2009. EGU coal fired boilers are subject to 

a phased compliance schedule of emission 

limits for May 1, 2009 and May 1, 2013. 

What is the attainment date? Clearly defined. May 1, 2009 

Specificity of conduct 

USEPA Question USEPA Requirement State Response 

What test method is required? Test method must be explicitly 

stated. 

• A.R. and CAIR subject EGU's – 40 CFR 

Part 75 CEMs. 

• Non-EGU units – As specified by source 

category either: 40 CFR Part 60 

monitoring or emissions stack testing 

every two years according to Method 7. 

Any non-EGU unit can utilize 

parametric monitoring according to 40 
9

CFR Part 75 appendix E. 

What is the averaging time in the 

compliance test method? 

Averaging time and application 

of limit must be explicit. 

• CEMs monitored units – 30 day rolling 

average. 

• Stack tested units – average of 3 hourly 

runs. 

Is a compliance calculation or 

evaluation required? (i.e., daily 

weighted average for VOC). 

Clearly defined. Yes, calculations and tabulation of 

emissions for the different monitoring 

methods and for specific cases of firing 

multiple fuels are specified in the rule. 

If a compliance calculation is 

necessary, list the formula, period of 

compliance, and/or evaluation 

method. 

Formula must be explicit. Specific calculations are specified in the 

rule under s. NR 428.23. 

Incorporation by reference

USEPA Question USEPA Requirement State Response 

What is the state authority for 

rulemaking. 

Clearly stated. s. 227.11(2)(a) and 285.11(1) and (6), Stats. 

Are methods/rules incorporated by 

reference in the right manner? 

Clearly stated. The rule incorporation by references were 

reviewed by the state legislative clearinghouse.

Record keeping

USEPA Question USEPA Requirement State Response 

What records are required to 

determine compliance? 

Clearly stated. • Applicable emission limit 

• 30 day rolling emission rate for CEMs 

monitored units or stack test 

determination every two years. 

• Records of monitoring equipment 

operation and maintenance. 

In what form or units (lbs/gal, gr/dscf, 

etc.) must the records be kept? On 

what time basis (instantaneously, 

hourly daily)? 

Records to be kept must be 

consistent with units of 

compliance in the performance 

requirements, including the 

applicable time period . 

Units of the emission limitations are 

specified for each source category. The 

records to be kept include: 

• Applicable emission limit 

• 30 day rolling emission rate for CEMs 

monitored units or stack test 

determination every two years. 

• Unit's heat input or output on a monthly 

basis. 

• Unit's capacity utilization on an ozone 

season and annual basis. 

Records of monitoring equipment operation 

and maintenance.

Does the rule affirmatively require 

the records be kept? 

There must be clearly defined 

and distinguishable from what 

constitutes a violation. 

Yes, recordkeeping requirements are 

specified under s. NR 428.24 

Exemptions
10

USEPA Question USEPA Requirement State Response 

List any exemptions allowed. Must be clearly defined and 

distinguishable from what 

constitutes a violation. 

• Exemptions are specified under s. NR 

428.21 and include: 

1) General exemptions – a list of defined 

units by application type. 

2) Low operating units – establishes a 

threshold of operation during the ozone 

season for being subject to the emission 

limits. 

3) Reciprocating engines – Certain EPA 

certified engines which are meeting the 

emission limit or which are well control and 

costly to implement additional control. The 

engines are certified to emit at these levels 

of its life and therefore no additional 

monitoring is required. 

4) Other regulated units – Units that are 

subject to a NOx emission limit under 

current NR 428 requirements which limits 

emissions to less than 75 tons per year. 

• The units qualifying for exemption 

(except EPA certified engines) have 

record keeping requirements under NR 

428.24 to clearly establish what 

constitutes a violation. 

Is the criteria for application clear? Clearly stated. Yes, see previous response. 

Malfunction Provisions

USEPA Question USEPA Requirement State Response 

Are there any malfunction provisions 

in the rule? 

Rule must specify what 

exceedances may be excused, 

how the standard is to be 

applied, and who makes the 

determination. 

• Malfunction provisions are not specific 

in the RACT rules. However all state air 

rules are subject to a requirement of 

malfunction and abatement plans under 

s. NR 439.11 applicable to units that 

may emit 3 lbs per hour or 15 lbs per 

day. 

• The RACT rule contains a Utility 

Waiver provision which allows 

evaluation of compliance related to 

uncontrollable or foreseeable events. 

The waiver may grant temporary relief 

from the emission limitation and is 

subject to public comment and EPA 

approval.