FINAL REPORT 

Small Business Advocacy Review Panel on 

EPA’s Rulemaking for 

Hazardous Air Pollutants from Coal- and Oil-Fired 

Electric Utility Steam Generating Units 

February 16, 2011
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Table of Contents 

1. Introduction ..........................................................................................................................4

2. Background ..........................................................................................................................5

2.1 Background and Regulatory History ................................................................................5 

2.2 Description of the Rule and its Scope ..............................................................................6 

2.3 Related Federal Rules .......................................................................................................7 

3. Overview of Proposal Under Consideration......................................................................9

3.1 Potential Requirements of the Proposal ...........................................................................9 

3.2 Options Likely to be Proposed .......................................................................................11 

4. Applicable Small Entity Definitions .................................................................................14

5. Small Entities That may be Subject to the Proposed Regulation ..................................15

6. Summary of Small Entity Outreach .................................................................................16

6.1 Small Entity Outreach ....................................................................................................16 

6.2 Summary of Panel’s Outreach Meeting with Small Entity Representatives ..................16 

7. List of Small Entity Representatives ................................................................................17

8. Summary of Input from Small Entity Representatives ..................................................18

8.1 Number and Types of Entities Affected .........................................................................18 

8.2 MACT Floors and Variability ........................................................................................19 

8.3 Monitoring, Reporting, and Recordkeeping ...................................................................21 

8.4 Subcategorization ...........................................................................................................22 

8.5 Area Source Standards ...................................................................................................23

8.6 Work Practice Standards ................................................................................................23 

8.7 Health Based Emission Limits .......................................................................................23 

8.8 Related Federal Rules .....................................................................................................24 

8.9 Potential Adverse Economic Impacts ............................................................................24 

8.10 Concerns with the Small Business Advocacy Review Process ....................................26 

9. Panel Findings and Discussion ..........................................................................................27

9.1 Number and Types of Entities Affected .........................................................................27 

9.2 MACT Floors and Variability ........................................................................................28 

9.3 Monitoring, Reporting, and Recordkeeping ...................................................................31 
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9.4 Subcategorization ...........................................................................................................32 

9.5 Area Source Standards ...................................................................................................33

9.6 Work Practice Standards ................................................................................................34 

9.7 Health Based Emission Limits .......................................................................................34 

9.8 Related Federal Rules .....................................................................................................35 

9.9 Potential Adverse Economic Impacts ............................................................................36 

9.10 Concerns with the Small Business Advocacy Review Process ....................................37 

Appendices ..............................................................................................................................39

Appendix A: List of Materials EPA Shared with SERs ......................................................39 

Appendix B: Questions for SERs ........................................................................................40 

Appendix C: Written Comments Received from SERs ......................................................43 
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Final Report for the Small Business Advocacy Review Panel 

on EPA’s Planned Proposal of National Emission Standards for Hazardous Air 

Pollutants from Coal- and Oil-Fired Electric Utility Steam Generating Units 

1. INTRODUCTION 

This report is presented to the Small Business Advocacy Review Panel (SBAR Panel 

or Panel) convened for the planned proposed rulemaking on the National Emission Standards 

for Hazardous Air Pollutants (NESHAP) for Coal- and Oil-Fired Electric Utility Steam 

Generating Units (Utility NESHAP) currently being developed by the U.S. Environmental 

Protection Agency (EPA). Under section 609(b) of the Regulatory Flexibility Act (RFA) as 

amended by the Small Business Regulatory Enforcement Fairness Act of 1996 (SBREFA), a 

Panel is required to be convened prior to publication of the initial regulatory flexibility 

analysis (IRFA) that an agency may be required to prepare under the RFA. In addition to 

EPA’s Small Business Advocacy Chairperson, the Panel will consist of the Director of 

EPA’s Sector Policies and Programs Division within the Office of Air Quality Planning and 

Standards, the Administrator of the Office of Information and Regulatory Affairs within the 

Office of Management and Budget, and the Chief Counsel for Advocacy of the Small 

Business Administration. 

This report includes the following: 

• background information on the proposed rule being developed; 

• information on the types of small entities that would be subject to the proposed 

rule; 

• a description of efforts made to obtain the advice and recommendations of 

representatives of those small entities; and 

• a summary of the comments that have been received to date from those 

representatives. 

RFA section 609(b) directs the Panel to report on the comments of small entity 

representatives and make findings on issues related to identified elements of IRFA under 

RFA section 603. Those elements of an IRFA are: 

• a description of and, where feasible, an estimate of the number of small entities to 

which the proposed rule will apply; 

• projected reporting, record keeping, and other compliance requirements of the 

proposed rule, including an estimate of the classes of small entities which will be 

subject to the requirements and the type of professional skills necessary for 

preparation of the report or record; 
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• an identification, to the extent practicable, of all other relevant Federal rules 

which may duplicate, overlap, or conflict with the proposed rule; and 

• any impacts on small entities and any significant alternatives to the proposed rule 

which accomplish the stated objectives of applicable statutes and which minimize 

any significant economic impact of the proposed rule on small entities. 

Once completed, the Panel report is provided to the agency issuing the planned 

proposed rule and included in the rulemaking record. In light of the Panel report, and where 

appropriate, the agency is to make changes to the draft proposed rule, the IRFA for the 

proposed rule, or the decision on whether an IRFA is required. 

It is important to note that the Panel’s findings and discussion will be based on the 

information available at the time the final Panel report is drafted. EPA will continue to 

conduct analyses relevant to the proposed rule, and additional information may be developed 

or obtained during the remainder of the rule development process. The Panel makes its 

report at a preliminary stage of rule development and its report should be considered in that 

light. At the same time, the report provides the Panel and the Agency with an opportunity to 

identify and explore potential ways of shaping the proposed rule to minimize the burden of 

the rule on small entities while achieving the rule’s purposes. 

Any options identified by the Panel for reducing the rule’s regulatory impact on small 

entities may require further analysis and/or data collection to ensure that the options are 

practicable, enforceable, environmentally sound, and consistent with the Clean Air Act 

(CAA). 

2. BACKGROUND 

2.1 Background and Regulatory History 

In December 2000, EPA made a finding that it was appropriate and necessary to 

regulate coal- and oil-fired electric utility steam generating units (EGUs) under CAA section 

112 and listed EGUs pursuant to CAA section 112(c). On March 29, 2005 (70 FR 15994), 

EPA published a final rule (Section 112(n) Revision Rule) that removed EGUs from the list 

of sources for which regulation under CAA section 112 was required. That rule was 

published in conjunction with a rule requiring reductions in emissions of mercury from 

electric utility steam generating units pursuant to section 111 of the CAA (Clean Air Mercury 

Rule (CAMR), May 18, 2005, 70 FR 28606). The Section 112(n) Revision Rule was vacated 

on February 8, 2008, by the U.S. Court of Appeals for the District of Columbia Circuit. As a 

result of that vacatur, CAMR was also vacated and EGUs remain on the list of sources that 

must be regulated under CAA section 112. 

In the December 2000 regulatory determination, EPA made a finding that it was 

appropriate and necessary to regulate EGUs under CAA section 112. The February 2008 

vacatur of the Section 112(n) Revision Rule reverted the status to that of the December 2000 

regulatory determination. CAA section 112(n)(1)(A) and the 2000 determination do not 
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differentiate between EGUs located at major versus area sources of hazardous air pollutants 

(HAP). Thus, the NESHAP for EGUs will regulate units at both major and area sources. 

Major sources of HAP are those that have the potential to emit 10 tons per year (tpy) or more 

of any one HAP or 25 tpy or more of any combination of HAP. 

2.2 Description of the Rule and its Scope 

The “electric utility steam generating unit” source category includes those units that 

combust coal or oil for the purpose of generating electricity for sale and distribution through 

the national electric grid to the public. CAA section 112(a)(8) defines an “electric utility 

steam generating unit” as: 

any fossil fuel-fired combustion unit of more than 25 megawatts electric 

(MWe) that serves a generator that produces electricity for sale. A unit that 

cogenerates steam and electricity and supplies more than one-third of its 

potential electric output capacity and more than 25 MWe output to any utility 

power distribution system for sale is also considered an electric utility steam 

generating unit. 

The source category includes investor-owned units as well as units owned by the 

Federal government, municipalities, and cooperatives, among others. These units provide 

electricity for commercial, industrial, and residential uses. Currently, coal-fired generating 

units typically supply “base-load” electricity, which means these units operate continuously 

throughout the day and meet the part of electricity demand that is relatively constant. Oilfired generating units typically supply “peak” power, when there is increased demand for 

electricity (e.g., when businesses operate throughout the day or when people return home 

from work and run appliances and heating/air-conditioning, versus late at night or very early 

morning when demand for electricity is reduced). Coal- and oil-fired EGUs have the 

potential to emit many HAP. 

Coal-fired EGUs include units that burn coal, coal refuse, or a synthetic gas derived 

from coal either exclusively, in any combination together, or in any combination with other 

supplemental fuels. Examples of supplemental fuels included petroleum coke and tirederived fuels. Oil-fired EGUs include units that burn liquid oil or solid oil-derived fuel (i.e., 

petroleum coke). The NESHAP will establish standards for HAP emissions from both coaland oil-fired EGUs and will apply to any existing, new, or reconstructed units located at 

major or area sources of HAP. Although all HAP are pollutants of interest, those of 

particular concern are hydrogen fluoride (HF), hydrogen chloride (HCl), dioxins/furans, and 

HAP metals, including antimony, arsenic, beryllium, cadmium, chromium, cobalt, mercury, 

manganese, nickel, lead, and selenium. 

In developing the vacated CAMR, EPA identified a total of 81 potentially affected 

small entities with coal-fired EGUs and determined that CAMR would not have a significant 

impact on a substantial number of those small entities. That determination was based on the 

fact that the final rule would not establish requirements applicable to small entities, other 

than new sources. At that time, EPA projected no new construction of coal-fired utility units. 
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Additionally, CAMR did not establish requirements applicable to existing small entities 

because the final rule made allowances available to each State; the States were then to 

distribute their allowances to the EGUs within their State according to their individual 

situations. Based on current information, we have identified approximately 525 facilities 

with 1,350 individual coal- or oil-fired units. We estimate that 80 companies that own coalor oil-fired EGUs are small entities. 

2.3 Related Federal Rules 

As noted above, the “electric utility steam generating unit” source category includes 

those units that combust coal or oil for the purpose of generating electricity for sale and 

distribution through the national electric grid to the public. Because of the definition 

provided in CAA section 112(a)(8), there should not be any EGU that is regulated under 

another CAA section 112 regulation. 

Combustion units that burn fossil fuels but do not meet the size or electric distribution 

requirements of CAA section 112(a)(8) will be covered under the CAA section 112(d) rules 

for Industrial, Commercial, and Institutional Boilers (Area and Major Source Boiler 

NESHAPs), which were proposed on June 4, 2010 (75 FR 31896 and 75 FR 32006). 

Combustion units that burn a solid waste as defined by the Administrator will be covered as 

solid waste incineration units under CAA section 129. However, combustion units that burn 

a homogeneous solid waste and are qualifying units and are thus exempt from regulation 

under CAA section 129 under the provisions of CAA section 129(g)(1)(B) will be covered 

under the Utility NESHAP if they combust fossil fuel and meet the size and electric 

distribution requirements of CAA section 112(a)(8); otherwise they will likely be covered 

under one of the Boiler NESHAPs (final action required by February 21, 2011). 

In 2007, EPA revised new source performance standards (NSPS) for EGUs having a 

heat input capacity greater than 250 million Btu per hour (40 CFR part 60, subpart Da). The 

NSPS regulates emissions of particulate matter (PM), sulfur dioxide (SO2), and nitrogen 

oxides (NOX) from boilers constructed after June 2007. EPA is currently working on 

additional revisions to the PM, SO2, and NOX emissions limits in subpart Da. Those 

revisions will be proposed and promulgated along with the Utility NESHAP on March 16, 

2011 and November 16, 2011, respectively. Sources subject to the NSPS would also be 

subject to the Utility NESHAP because those rules regulate sources of HAP whereas the 

NSPS does not. However, in developing the NESHAP for EGUs, EPA will minimize the 

monitoring requirements, testing requirements, and recordkeeping requirements to avoid 

duplicating requirements to the extent possible. 

On June 3, 2010 (75 FR 31514), EPA issued a final rule that establishes thresholds 

for greenhouse gas (GHG) emissions that define when permits under the New Source Review 

Prevention of Significant Deterioration (PSD) and title V Operating Permit programs are 

required for new and existing industrial facilities (the Tailoring Rule). The final rule 

addresses emissions of six GHGs: carbon dioxide (CO2), methane (CH4), nitrous oxide 

(N2O), hydrofluorocarbons (HFCs), perfluorocarbons (PFCs), and sulfur hexafluoride (SF6). 

As of January 2, 2011, large industrial sources, including power plants, are subject to 
8 

permitting requirements for their GHG emissions if they otherwise are required to obtain a 

PSD or title V permit due to emissions of other air pollutants. 

On December 23, 2010, EPA announced a settlement agreement, subject to CAA 

section 113(g) public comment, under which it would issue a proposed rule under CAA 

section 111(b) that includes standards of performance for GHGs for new and modified EGUs 

as well as issuing a proposed rule under CAA section 111(d) that includes emission 

guidelines for GHGs from existing EGUs . The rules would establish NSPS for new and 

modified EGUs and emission guidelines for existing EGUs. In addition to the NSPS 

requirements established for new and modified sources under section 111(b) of the CAA, for 

pollutants not regulated under other parts of the CAA, EPA must establish emission 

guidelines under CAA section 111(d) that States use to develop plans for reducing emissions 

from existing sources. The guidelines include targets based on demonstrated controls, 

emission reductions, costs and expected timeframes for installation and compliance, and can 

be less stringent than the requirements imposed on new sources. Under the agreement, EPA 

commits to issuing these proposed regulations by July 26, 2011 and, after considering any 

public comments received concerning the proposed rule(s), a final rule that takes final action 

with respect to the proposed rule(s) by May 26, 2012. At this time the Agency has not 

formulated a final approach for regulating GHGs from EGUs; however, there is the potential 

that compliance with requirements of the NESHAP could result in some existing sources 

becoming new sources for purposes of the NSPS. 

On August 2, 2010 (75 FR 45210), EPA proposed a rule that would require 31 states 

and the District of Columbia (D.C.) to significantly improve air quality by reducing power 

plant emissions that contribute to ozone and fine particle pollution in other states (the Clean 

Air Transport Rule). Specifically, the proposal would require reductions in SO2 and NOX

emissions that cross state lines. In response to a December 2008 court decision, the proposed 

Transport Rule would replace EPA’s remanded 2005 Clean Air Interstate Rule (CAIR). The 

Transport Rule is expected to be finalized in July 2011. To the extent that EGUs are located 

in the final set of states or D.C., they would be subject to the Transport Rule. 

Based on the findings from EPA’s multi-year study of the Steam Electric Power 

Generating industry, EPA plans to revise the current effluent guidelines under the Clean 

Water Act (CWA) that apply to steam electric power plants. EPA evaluated waste streams 

generated at power plants, including wastewaters from wet flue gas desulfurization (FGD) air 

pollution control systems, fly ash and bottom ash handling, coal pile runoff, condenser 

cooling, equipment cleaning, and leachate from landfills and impoundments, but ultimately 

focused largely on discharges associated with coal ash handling operations and wastewater 

from FGD systems because these sources comprise a significant fraction of the pollutants 

discharged by steam electric power plants. EPA is required by consent decree to propose 

revised effluent guidelines in July 2012 and to finalize the guidelines in January 2014. 

Section 316(b) of the CWA requires EPA to establish best technology available 

standards to minimize adverse environmental impacts from cooling water intake structures. 

In developing these standards, EPA divided its effort into three rulemaking phases. Phase I, 

for new EGU plants using cooling water, was promulgated on December 18, 2001 (66 FR 
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65255). Minor revisions to the Phase I rule were finalized on June 19, 2003 (68 FR 36749). 

Phase II, for existing EGU plants that use at least 50 million gallons per day (MGD) of 

cooling water, was promulgated on July 9, 2004 (69 FR 41576). Those regulations were 

challenged, and several provisions of the Phase II rule were remanded on various grounds. 

EPA suspended most of the rule in response to the remand (72 FR 37107, July 9, 2007). On 

June 16, 2006 (71 FR 35005), EPA promulgated the Phase III regulations covering existing 

EGU plants using less than 50 MGD of cooling water. Those regulations also were 

challenged, and EPA requested, and was granted, a partial remand. EPA plans to issue 

regulations that address both Phase II and III facilities. EPA signed a settlement agreement 

that requires those regulations to be proposed by March 14, 2011, and promulgated by July 

27, 2012. 

On June 21, 2010 (75 FR 35128), EPA proposed national rules for the management of 

coal combustion residuals under the Resource Conservation and Recovery Act (RCRA). 

Coal combustion residuals, commonly known as coal ash, are residues from the combustion 

of coal in power plants and are captured by pollution control technologies, like scrubbers. 

The residues are disposed of in liquid form at surface impoundments and in solid form at 

landfills. EGUs will be subject to these coal ash specific regulations when they are issued. 

The date of final action has not yet been determined. 

3. OVERVIEW OF PROPOSAL UNDER CONSIDERATION

3.1 Potential Requirements of the Proposal 

As explained above, in the December 2000 regulatory determination, EPA made a 

finding that it was appropriate and necessary to regulate EGUs under CAA section 112. 

Voluntary and incentive-based approaches are not available for these standards. The 

proposed standards must set technology-based limits as appropriate, but we will explore the 

viability of other rulemaking options, such as work practices standards and health based 

standards. A work practice standard, instead of emission standards, may be proposed for 

major sources if it is not feasible to prescribe or enforce an emission standard. CAA section 

112(h)(2)(B) defines, in part, “not feasible to prescribe or enforce and emission standard” to 

mean that “the application of measurement methodology to a particular class of sources is not 

practicable due to technological and economic limitations.” CAA section 112(d)(4) provides 

EPA with discretionary authority to establish health-based emission standards for HAP for 

which a health threshold has been established. The provision is intended for cases where an 

alternative emission standard will still ensure that the health threshold will not be exceeded, 

with an ample margin of safety. 

CAA section 112(d)(2) requires standards for major sources be based on the maximum 

achievable control technology (MACT). CAA section 112(d)(3) sets minimum stringency 

criteria (MACT Floor) for these standards. For existing sources, the standards shall not be 

less stringent than “the average emission limitation achieved by the best performing 12 

percent of existing sources....” For new sources, the MACT floor is “the emission control 

achieved in practice by the best controlled similar source....” Costs may not be considered 

when determining MACT floors. EPA must consider regulatory options more stringent than 
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the MACT floor and may regulate “beyond the floor” where justified. Beyond-the-floor 

options can include additional control technologies, process changes, or other means of 

reducing HAP. Costs and other impacts/issues must be considered when assessing beyondthe-floor options. 

Since the inception of the MACT program, EPA has consistently maintained that the 

“pollutant-by-pollutant” approach to setting floors is the appropriate approach. See e.g. 61 

FR at 17368 (April 19, 1996). The “pollutant-by-pollutant” approach entails determining the 

best performing unit or units in the category for each HAP and establishing the MACT floor 

separately for each HAP (or group of HAP if a surrogate standard is established). Under this 

approach, the units on which the MACT floor are based may be different for each HAP if, for 

example, the best performing units for one HAP are poor performers for other HAP. It has 

been suggested that MACT floors should be established using a facility-wide approach. The 

concerns associated with the facility-wide approach are discussed below. 

The court has ruled that “no emission reduction” MACT floors (resulting in no 

emission limits being set) are unlawful. See Sierra Club v. EPA, 479 F.3d 875, 883. Thus, 

the proposal will contain limits for HAP for all affected EGUs. We are considering 

developing emission limits for particulate matter (PM) (as a surrogate for non-mercury HAP 

metals), mercury, hydrogen chloride (HCl) or sulfur dioxide (SO2) (as a surrogate for HAP 

acid gases), dioxin/furan, and carbon monoxide (CO) or other pollutants (e.g., polycyclic 

aromatic hydrocarbons (PAH) or formaldehyde) (as a surrogate for non-dioxin/furan organic 

HAP). The court has stated that the use of surrogate standards is allowed if it can be 

demonstrated that the surrogate standards are reasonable. For example, the recently 

promulgated NESHAP for the Portland Cement Manufacturing Industry includes emission 

limits for PM, mercury, HCl, dioxin/furan, and THC (75 FR 54970, September 9, 2010). In 

addition, the proposed Major Source Boiler NESHAP includes limits for PM, mercury, HCl, 

dioxin/furan, and CO (75 FR 32006, June 4, 2010). Based on the similarities in types of 

HAP emitted from industrial/commercial/institutional boilers and EGUs, the Major Source 

Boiler NESHAP proposal provides an estimation of potential control technologies that may 

represent those predominantly used by EGUs in the MACT floor and that may result in the 

emission reductions necessary to meet the standards for the various emissions from coal- and 

oil-fired EGUs. For example, the average PM emission limitation (as a surrogate for nonmercury HAP metals) achieved by the best performing EGUs is likely to be based on a fabric 

filter-controlled EGU, and use of a fabric filter will likely achieve the PM emission limit. 

For the various pollutants likely to be regulated under the Utility NESHAP, the estimated 

control technologies are: 

• PM/non-mercury HAP metals = Fabric Filters 

• Mercury/dioxin/furan = Activated carbon injection 

• HCl/SO2/acid gas HAP = Wet or dry scrubber 

• CO/PAH/formaldehyde/non-dioxin/furan organic HAP = Good combustion 

practices 

The court also indicated that when determining variability, sources outside the MACT 

floor may not be considered unless a demonstrated relationship between the variability of 
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sources outside the floor and the variability of sources within the floor can be shown. In 

characterizing variability of the best performing EGUs, we may include fuel variability and 

performance variability. In addition, we will look at load variability. Recent regulatory 

actions (e.g. the Major Source Boiler NESHAP proposal, final NESHAP for Portland 

Cement Manufacturing Industry) assessed variability based on the 99th percentile upper 

predictive limit (UPL). The 99th percentile UPL means that for a future test from a best 

performing source, there is 99 percent confidence that the reported level will fall at or below 

the UPL value. 

CAA section 112(d)(1) provides EPA with the authority to distinguish among classes, 

types, and sizes of sources in establishing standards. However, there must be a basis for 

distinguishing between subcategories (e.g., design differences, operating mode (continuous 

or batch), or other characteristics). Data necessary to establish MACT floors are required for 

each subcategory that is identified. 

In order to make the determinations necessary to develop the proposal, EPA has 

essentially completed an effort to collect facility information (e.g., boiler types, fuels 

combusted, control technologies) and available emissions data from 1,332 EGUs (requiring 

approximately 800 EGUs to conduct emissions testing). To date, facility information and 

available emissions data from the past 5 years have been received from almost all of the 

units. Emissions test results have been received from over 99 percent of the EGUs required 

to conduct testing. 

3.2 Options Likely to be Proposed 

EPA is still developing the proposal. EPA has not yet decided on a detailed approach 

for subcategorizing the source category, determining the MACT floor, or the compliance 

requirements. As EPA is developing the proposed rulemaking, EPA is also discussing 

appropriate options that would, consistent with the CAA, ease the compliance burden for 

small businesses that may be affected by the rule while maintaining the overall goals of the 

program. EPA will continue to seek input from small entities throughout the regulatory 

development process. Potential options must be assessed in light of the CAA and current 

case law. Some potential options to assist small entities in compliance with the new rule 

requirements are discussed below. 

All HAP emitted from EGUs must be addressed by the Utility NESHAP. Surrogate 

standards are allowed if reasonable. Regardless of whether emission standards are 

established for HAP or for surrogate pollutants, the same control technologies (or process 

changes or other means of reducing HAP) would be installed in order to comply with those 

standards. Use of surrogate standards has the potential to reduce monitoring and testing costs 

imposed on affected entities. 

 One likely option is to establish subcategories based on boiler design (e.g., units 

designed to burn coal versus units designed to burn oil versus integrated gasification 

combined cycle (IGCC) systems (burning of synthetic gas)). Other options include 

subcategorizing EGUs by duty cycle (e.g., peaking units versus base-load units), 
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subcategorizing coal-fired EGUs by coal rank (e.g., bituminous, subbituminous, lignite) 

and/or unit type (e.g., fluidized bed, pulverized coal), and subcategorizing oil-fired EGUs by 

oil type (e.g., residual, distillate). Additional potential options include the use of work 

practice or management practice standards, health-based emission levels, emissions 

averaging within a facility, reduced monitoring/testing requirements, or allowing more time 

for compliance, as long as they are consistent with the provisions of the CAA. 

Although emission standards are often structured in terms of numerical emissions 

limits, alternative approaches are sometimes necessary and authorized pursuant to CAA 

section 112. In some cases, physically measuring emissions from a source may not be 

practicable due to technological and economic limitations. CAA section 112(h) authorizes 

the Administrator to promulgate a design, equipment, work practice, or operational standard, 

or combination thereof, consistent with the provisions of CAA sections 112(d) or (f), in those 

cases where, in the judgment of the Administrator, it is not feasible to prescribe or enforce an 

emission standard for major sources. As previously explained, section 112(h)(2) provides 

that the phrase “not feasible to prescribe or enforce an emission standard” includes the 

situation in which the Administrator determines that the application of measurement 

methodology to a particular class of sources is not practicable due to technological and 

economic limitations. 

Under CAA section 112(d)(5), EPA may elect to promulgate standards or 

requirements for area sources “which provide for the use of generally available control 

technologies or management practices (‘GACT’) by such sources to reduce emissions of 

hazardous air pollutants.” Consistent with the legislative history, costs and economic 

impacts may be considered in determining GACT. Determining what constitutes GACT 

involves considering the control technologies and management practices that are generally 

available to the area sources in the source category. The standards applicable to major 

sources in the analogous source category also are considered to determine if the control 

technologies and work practices are transferable and generally available to area sources. In 

appropriate circumstances, technologies and practices at area and major sources in similar 

categories may be considered to determine whether such technologies and practices could be 

considered generally available for the area source categories at issue. 

As a general matter, section 112(d) of the CAA requires MACT standards at least as 

stringent as the MACT floor to be set for all HAP emitted from major sources. However, 

section 112(d)(4) provides that for HAP with established health thresholds, the Administrator 

has the discretionary authority to consider such health thresholds when establishing emission 

standards under section 112(d). This provision is intended to allow EPA to establish 

emission standards other than conventional MACT standards in cases where the alternative 

emission standard would ensure that the health threshold will not be exceeded, with an ample 

margin of safety. To exercise this discretion, EPA must first conclude the HAP at issue has 

an established health threshold and must then provide for an ample margin of safety when 

considering the health threshold to set an emission standard. EPA has exercised its 

discretionary authority under CAA section 112(d)(4) in a handful of prior actions setting 

emissions standards for other major source categories, including the emissions standards 

issued in 2004 for commercial and industrial boilers and process heaters, which were vacated 
13 

on other grounds by the D.C. Circuit Court. In both the Pulp and Paper NESHAP, 63 FR 

18765 (April 15, 1998), and Lime Manufacturing NESHAP, 67 FR 78054 (December 20, 

2002), EPA invoked CAA section 112(d)(4) for HCl emissions for discrete units within the 

facility. In those actions, EPA concluded that HCl had an established health threshold and 

was not classified as a human carcinogen. In light of the absence of evidence of carcinogenic 

risk, the availability of information on non-carcinogenic effects, and the limited potential 

health risk associated with the discrete units being regulated, EPA concluded that it was 

appropriate to exercise its discretion under CAA section 112(d)(4) for HCl under the 

circumstances of those actions. In a more recent action, EPA decided not to propose a 

health-based emission standard for HCl emissions under CAA section 112(d)(4) for Portland 

Cement facilities, 75 FR 54970 (September 9, 2010). EPA has never implemented a 

NESHAP that used section 112(d)(4) authority with respect to the other HAP acid gases of 

hydrogen fluoride (HF), chlorine (Cl2), and hydrogen cyanide (HCN). 

EPA has a general policy of encouraging the use of flexible compliance approaches 

where they can be properly monitored and enforced. Emissions averaging can provide 

sources the flexibility to comply in the least costly manner while still maintaining regulation 

that is workable and enforceable. Emissions averaging allows an affected source to 

demonstrate that the source complies with the emission limits by averaging the emissions 

from an individual affected unit that is emitting above the emission limits with other affected 

units at the same facility that are emitting below the emission limits. EPA has generally 

imposed certain limits on the scope and nature of emissions averaging. These limits include 

no averaging between different types of pollutants; no averaging between sources that are not 

part of the same affected source; no averaging between individual sources within a single 

major source if the individual sources are not subject to the same NESHAP; and no 

averaging between existing sources and new sources. 

EPA’s standards must establish requirements that are adequate to assure continuous 

compliance with the rule. In some instances, that can be achieved without significant 

additional burden for facilities that must implement the rule. For example, use of surrogate 

pollutants may result in reduced compliance costs because testing would only be required for 

the surrogate pollutants (e.g., PM) versus the HAP (e.g., all non-mercury HAP metals). 

Continuous monitoring of control device parameters, rather than continuous monitoring of 

emissions, results in reduced monitoring costs. Standards based on work practices or 

management practices in lieu of emission limits also result in reduced compliance costs 

because testing and continuous monitoring would not typically be required. 

Section 112 of the CAA specifies the dates by which affected sources must comply 

with the emission standards. New or reconstructed units must be in compliance with the final 

rule immediately upon startup or the date that the final rule is published in the Federal 

Register, whichever is later. Existing units may be allowed up to 3 years to comply with the 

final rule. EPA has authority to require that existing sources comply in less than 3 years 

where appropriate. With respect to compliance with the Utility NESHAP, EPA believes that 

3 years for compliance is likely necessary to allow adequate time to design, install and test 

control systems. Section 112(i)(3)(B) of the CAA allows facilities to request a one-year 

extension to any MACT compliance schedule if such additional time is necessary for the 
14 

installation of controls. The extension is not automatic and may be provided on a case-bycase basis by each facility’s permitting authority based on a request by the affected facility. 

The President may exempt any stationary source from compliance with any standard or 

limitation under CAA section 112 for a period of not more than 2 years if the President 

determines that the technology to implement such standard is not available and that it is in 

the national security interests of the United States to do so (see CAA section 112(i)(4)). An 

exemption under this provision may be extended for one or more additional periods, each 

period not to exceed 2 years. 

4. APPLICABLE SMALL ENTITY DEFINITIONS 

For purposes of assessing the impacts of the proposed rule on small entities, small 

entity is defined as: (1) a small business according to the Small Business Administration 

(SBA) size standards by the North American Industry Classification System (NAICS) 

category of the owning entity (the range of small business size standards for electric utilities 

is 4 million megawatt hours of production or less); (2) a small governmental jurisdiction that 

is a government of a city, county, town, township, village, school district or special district 

with a population of less than 50,000; and (3) a small organization that is any not-for-profit 

enterprise which is independently owned and operated and is not dominant in its field. As set 

by SBA, the categories of small entities that will potentially be affected by this rulemaking 

are defined in the following table: 

Sector NAICS 

Code 

Defined as small entity by SBA if less 

than or equal to: 

Population Size Standard 

Fossil Fuel Electric Power 

Generation (Industry) 221112 N/A 4 million megawatt hours

Fossil Fuel Electric Power 

Generation 

(State/Local Government) 

221112 50,000 N/A 

Fossil Fuel Electric Power 

Generation (American Indian 

and Alaska Native Tribal 

Governments) 

921150 N/A (see 

footnote)1 N/A (see footnote)1

EPA used a variety of sources to identify which entities are appropriately considered 

“small.” EPA used the criteria for small entities developed by SBA under the NAICS 

 

1

 As stated in the current SBA small business size standards: NAICS Sector 92 – Small business size standards 

are not established for this sector. Establishments in the Public Administration sector are Federal, State, and 

local government agencies which administer and oversee government programs and activities that are not 

performed by private establishments. Concerns performing operational services for the administration of a 

government program are classified under the NAICS private sector industry based on the activities performed. 

Similarly, procurements for these types of services are classified under the NAICS private sector industry that 

best describes the activities to be performed. For example, if a government agency issues a procurement for law 

enforcement services, the requirement would be classified using one of the NAICS industry codes under NAICS 

industry 56161, Investigation, Guard, and Armored Car Services. 
15 

code(s) as a guide.2

 Utility NESHAP information collection request (ICR) responses and 

data from other Agency actions (e.g., Clean Air Interstate Rule, proposed Transport Rule) 

were used to identify facilities. EPA then found revenue, employment, and population 

information for parent entities using sources including Dun and Bradstreet, Standard & 

Poor’s, American Business Information, the Energy Information Administration (EIA) within 

the U.S. Department of Energy, the U.S. Census Bureau, and Ventyx. 

5. SMALL ENTITIES THAT MAY BE SUBJECT TO THE PROPOSED 

REGULATION 

The estimated number of small entities that will be potentially subject to the Utility 

NESHAP, as required by CAA, include 66 small State/local governments and 14 small nongovernment entities. These numbers reflect additions and deletions to the initial list of 

potentially impacted small entities as suggested by SERs as appropriate. EPA is aware of 

EGUs located in Indian Country but is not aware of any EGUs owned by Tribal entities. 

Potentially affected small entities are presented in the following table: 

Alexandria LA (City of) Dalton GA (City of) Los Alamos County 

Sam Rayburn G & T 

Electric Coop Inc 

Algona Municipal Utilities Dover DE (City of) 

Louisiana Energy & Power 

Authority 

San Miguel Electric Coop 

Inc 

Alta IA (City of) East Power Corporation Lyndonville Electric Dept Sikeston Utilities 

American Consumer 

Industries Inc East Texas Electric Coop Manitowoc Public Utilities 

South Mississippi Electric 

Power Association 

American Consumers Inc Eldridge IA (City of) 

Marquette Board of Light & 

Power 

Southern Illinois Power 

Coop 

American Hydropower 

Company Farmington NM (City of) Milford Municipal Utilities 

Southern Minnesota 

Municipal Power Agency 

American Power Investors 

Inc. Fort Pierce Utility Authority 

Missouri River Energy 

Services Spencer Municipal Utilities 

Arizona Electric Power 

Coop 

Fremont Dept of Public 

Utilities 

Montezuma Municipal 

Utilities Square Butte Electric Coop 

Atlantic Municipal Utilities Geneseo Municipal Utilities 

Municipal Energy Agency 

of Nebraska 

Sumner Municipal Light 

Plant 

Austin Utilities 

Graettinger Municipal Light 

Plant Muscatine Power & Water 

Sunflower Electric Power 

Coop 

Azusa CA (City of) 

Grand Haven Light & 

Power 

National Energy & Gas 

Transmission Tipton IA (City of) 

Bancroft Municipal Utilities Grand Island Utilities 

New Hampton Municipal 

Light Plant Tondu Corp 

Banning Electric Division 

Greenville Electric Utility 

System 

North American Power 

Group Ltd 

Utah Associated Municipal 

Power System 

Beowulf Energy LLC Harlan Municipal Utilities 

Northeast Texas Electric 

Coop Inc 

Wabash Valley Power 

Association Inc 

Cedar Falls Utilities Hastings Utilities (NE) Northwest Power Coop Waverly Light & Power 

Central Iowa Power Coop 

Henderson Municipal Power 

& Light Osceola AR (City of) Webster City IA (City of) 

Central Vermont Public 

Service Corp 

Holland Board of Public 

Works 

Pella Municipal Light & 

Power West Bend IA (City of) 

Colstrip Energy LP Jonesboro Water & Light Power Resources Coop West Memphis Utility Dept 

Coon Rapids IA (City of) Kansas Electric Power Coop Prairie Power Coop Winfield KS (City of) 

Corn Belt Power Coop Laurens IA (City of) Richmond Power & Light WPPI Energy 

 

2

 The current SBA size standards are found at 

http://www.sba.gov/idc/groups/public/documents/sba_homepage/serv_sstd_tablepdf.pdf. 
16 

 EPA’s list of potentially affected small entities includes electricity generators. SERs 

believe that this list should also include distribution cooperatives that own electricity 

generation and transmission (G&T) cooperatives and that qualify as small entities. SERs 

stated that the Utility NESHAP will have a direct impact on all electric cooperatives 

generating and/or distributing coal-based power given the closely interwoven nature of the 

G&T cooperatives and the distribution cooperatives. SERs explained that any expenditure 

made by the G&T cooperatives in order to comply with requirements of the Utility NESHAP 

will be borne in tandem by the distribution cooperatives because the G&T cooperatives are 

owned by the distribution cooperatives they serve. EPA acknowledges that small entity 

distribution cooperatives that own generation processes would be impacted in some way by 

the Utility NESHAP because generation processes will be regulated by the standards, but the 

extent to which small entity distribution cooperatives would be impacted is unclear without 

more detailed information on these entities. 

6. SUMMARY OF SMALL ENTITY OUTREACH 

6.1 Small Entity Outreach 

Before beginning the formal SBREFA process, EPA engaged in outreach with entities 

that would potentially be affected by the upcoming rulemaking to provide an opportunity for 

discussion of their questions and concerns regarding the upcoming rulemaking. The outreach 

consisted of meeting with some organizations that represent and include small entities, 

including the American Public Power Association (APPA), Edison Electric Institute (EEI), 

the Utilities Air Regulatory Group (UARG), and the Coal Utilization Research Council 

(CURC). Once the SBAR Panel process began and potential small entity representatives 

(SERs) were identified, EPA provided each SER with background information on the Utility 

NESHAP rulemaking process. An outreach meeting with the SERs was held on December 2, 

2010. 

6.2 Summary of Panel’s Outreach Meeting with Small Entity Representatives

 The SBAR Panel convened on October 27, 2010. The Panel held a formal outreach 

meeting/teleconference with SERs on December 2, 2010. To help the SERs prepare for the 

meeting/teleconference, on November 17, 2010, the Panel sent materials to each of the SERs 

via e-mail. Representatives from fourteen of the eighteen companies and organizations that 

were selected as SERs for this SBREFA process participated in the meeting (in person and 

by phone). There were five non-SER participants from organizations representing power 

producers. The Outreach Meeting was held to solicit input/suggestions from the SERs 

regarding the upcoming rulemaking. The meeting was opened by Ken Munis, acting in place 

of Alex Cristofaro, EPA’s Small Business Advocacy Chair, with a short introduction to the 

Regulatory Flexibility Act (RFA) and SBREFA process, the purpose of the Outreach 

Meeting, and the importance of the SERs’ comments. Following this was a presentation by 

EPA staff. Information presented included: 

• Background 
17 

• Project history 

• Section 112 overview 

• Constraints on rulemaking 

• Affected facilities 

• Data 

• Rulemaking options under consideration 

• Potential control technologies and estimated costs 

• Applicable small entity definitions 

• Small entities potentially subject to regulation 

• Questions for SERs 

A discussion of issues related to the NESHAP program in general, the potential 

requirements of the Utility NESHAP, and the regulatory areas where EPA has discretion and 

could potentially provide flexibility followed the presentation (see section 8.5 for 

discussions/comments raised during the EPA Outreach Meeting). EPA asked that the SERs 

provide feedback on the outreach materials they received as well as the outreach meeting by 

December 16, 2010. The Agency received written comments from, or on behalf of, ten 

SERs. Written comments also were received from the National Rural Electric Cooperative 

Association (NRECA) and the American Public Power Association (APPA). (See appendix 

B). 

7. LIST OF SMALL ENTITY REPRESENTATIVES 

Eighteen SERs were selected for the Panel Process. The official SER list is as 

follows: 

Atlantic Municipal Utilities Bancroft Municipal Utilities 

Atlantic, IA Bancroft, IA 

Alan Bonderman Brian Hatten 

Colstrip Energy LP Central Iowa Power Cooperative* 

Boise, ID Cedar Rapids, IA 

Scott Siddoway Greg Gerdes and Rex Butler 

Coon Rapids Municipal Utilities Corn Belt Power Cooperative* 

Coon Rapids, Iowa Humboldt, IA 

 Michael Thatcher 

Dalton Utilities Geneseo Municipal Utilities* 

Dalton, GA Geneseo, IL

 Tim Long 

Holland Board of Public Works Jamestown Board of Public Utilities 

Holland, MI Jamestown, NY 

Daniel Nally Steve Kulig 
18 

Marquette Board of Light & Power Montezuma Municipal Utilities 

Marquette, MI Montezuma, IA 

Erik Booth Kevin Kundart 

Muscatine Power & Water San Miguel Electric Cooperative, Inc.* 

Muscatine, IA Joe Eutizi 

Donald Pauken 

Southern Illinois Power Cooperative* Tes Filer City Station Power Plant 

Marion, IL Manistee, MI 

Leonard Hopkins Tondu Corporation 

 Houston, TX 

 James A. Ford 

Texas Municipal Power Agency Wyandotte Municipal Services 

Bryan, TX Wyandotte, MI 

Ken Babb James R. French 

*SER for Panel on Clean Air Interstate Rule Federal Implementation Plan 

Representatives of the NRECA, APPA, Edison Electric Institute (EEI), Hunton & 

Williams, and J.E. Cichanowicz, Inc. participated as viewers/technical backup that 

augmented the SERs and provided comment but did not act as SERs. Those representatives 

are as follows: 

Bill Wemhoff Theresa Pugh 

Sr. Principal, Environmental Policy Director of Environmental Services 

NRECA APPA 

Arlington, VA Washington, D.C. 

Michael Rossler Lee Zeugin 

Manager Environmental Programs Attorney at Law 

EEI Hunton & Williams 

Washington, D.C. Washington, D.C. 

J. Edward Cichanowicz 

J.E. Cichanowicz, Inc. 

Saratoga, CA 

8. SUMMARY OF INPUT FROM SMALL ENTITY REPRESENTATIVES 

8.1 Number and Types of Entities Affected 

The table in Chapter 5 of this report, which presents the small entities potentially 

affected by the Utility NESHAP, was provided to the SERs before the outreach meeting, and 

was discussed at the meeting. During the outreach meeting, SERs indicated that they believe 
19 

more small entities than those EPA estimated will be impacted. With regard to 

municipalities, SERs pointed out that joint action agencies also could be small entities 

potentially impacted. For cooperatives, SERs indicated that in addition to small entity G&T 

cooperatives, there are small entity distribution cooperatives that own G&T entities that 

could be potentially impacted. 

Written comments indicate that cooperatives are concerned that EPA’s evaluation of 

the potential impacts on small entities fails to account for a large number of potentially 

affected small distribution cooperatives. Because the G&Ts are owned by the distribution 

cooperatives they serve, SERs believe that the Utility NESHAP will have a direct impact on 

all electric cooperatives generating and/or distributing coal-based power. NRECA provided 

a list of the 14 G&T cooperatives that own coal-fired generation and that NRECA believes 

qualify as small entities under the SBA size standards. NRECA’s list includes cooperatives 

that NRECA believes meet the SBA size standards and were not on EPA’s list, and omits 

some cooperatives that were on EPA’s list and that NRECA believes do not meet the size 

standards. In addition, SERs believe that 559 distribution cooperatives also qualify as small 

entities. 

8.2 MACT Floors and Variability 

During the outreach meeting, SERs raised the following four issues with respect to 

determining MACT floors and assessing variability: (1) pollutant-by-pollutant ranking 

approach, (2) pollutants to be regulated, (3) floor determination methodology for existing 

units, and (4) assessment of emissions variability, including periods of startup and shutdown, 

and fuel, performance, and load variability. SERs believe that determining MACT floors on 

a pollutant-by-pollutant basis creates emission limits that are technically infeasible because 

the limits are based on the best performing units for each pollutant and not on the best 

performers on a unit or facility basis. SERs suggested that a facility-wide approach to 

determining the MACT floors should be used. An example of how a pollutant-by-pollutant 

approach could result in technical infeasibility with respect to CO and nitrogen oxides (NOX) 

was discussed. SERs explained that minimizing CO to meet its limit could actually lead to 

an increase in NOX emissions (i.e., de-tuning the boiler). 

Written comments reiterated that the end result of determining a MACT floor for 

each HAP or HAP surrogate for each subcategory of sources is a set of MACT floors that do 

not represent the emission levels achieved by an actual, best-performing unit. Instead, they 

reflect the performance of a hypothetical, ideal unit that does not exist. SERs believe that 

this methodology for setting MACT floors is inconsistent with CAA section 112(d)(3) 

requirements. In addition, by focusing on one HAP at a time, SERs believe that the 

antagonistic effects a given HAP limit will have on other regulated pollutants are missed 

(e.g., production of CO during the combustion process is inversely related to NOX production 

and, therefore, it may be difficult to meet a CO limit if NOX reductions are also required). 

One SER explained that, in fact, using CO as a surrogate is a concern because of the inverse 

relationship between NOX and CO. 
20 

In written comments, SERs stated their belief that the Utility NESHAP should be 

limited to mercury control only. EPA has not determined that emissions of other HAP in the 

quantities emitted are detrimental to human health or the environment. SERs support EPA’s 

2004 legal analysis of why it believed it only had authority to set MACT standards for 

mercury under section 112(d) of the CAA (see 69 FR 4659-61, January 30, 2004). 

SERs commented during the outreach meeting that the MACT floor for existing units 

should be determined using the entire inventory of EGUs and not using only the units for 

which EPA has test data. SERs believe that basing the MACT floor on only those units for 

which there is data results in a floor value that is representative of the “best of the best” (i.e., 

based on the best performing units of the group of units estimated by EPA to be the best 

performers and, therefore, were required to conduct emissions tests). In written comments, 

SERs stated their belief that Congress never contemplated the situation where the amount of 

available data from a large source category or subcategory would require EPA to set MACT 

limits based on the performance of only one or two sources (as EPA did in the proposed 

NESHAP for major industrial, commercial, and institutional boilers and process heaters). 

With respect to estimating variability associated with emissions of the best 

performing EGUs, during the outreach meeting, SERs asked that EPA consider establishing 

percent reduction limits (i.e., required emissions reduction between the EGU inlet and the 

stack) as an alternative to complying with an emissions limit (i.e., an emissions value at the 

stack). They believe that percent reduction limits would provide small entities flexibility in 

complying with the NESHAP in addition to providing a means of potentially accounting for 

variability. SERs expressed concern that periods of startup and shutdown could present 

problems with meeting PM, CO, and other emission limits. During these periods, the 

emissions tend to increase to levels that in some instances are far greater than emissions 

during normal operation. SERs commented that an approach that would aid small entity 

compliance by accounting for startup and shutdown periods would be to base emissions 

limits on a longer averaging time (e.g., 30-days or 12-months, as recommended in written 

comments from one SER) rather than basing limits on 3-run (hour) averages. Given the 

inherent variability in boiler performance, a longer averaging period, especially for CO, 

would prevent a single spike in emissions from causing a well performing unit to be in noncompliance. 

SERs stated in written comments that in order for a standard to be achievable, it must 

be achievable under most adverse circumstances which can reasonably be expected to recur 

and, thus, the rule must account for all variability in HAP emissions. One SER pointed out 

that EPA was instructed by the court to consider the efficiency of control equipment but also 

non-technology factors that may influence the emissions of the best performing units. That 

SER also explained that three-day stack sampling provides a snapshot of a unit’s HAP 

emissions and is not indicative or representative of the unit’s emissions over longer periods 

of time. Thus, the SER stated that EPA must account for emissions variability in order to 

determine the level of performance achieved by the best performing units and inquired how 

EPA plans to modify the stack emissions to account for fuel, performance, and load 

variability. SERs restated their recommendation that the rule should include an either/or 

standard of percent reduction or emission limits to allow the source to comply with the least 
21 

expensive or burdensome option. They pointed out that the composition of coal used at 

facilities can vary considerably due to dissimilarity in composition from different locations or 

layers in the mine, to the use of coal from more than one mine, and to the blending of various 

sources, types, or amounts of coal. One SER pointed out that, over the past six years, 

variation in their monthly composite coal sample from a single mine has ranged between 17 

and 48 pounds of mercury per trillion Btu, and yearly averages have ranged between 24.5 

and 31.9 pounds of mercury per trillion Btu. That SER recommended an emissions standard 

based on a 12-month rolling average due to the variability of mercury in fuel and the 

difficulty of measuring minute quantities of mercury. SERs representing cooperative entities 

believe that work practice standards are more appropriate during periods of startup, 

shutdown, and malfunction than are HAP emission limits based on long-term rolling 

averages. 

 One SER indicated that de minimis exemption is a regulatory option/small entity 

flexibility that EPA should consider. 

8.3 Monitoring, Reporting, and Recordkeeping 

During the outreach meeting, SERs made several observations in response to EPA’s 

estimated costs for mercury and PM continuous emissions monitoring systems (CEMS). 

Based on their experiences, mercury CEMS are expensive and haven’t worked well. One 

SER stated that the total capital investment for a mercury CEMS is close to double the cost 

estimated by EPA (i.e., $400,000–$500,000, rather than $260,000). A SER explained that 

their mercury CEMS worked for about one month and has presented numerous problems in 

the two and a half years since that time. For these reasons, SERs believe that mercury CEMS 

should not be a requirement of the Utility NESHAP. SERs stated that PM CEMS are not 

widely deployed within the utility sector. SERs expressed a concern regarding the ability of 

PM CEMS to operate properly in stacks containing moisture (i.e., EGUs with wet scrubbers). 

One SER suggested that requiring opacity monitoring and periodic emissions testing is more 

appropriate than requiring PM CEMS. Another SER stated that if PM CEMS are required by 

the Utility NESHAP, opacity monitoring requirements (i.e., continuous opacity monitors) of 

other Federal regulations should no longer apply. 

 In written comments, SERs recommended that monitoring, reporting, and 

recordkeeping requirements should be minimized and simplified to the maximum extent 

possible. One SER indicated that the use of PM as a surrogate for metal HAP is of concern 

because it would necessitate the use of PM monitoring technology which, according to the 

SER, is in its infancy and has not been proven to be reliable over varying load ranges. The 

SER stated that another problem regards the need to install PM monitors upstream of wet 

scrubbers rather than in the stack as is typical. Upstream installation will not account for the 

PM removal that occurs in the wet scrubber. Another SER recommended the use of opacity 

as an economical and proven indicator of good particulate emission controls over use of PM 

CEMS. They pointed out that PM CEMS offer no benefits to units that already have the Best 

Available Control Technology (BACT) installed and will already be below what the SER 

posits the PM limit may be. 
22 

8.4 Subcategorization 

One SER commented during the outreach meeting that EPA should subcategorize 

lignite-fired EGUs from other coal-fired EGUs. The SER further commented that separate 

subcategories should be established for the two types of lignite-fired EGUs (i.e., North 

Dakota lignite and Gulf Coast lignite). The SER indicated that not only do lignite-fired 

EGUs differ from other coal-fired EGUs, but EGUs fired with the two types of lignite also 

have very different characteristics. SERs explained that blending of bituminous and subbituminous coals in EGUs is a common practice. An option mentioned to address the 

practice of coal blending is to establish separate subcategories for bituminous coal-fired 

EGUs, sub-bituminous coal-fired EGUs, and blended bituminous/sub-bituminous coal-fired 

EGUs. No subcategorization of bituminous, sub-bituminous, and blended bituminous/subbituminous coal-fired EGUs is another option mentioned during discussion of coal blending. 

SERs pointed out that consideration needs to be given to how EGUs that may move between 

subcategories, depending on the subcategories that are established, will be regulated and 

show compliance with the applicable standards. For example, if subcategories were 

established for bituminous coal-fired EGUs, sub-bituminous coal-fired EGUs, and blended 

bituminous/sub-bituminous coal-fired EGUs, a single unit could potentially burn 100 percent 

bituminous coal at times, 100 percent sub-bituminous coal at times, and a blend of 

bituminous and sub-bituminous coal at other times. Some SERs requested that EPA consider 

establishing a subcategory for combined heat and power (CHP) units that meet the definition 

of EGU (i.e., generate enough electricity). With regard to consideration of separate 

subcategories for base-load EGUs and peaking EGUs, SERs explained that the duty cycles 

for some coal-fired EGUs are not primarily base-load, as in the past, but may alternate 

between operating as base-load units and peaking units. Similar comments were not made 

with regard to consideration of base-load oil-fired EGUs and peaking oil-fired EGUs as 

separate subcategories. 

 In written comments, SERs encouraged the broad use of subcategories. They pointed 

out that in providing EPA discretion to create subcategories, section 112(d)(1) of the CAA 

does not restrict subcategorization to cases where the class, type or size factors affect HAP 

emissions. As an example, SERs explained that, under CAA section 111, EPA has 

subcategorized boilers on the basis of size (heat input) or the type of fuel burned (coal, oil or 

gas) and that these subcategorization decisions were based on feasibility and/or cost 

considerations, not on the level of emissions. One SER specifically indicated that 

subcategorization based on EGU size should be one of the approaches considered when 

proposing the rule. SERs indicate that coal rank has a significant effect on mercury and HCl 

emissions. In addition to recognizing the differences in the characteristics of the Gulf Coast 

lignite and the North Dakota lignite, SERs pointed out that the quality of coal in the Illinois 

basin varies considerably even within the basin. One SER stated that subcategories should 

be established for base-load EGUs and peaking EGUs. The SER supported subcategories 

based on whether an EGU burns Powder River Basin (PRB) coal, lignite, fuel oil, or other 

fuel types. The SER further stated that the ability to change subcategory with changes in fuel 

type will be important. Another SER recommended that wall-fired EGUs and tangentiallyfired EGUs should be separate subcategories. The SER explained that tangentially-fired 

units have lower NOX emission rates than wall-fired units. NOX is not directly affected by 
23 

the Utility NESHAP but CO may be used as a surrogate for organic HAP. Because NOX and 

CO are inversely related, the SER further explained that the lower NOX emissions provide an 

advantage to tangentially-fired units. SERs representing public power entities urged EPA to 

consider a separate subcategory for small non-profit electric providers if the Agency 

continues with enacting multiple large-scale regulations. One SER also stated that EPA 

should consider a co-firing subcategory for coal and biomass with emission limits 

somewhere between the units designed to burn coal and units designed to burn biomass. 

Addition of such a subcategory would offer an incentive to offset the combustion of coal 

with biomass. 

8.5 Area Source Standards 

During the SER Outreach meeting, SERs suggested that EPA establish separate 

emission standards for EGUs located at area sources of HAP and for EGUs located at major 

sources of HAP. SERs suggested that the standards for EGUs at area sources be based on 

GACT rather than MACT, as allowed under section 112(d)(5) of the CAA. Specifically, 

SERs recommended that EPA establish management practice standards for natural area 

source EGUs as well as synthetic area source EGUs. EPA estimates that there are 

approximately three natural area source EGUs and between 30 and 40 synthetic area source 

EGUs.

 In written comments, SERs encouraged EPA to exercise its discretion and set 

separate standards for EGUs that qualify as area sources. They believe that separate 

standards would have the effect of lessening the regulatory burden on small entities. 

8.6 Work Practice Standards 

During the outreach meeting, SERs recommended that EPA establish work practice 

standards for major source EGUs. This recommendation was further detailed in written 

comments. SERs urged EPA to promulgate work practice standards as a replacement for 

emission limits to the fullest extent allowed. Specifically, SERs believe it is not feasible to 

prescribe or enforce an emission standard for control of a HAP emitted at or below the 

detection limit of the method that was used to collect and analyze HAP emissions (i.e., the 

uncertainty about the accuracy of a compliance measurement is as great as the measurement 

being reported). A number of HAP, including a large percentage of the dioxin/furan and 

non-dioxin organics measurements) from EGUs are emitted at or below detection limits. 

Therefore, in these instances, SERs believe that CAA section 112(h) allows the 

Administrator to promulgate a design, equipment, work practice, or operational standard. 

8.7 Health Based Emission Limits 

SERs commented during the outreach meeting that EPA should consider using its 

CAA section 112(d)(4) authority to set a health based emission limit (HBEL) for HCl based 

on its reference concentration for the entire EGU source category. In written comments, 

SERs stated that HBELs should be used to the maximum extent possible when facts support 

their use, such as for acid gas emissions (e.g., HCl, HF, Cl2, HCN) from coal-fired EGUs. 
24 

8.8 Related Federal Rules 

During the outreach meeting, SERs asked that EPA consider the impact of competing 

regulatory requirements and technologies when developing the Utility NESHAP. They 

expressed concern with how other regulatory actions would impact EGUs’ emissions profiles 

and if those impacts would be accounted for when determining requirements of the 

NESHAP. Specifically, SERs questioned what the impact of controlling SO2 and NOX

emissions as a result of complying with the Transport Rule will do to the level of CO 

emissions, given the NOX-CO relationship (i.e., when NOX emissions are reduced, CO 

emissions may increase). SERs commented that if CO emissions are, in fact, elevated in the 

future due to controlling NOX emissions as required by the Transport Rule, those higher CO 

emissions won’t be reflected in the Utility NESHAP emission limit calculations because 

those calculations will be based on current emissions data that don’t reflect the potential 

future emissions profiles impacts of other regulatory requirements. The SERs are concerned 

with the degree to which multiple Federal rules may have cumulative impacts on small 

entities. 

In written comments, SERs stated that EPA should consider the synergistic adverse 

impacts that the Utility NESHAP will have on small cooperatives in conjunction with the 

many other air-related rulemakings that are ongoing. They further explain that cooperatives 

will experience disproportionately higher costs due to their greater dependence on coal-fired 

generation and, being non-profit, all costs will have to be passed on to their consumerowners. SERs representing public power entities estimated that anywhere from 30-50% of 

the remaining coal-fired power plants might decide to close those plants due to the many 

environmental regulations affecting the utility sector from 2014 to 2020. Taken one at a 

time, compliance with the various rules is possible on an economical basis. However, when 

the capital cost must be absorbed at once, one SER explained that small non-profit 

municipalities and their ratepayers will suffer economic hardships. Because municipalities 

do not generate profits for shareholders and the municipal rate is set at a level to cover the 

cost of service provided, increased costs cannot be offset by reducing profit margins and 

costs must be passed on to the end user. One SER requested that EPA coordinate the various 

new regulations to minimize their impact on facilities with minimal planning staff (e.g., the 

SER’s facility has three environmental positions that are responsible for monitoring 

regulatory developments and planning to implement them, in addition to the day-to-day 

environmental responsibilities). 

8.9 Potential Adverse Economic Impacts 

SERs commented during the outreach meeting on a number of concerns they have 

with respect to small entities’ ability to comply with the potential requirements of the Utility 

NESHAP. Those concerns included (1) market implications, (2) labor and materials 

shortages, (3) competing regulatory interests, (4) financial constraints, (5) the ability to get 

and repay the necessary capital, (6) competing against large companies for loans, engineering 

services, equipment vendor services, emissions testing contractors, etc., (7) the lack of 

infrastructure, (8) physical constraints (i.e., footprint availability), (9) the lack of necessary 
25 

implementation time (SERs estimated that 5 to 8 years will be necessary for planning and 

engineering, financing, delivery and installation, emissions testing, etc.), and (10) a potential 

permitting delay caused by entities making other improvements (e.g., energy efficiency 

improvements) at the same time they comply with the Utility NESHAP that trigger New 

Source Review (NSR). Based on these concerns, as well as the overall concern that 

compliance with the Utility NESHAP will complicate the SERs’ ability to finance and plan 

ahead for meeting other future rules impacting EGUs, SERs believe that accommodations for 

small entities are warranted. With respect to dates associated with the NESHAP, SERs 

inquired as to EPA’s authority to (1) move the effective date of the standards, (2) determine 

when implementation begins, (3) allow a phase-in of compliance, and (4) streamline the 

process for petitioning for a fourth year for purposes of complying with the standards. 

SERs asked that EPA consider the implications of EGU reliability versus compliance 

with the Utility NESHAP when establishing the rule’s requirements. To comply, each EGU 

will be required to go offline for a period (or several periods) of time (i.e., “outage”). SERs 

commented that those offline periods may not correspond with a scheduled outage and 

explained that each outage has to be approved and may not be allowed for the time period 

requested. In written comments, SERs representing public power entities stated that there 

will be significant constraint issues with the electric grid if EPA proceeds with a 3-year 

compliance schedule. EGUs will have to compete for an outage schedule and the Utility 

NESHAP time constraints will not be flexible enough to take into account the timeframe 

needed so that each unit can go down and still satisfy the demands for power. One SER 

explained that during an outage his entity must continue purchasing power to supply system 

load but will not be receiving revenues from supplying that power. Thus, the entity will not 

only incur the cost of the pollution control equipment, but also experience lost revenues. 

Another SER recommended that any new pollution control requirements should be designed 

to utilize existing equipment to the greatest extent possible. The SER indicated that the lack 

of back-up generation is a particular concern for small entities. If the addition of a new 

pollution control device requires electricity generation to end for many months, the member 

municipalities would lose their primary source of electric power for that entire time. 

SERs expressed concern that, depending on the type and stringency of requirements, 

the regulations could be so expensive that they cause extensive plant retirements and job 

losses. In written comments, SERs representing cooperative entities explained that because 

the G&T cooperatives are owned by the distribution cooperatives they serve, there are no 

third party shareholders who could help share the costs of compliance. All additional costs 

borne by the cooperative (and paid for by the distribution cooperative member-owners) affect 

the financial well-being of the G&T cooperative. Thus, the notion that passing through 

regulatory compliance costs to customers will somehow avoid or mitigate their impact does 

not apply to consumer-owned cooperatives. SERs representing public power entities 

explained in their written comments that increased costs cannot be offset by reducing profit 

margins and costs must be passed on to the end user. One SER indicated that capital 

investment would be recovered through retail rates, and that typically rate adjustments take 

about six months. SERs stated that in addition to residential ratepayers, small businesses 

(e.g., grocery stores, retailers, locally owned gas stations) would endure hardships from an 

increase in electric rates in an already difficult economic climate. 
26 

In written comments, SERs stated that certain EGUs may have site unit-specific 

special considerations for which the potential negative impacts must be assessed and that 

must be addressed in a final rule (e.g., through providing alternative compliance methods). 

For example, specific units may not have the physical space to add the required control 

equipment or, for some sources, fuel switching may not be a reasonable or practical 

alternative to meeting emission limits. One SER suggested that EGUs at sites hampered by 

physical site constraints may need a limit higher than MACT (i.e., a limit that can be met 

using a control device that would fit in the physical constraints of the site). SERs believe that 

small entities with few units should be given additional time to comply with new 

requirements in order to account for their disadvantage in competing with large electric 

generating providers for equipment and skilled labor resources in a severely tight compliance 

timeframe. SERs believe that the most competitive pricing and attention will go to the 

large-scale accounts due to the limited number of manufacturers. In his written comments, 

one SER estimated that it will take a minimum of one year to obtain financing and suggested 

that the U.S. Department of Agriculture’s Rural Utilities Service (RUS) electric loan policy 

be changed to allow loans for coal-fired projects to meet environmental regulations. Another 

SER estimated that six months will be needed to obtain funding through municipal bonds 

once the project cost is known. One SER recommended that small entities be given an 

additional three years to install the required emission controls. Another SER recommended 

that consideration be given to an approach that requires the largest emitters to install control 

technology first, followed by a second phase for moderate emitters, and, lastly, followed by a 

third phase for the lowest emitters. One SER recently investigated converting a hot side 

electrostatic precipitator (ESP) to a fabric filter, and their analysis concluded that it would 

take a minimum of 40 months to complete the project (not accounting for the need to 

compete for resources). 

One SER pointed out that, with respect to fuel switching, sources without 

transportation infrastructure to unload coal via railroad or that are not on a navigable 

waterway are at a significant disadvantage as compared to sources that receive coal via 

railroad or river/ocean barge. In addition, it is unknown whether a replacement fuel could be 

used without a major modification of a boiler that was built to handle a specific coal rank. 

The SER recommended that the MACT standard not be finalized in a manner that would 

effectively require a fuel change (blending or completely), especially for mine mouth coal 

electric generating stations. 

One SER stated that energy optimization should be incorporated in the Utility 

NESHAP. EPA should include guidelines and a project specific list of process changes and 

modifications that will not trigger NSR. The SER further explained that the ambiguity of 

what triggers NSR and the litigious atmosphere surrounding boiler upgrades provides a 

disincentive for utility efficiency improvements. 

8.10 Concerns with the Small Business Advocacy Review Process 

 

In written comments, SERs stated that they do not believe they were provided the 

opportunity for effective participation in the Federal regulatory process as required by 
27 

SBREFA. Specifically, SERs indicated that they were not provided descriptions of 

significant alternatives to the proposed rule, differing compliance or reporting requirements 

or timetables that take into account the resources available to small entities, and the 

clarification, consolidation, or simplification of compliance and reporting requirements for 

small entities. SERs further indicated that there was no pre-meeting to go over information 

on the rule, there was only one outreach meeting, and SERs were only provided 14 days to 

prepare written comments. Thus, the highly abbreviated small business review panel 

prevents small entities from having the meaningful advisory role contemplated by SBREFA. 

SERs requested that EPA schedule additional panel meetings once the Agency has 

progressed further in its rulemaking preparation. One SER indicated that EPA should 

consider starting over with the SBREFA process. Another SER recommended that EPA 

request an extension from the court deadline to allow time to (1) adequately analyze lessons 

learned in the Boiler MACT rule development process, (2) thoroughly analyze the emissions 

data, (3) continue to meet with utility industry representatives, and (4) consider the range of 

possible emission control options that would allow for implementation to take place such that 

the integrity of the Grid, the national economy, and national security will be protected. 

9. PANEL FINDINGS AND DISCUSSION 

9.1 Number and Types of Entities Affected 

In general, SERs believe that more small entities than those estimated by EPA will be 

impacted by the Utility NESHAP. SERs representing public power entities made the point 

that joint action agencies could be small entities potentially impacted by the Utility 

NESHAP. SERs representing cooperatives pointed out that a large number of small 

distribution cooperatives that own generation cooperatives also could be potentially impacted 

by the NESHAP. 

With regard to the SERs’ comment that joint action agencies also could be small 

entities potentially impacted, the Panel notes that two joint action agencies, Municipal 

Energy Agency of Nebraska and Southern Minnesota Municipal Power Agency, are included 

on the list of potentially impacted small entities. The RFA guidance directs EPA to estimate 

direct impacts at the highest level of ownership (i.e., holding company) rather than at the 

subsidiaries/member level. Even if impacts were estimated at the member level for these two 

organizations, the potential impacts would be far less because the overall impacts on each 

joint action agency would be divided among the total number of members. 

Regarding cooperatives, SERs indicated that there are small entity distribution 

cooperatives that own G&T entities that could be potentially impacted. The Panel notes that 

because transmission processes will not be regulated by the Utility NESHAP, impacts to 

entities that own those processes cannot be accounted for in the small entity analysis. Thus, 

if a small entity distribution cooperative owns transmission processes, the impacts for the 

NESHAP are indirect in nature and not accounted for in the small entity analysis. The Panel 

acknowledges that small entity distribution cooperatives that own generation processes 

would be impacted in some way by the Utility NESHAP because generation processes will 

be regulated by the standards, but the extent to which small entity distribution cooperatives 
28 

would be impacted is unclear without more detailed information on these entities. It should 

be noted that some small entity distribution cooperatives own small entity generation 

cooperatives, but other small entity distribution cooperatives own generation cooperatives 

that are not small entities, or other distribution cooperatives that are not small entities own 

small entity generation cooperatives. 

For an estimate of the type and number of small entities to which the proposed rule 

will apply, see Section 5. 

9.2 MACT Floors and Variability 

SERs raised four issues with respect to determining MACT floors and assessing 

variability: (1) pollutant-by-pollutant ranking approach, (2) pollutants to be regulated, (3) 

floor determination methodology for existing units, and (4) assessment of emissions 

variability, including periods of startup and shutdown, and fuel, performance, and load 

variability. We lay out our recommendations for each of these issues in succession below. 

SERs stated that the end result of determining a MACT floor for each HAP or HAP 

surrogate (a pollutant-by-pollutant approach) for each subcategory of sources is a set of 

MACT floors that do not represent the emission levels achieved by an actual, bestperforming EGU. SERs believe that this methodology for setting MACT floors is 

inconsistent with the requirements of CAA section 112(d)(3). 

Panel Recommendations

EPA recommendation: Consistent with EPA’s legal interpretation, EPA panel members 

recommend that the Agency use the pollutant-by-pollutant approach for determining MACT 

standards for each HAP or HAP surrogate, while taking into account potential direct conflicts 

between pollution control technologies 

As noted above, there are concerns with respect to the suggestion that MACT floors should 

be established using a facility-wide approach. Determining floors based on a facility-wide 

approach would lead to least common denominator floors – that is floors reflecting mediocre 

or no control, rather than performance which, for existing sources, is the average of what the 

best performing sources have achieved. For example, if the best performing 12 percent of 

facilities for HAP metals did not control organics as well as a different 12 percent of 

facilities, the floor for organics and metals would end up not reflecting best performance. 

This fact pattern has come up in every rule where EPA investigated a facility-wide approach. 

See, e.g. 75 FR at 54999 (Sept. 10, 2010). Thus, utilizing the single-facility theory proffered 

by the stakeholders would result in EPA setting the standards at levels that would, for some 

pollutants, actually be based on emissions limitations achieved by the worst-performing unit, 

rather than the best-performing unit, as required by the statute. Moreover, a single-facility 

approach would require EPA to make value judgments as to which pollutant reductions are 

most critical in working to identify the single facility that reduces emissions of HAP on an 

overall best-performing basis. 
29 

OMB and SBA recommendation: OMB and SBA recommend that in the proposed rule, EPA 

seek comment on reasonable alternative approaches to setting the MACT floor, which 

account for achievement in practice for control of all HAP. 

SERs stated their belief that the Utility NESHAP should be limited to mercury 

control only. They explained that EPA has not determined that emissions of other HAP in 

the quantities emitted are detrimental to human health or the environment. SERs continue to 

support EPA’s 2004 legal analysis that stated EPA believed it only had authority to set 

MACT standards for mercury under CAA section 112(d). 

Panel Recommendations

EPA recommendation: As to the comment that EPA should only regulate mercury from 

coal-fired EGUs and nickel from oil-fired EGUs consistent with the reasoning in the 

proposed NESHAP for these sources that was published on January 30, 2004, EPA panel 

members note that the Agency never finalized that proposed interpretation, and the Agency 

has determined that it must establish CAA section 112(d) standards for all HAP emitted from 

major source EGUs consistent with the statute and case law from the Court of Appeals for 

the D.C. Circuit. Specifically, CAA section 112(n)(1)(A) requires EPA to regulate EGUs 

"under this section [112]" if the Agency determines that regulation is appropriate and 

necessary. Sources are regulated under CAA section 112 consistent with the requirements of 

CAA sections 112(d) and (f). The D.C. Circuit has stated, on more than one occasion, that 

EPA must establish MACT standards for each listed HAP emitted by major sources, the most 

recent pronouncement coming three years after the proposed NESHAP for EGUs. See Sierra 

Club v. EPA, 479 F.3d 875, 883 (D.C. Cir. 2007). (“EPA has a ‘clear statutory obligation to 

set emission standards for each listed HAP,’ which does not allow it to ‘avoid setting 

standards for HAPs not controlled with technology.’” quoting Nat’l Lime Ass’n v. EPA, 233 

F.3d 625, 634 (D.C. Cir. 2000)); see also Natural Resources Defense Council v. EPA, 489 

F.3d 1364, 1371 (D.C. Cir. 2007) (affirming that EPA must establish emission standards for 

listed HAP emitted from a category, citing Sierra Club and National Lime). For these 

reasons, EPA rejects the proposed interpretation set forth in the 2004 proposed rule. 

OMB and SBA recommendation: OMB and SBA recommend that in the proposed rule, EPA 

seek comment on the specific elements of the 2004 legal analysis and how subsequent court 

decisions affect that 2004 legal analysis. 

Panel Recommendation: The Panel recommends that the analysis of impacts be able to 

distinguish the marginal costs and benefits of each required control technology, in order for 

the public to distinguish the impacts of regulating mercury from the impacts of regulating 

other HAPs. It should be noted that EPA cannot, at this point, estimate monetized benefits 

for HAP reductions other than Hg. 

In addition, by focusing on one HAP at a time, SERs believe that the antagonistic 

effects a given HAP limit will have on other regulated pollutants are missed. Because 

production of CO during the combustion process is inversely related to NOX production, it 

may be difficult to meet a CO limit if NOX reductions also are required. 
30 

Panel Recommendation: The Panel recommends that the Agency investigate other potential 

surrogate pollutants for organic HAP (e.g., PAH, formaldehyde). The SERs’ example of 

how a pollutant-by-pollutant approach could result in technical infeasibility with respect to 

CO and NOX may argue against using CO as the surrogate pollutant for organic HAP. 

SERs commented that the MACT floor for existing units should be determined using 

the entire inventory of EGUs and not using only the units for which EPA has test data. 

Panel Recommendations

EPA recommendation: The CAA requires the MACT floor for existing sources be based on 

the best performing sources. Thus, EPA must be able to show that the best performing units 

are in fact used to establish the MACT floor. To use the entire inventory of EGUs as the 

basis for determining the average of the best performing 12 percent of units, EPA must be 

confident that the EGUs for which data are available are the best performers. EPA panel 

members recommend that the Agency establish the MACT floors using all the available ICR 

data that was received to the maximum extent possible consistent with the CAA 

requirements. 

 

OMB and SBA recommendations: OMB and SBA recommend that EPA establish MACT 

standards that minimize the burden on small businesses. OMB and SBA also recommend 

that EPA consider, and present for comment, MACT floors based on the best performing 12 

percent, rather than the best 12 percent of the data EPA collected. If EPA proposed the latter, 

OMB and SBA recommend that they clearly explain why the subset of sources for which 

they have data is representative of the entire set of sources. 

SERs asked that EPA consider establishing percent reduction limits as an alternative 

to complying with an emissions limit as a means of providing small entities flexibility in 

complying with the NESHAP in addition to providing a means of potentially accounting for 

variability. SERs expressed concern that periods of startup and shutdown could present 

problems with meeting emission limits and suggested that the emissions limits be based on a 

longer averaging time rather than basing limits on 3-run averages. SERs stated that the threeday stack sampling required by EPA’s ICR provides a snapshot of a unit’s HAP emissions 

and is not indicative or representative of the unit’s emissions over longer periods of time. 

SERs pointed out that a critical question is how EPA plans to modify the stack emissions 

reported during the ICR to account for fuel, performance, and load variability. One SER 

suggested that use of a longer-term rolling average (i.e., a 12-month minimum rolling 

average) is necessary in order to account for varying levels of mercury in fuel. Additionally, 

one SER indicated that a de minimis exemption is a regulatory option/small entity flexibility 

that EPA should consider. 

Panel Recommendations

EPA recommendations: EPA is limited in its ability to establish percent reduction limits as 

an alternative to complying with an emissions limit. Even assuming that EPA can establish 
31 

percent reduction standards under CAA section 112, to establish such standards, emissions 

data for the inlet to the EGU and for the stack are necessary. At this time, EPA does not have 

such data. EPA panel members recommend that the Agency consider the inclusion of 

percent reduction standards given the legal constraints and the lack of data necessary to 

establish such standards. Regarding the SERs’ concerns with meeting emissions limits 

during periods of startup and shutdown, EPA panel members recommend that the Agency 

base the proposed emission limits on reasonable averaging times where appropriate. In 

determining reasonable averaging times, EPA panel members recommend that in addition to 

considering performance during periods of startup and shutdown, the Agency also consider 

fuel and load variability. In addition, EPA panel members recommend that the Agency use 

all data gathered through the ICR for EGUs that comprise the MACT floor, to the maximum 

extent possible consistent with the CAA requirements and as appropriate, in order to account 

for fuel, performance, and load variability. With regard to one SER’s request that a de 

minimis exemption be considered, EPA must establish standards for all HAP emitted from 

major sources consistent with CAA section 112(d) and case law from the U.S. Court of 

Appeals for the D.C. Circuit. See Sierra Club v. EPA, 479 F.3d 875, 883 (D.C. Cir. 2007) 

(“EPA has a ‘clear statutory obligation to set emission standards for each listed HAP,’ which 

does not allow it to ‘avoid setting standards for HAPs not controlled with technology.’” 

quoting Nat’l Lime Ass’n v. EPA, 233 F.3d 625, 634 (D.C. Cir. 2000)); see also Natural 

Resources Defense Council v. EPA, 489 F.3d 1364, 1371 (D.C. Cir. 2007) (affirming that 

EPA must establish emission standards for listed HAP emitted from a category, citing Sierra 

Club and National Lime). 

Panel recommendations: The Panel recommends that EPA propose provisions for emissions 

averaging between units at a facility and long averaging times to address startup, shutdown, 

and fuel variability for the proposed emissions limit and, further, that the Agency solicit 

comment on an appropriate averaging time. The Panel recommends that EPA consider fuel 

variability when deriving the emissions standards. The panel members recommend that the 

Agency evaluate whether establishing work practice requirements during periods of startup 

and shutdown would be consistent with CAA section 112(h) and investigate whether there 

are technical bases for establishing separate standards (e.g., work practices or 

subcategorization) for EGUs below a certain size and what that size threshold is. 

9.3 Monitoring, Reporting, and Recordkeeping 

In general, SERs recommended that monitoring, reporting, and recordkeeping 

requirements should be minimized and simplified to the maximum extent possible. SERs 

specifically expressed concern with potential requirements under the Utility NESHAP that 

CEMS be used. 

Panel Recommendations

EPA recommendations: EPA panel members recommend that the Agency consider 

proposing alternative monitoring approaches (e.g., parameter monitoring in lieu of requiring 

the use of mercury CEMS, sorbent traps, periodic stack testing, etc.) and consider requiring 

PM CEMS only for the largest EGUs or allow use of PM CEMS as an alternative to 
32 

conducting opacity monitoring and periodic emissions testing. With respect to SERs’ 

suggestion that if PM CEMS are required by the Utility NESHAP, opacity monitoring 

requirements of other Federal regulations should no longer apply, EPA panel members 

recommend that the Agency consider the available alternatives and options to the current 

opacity provisions. 

OMB recommendations: OMB recommends EPA propose alternative monitoring 

approaches (e.g., parameter monitoring in lieu of requiring the use of mercury CEMS, 

sorbent traps, periodic stack testing) for small entities and that EPA propose PM CEMS only 

for the largest EGUs or propose allowing use of PM CEMS as an alternative to conducting 

opacity monitoring and periodic emissions testing. 

SBA recommendations: SBA agrees that EPA should consider relevant factors identified by 

the SERs in developing this rulemaking, but it does not believe that the Panel has sufficient 

information to make recommendations beyond EPA's existing obligations under the RFA or 

Paperwork Reduction Act. SBA agrees that these are flexibilities worthy of consideration, 

and perhaps proposal, but without information necessary to evaluate specific regulatory 

alternatives or the impacts of those decisions on particular small entities or small entities in 

general, SBA believes that the Panel can make no recommendations as to what specific 

regulatory options would "accomplish the stated objectives of applicable statutes and which 

minimize any significant economic impact of the proposed rule on small entities." 

9.4 Subcategorization 

In general, SERs encouraged the broad use of subcategories. SERs commented that 

EPA should consider subcategorizing EGUs based on fuel type, boiler type, duty cycle, and 

size. Some SERs requested that EPA consider establishing a subcategory for combined heat 

and power (CHP) units that meet the definition of EGU (i.e., generate enough electricity). 

SERs explained that the duty cycles for some coal-fired EGUs are not primarily base-load, as 

in the past, but may alternate between operating as base-load units and peaking units. 

Similar comments were not made with regard to consideration of base-load oil-fired EGUs 

and peaking oil-fired EGUs as separate subcategories. 

Panel Recommendations

EPA recommendations: EPA recognizes subcategorization may be necessary and we will 

consider whether subcategorization is reasonable in light of the data and other information 

obtained in response to the ICR to the utility industry and the information from the SERs. 

SERs recommended that EPA consider adopting the following subcategories for EGUs: 

 Fuel type 

► North Dakota lignite 

► Gulf Coast lignite 

► Bituminous coal 

► Sub-bituminous coal 

► Blended bituminous/sub-bituminous coal 
33 

► Powder River Basin coal 

► Illinois Basin coal 

 Boiler design 

► Units designed to burn coal 

► Units designed to burn oil 

► IGCC units 

► CHP units 

► Units designed to burn multiple fuels 

 Unit type 

► Fluidized bed 

► Pulverized coal 

► Wall-fired 

► Tangentially-fired 

 Duty cycle 

► Base-load oil-fired units 

► Peaking oil-fired units 

► Base-load coal-fired units 

► Coal-fired units that alternate operating as base-load and peaking 

 Boiler class 

► Small entity non-profit providers 

EPA and OMB recommendations: EPA panel members and OMB acknowledge that it may 

not be practicable to adopt all of the proposed subcategories, as there may be substantial 

overlap between the groups. EPA panel members and OMB recommend that EPA consider 

these subcategories and adopt a set of standards that is consistent with the CAA and which 

effectively reduces burden on small entities. 

SBA recommendations: SBA agrees that EPA should consider various subcategorization 

options in developing this rulemaking, but it does not believe that the Panel has sufficient 

information to recommend a particular subcategorization option that would minimize the 

significant economic impact of the proposed rule on small entities. While a large number of 

subcategories may serve to establish standards that minimize the economic impacts on some 

particular small entities, it could also disadvantage small entities that would otherwise be 

among the best performing 12 percent of a larger subcategory. 

9.5 Area Source Standards 

SERs suggested that EPA establish separate emission standards for EGUs located at 

area sources of HAP and that the standards be based on GACT as allowed under section 

112(d)(5) of the CAA. Specifically, SERs recommended that EPA establish management 

practice standards for natural area source EGUs as well as synthetic area source EGUs. 

Panel Recommendations

EPA recommendations: EPA panel members recommend that the Agency consider a 

regulatory approach for EGUs at area sources of HAP based on GACT. Further, EPA panel 
34 

members recommend that the Agency consider establishing management practices for area 

source EGUs pursuant to CAA section 112(d)(5). 

OMB recommendations: OMB recommends that EPA propose a regulatory approach for 

EGUs at area sources of HAP based on GACT and propose management practices for area 

source EGUs. 

SBA recommendations: SBA agrees that EPA should consider the use of its authority to 

establish area sources standards for natural and synthetic area sources to the maximum extent 

permitted by statute, but does not believe that the Panel has sufficient information to 

recommend a particular regulatory option that would minimize the significant economic 

impact of the proposed rule on small entities. 

 9.6 Work Practice Standards

 SERs recommended that EPA establish work practice standards for major source 

EGUs. A work practice standard, instead of MACT emission limits, may be proposed if it 

can be justified under section 112(h) of the CAA that it is not feasible to prescribe or enforce 

an emission standard (i.e., the application of measurement methodology to a particular class 

of sources is not practicable due to technological and economic limitations). Specifically, 

SERs believe it is not feasible to prescribe or enforce an emission standard for control of a 

HAP emitted at or below the detection limit of the method that was used to collect and 

analyze HAP emissions. A number of HAP, including a large percentage of the dioxin/furan 

and non-dioxin organics measurements, are emitted at or below detection limits. 

Panel Recommendations

EPA and OMB recommendation: EPA panel members and OMB recommend that the 

Agency evaluate the availability of work practice standards pursuant to CAA section 112(h), 

in particular with regards to HAP that are emitted at or below the detection limit. 

SBA recommendation: SBA recommends that EPA propose work practices standards 

pursuant to CAA section 112(h) to the maximum extent permitted by statute. However, the 

Panel does not have sufficient information to specify which work practices standards can be 

proposed. 

9.7 Health Based Emission Limits 

SERs commented that HBELs should be used to the maximum extent possible when 

facts support their use. Specifically, SERs encouraged EPA to use its CAA section 112(d)(4) 

authority to set a HBEL for HCl based on its reference concentration for the entire EGU 

source category. 

Panel Recommendations
35 

EPA recommendation: EPA panel members recommend that the Administrator consider her 

discretionary authority to propose a HBEL for acid gas HAP emissions as a regulatory 

flexibility option. 

OMB and SBA recommendations: OMB and SBA recommend that in the proposed rule, 

EPA co-propose and seek comment on an HBEL for HAPs to the maximum extent permitted 

by statute, including, but not limited to, the acid gas HAP. OMB and SBA recommend that 

in the proposal EPA explain their method for deriving these limits, along with sample 

calculations. 

 

9.8 Related Federal Rules 

SERs asked that EPA consider the impact of competing regulatory requirements and 

technologies when developing the Utility NESHAP. EPA is currently working on revisions 

to the PM, SO2, and NOX emissions limit in subpart Da. Sources subject to the NSPS would 

also be subject to the Utility NESHAP because those rules regulate sources of HAP whereas 

the NSPS does not. 

EPA issued a final rule that establishes thresholds for GHG emissions that define 

when permits under the New Source Review PSD and title V Operating Permit programs are 

required for new and existing industrial facilities (the Tailoring Rule). Beginning in January 

2011, large industrial sources, including power plants, became subject to permitting 

requirements for their GHG emissions. 

On December 23, 2010, EPA announced that it entered into a settlement agreement to 

issue rules that will address GHG emissions from fossil fuel-fired power plants. The rules 

would establish NSPS for new and modified EGUs and emission guidelines for existing 

EGUs. Under the agreement, EPA commits to issuing proposed regulations by July 26, 2011 

and final regulations by May 26, 2012. 

SERs expressed concern regarding what the impact of controlling SO2 and NOX

emissions as a result of complying with the Transport Rule will do to the level of CO 

emissions. The Transport Rule, as proposed, would require 31 states and D.C. to 

significantly improve air quality by reducing power plant emissions that contribute to ozone 

and fine particle pollution in other states. Specifically, the proposal would require reductions 

in SO2 and NOX emissions that cross state lines. The Transport Rule is expected to be 

finalized in late Spring 2011 and, to the extent that EGUs are located in the final set of states 

or D.C., they would be subject to the Transport Rule. 

Based on the findings from EPA’s multi-year study of the Steam Electric Power 

Generating industry, EPA plans to revise the current effluent guidelines that apply to steam 

electric power plants. Revised effluent guidelines will be proposed in July 2012 and 

finalized in January 2014. 

As required by section 316(b) of the CWA, EPA established best technology 

available standards to minimize adverse environmental impacts from cooling water intake 
36 

structures. In developing these standards, EPA divided its effort into three rulemaking 

phases. Phase I standards, for new EGU plants using cooling water, were finalized in June 

2003. Phases II and III standards, which address existing EGU plants that use cooling water, 

were promulgated in July 2004 and June 2006, respectively. Both regulations were 

challenged. Several provisions of the Phase II rule were remanded and EPA suspended most 

of the rule in response to the remand. EPA requested, and was granted, a partial remand of 

the Phase III rule. EPA signed a settlement agreement that requires regulations for Phase II 

and III facilities to be proposed by March 14, 2011, and promulgated by July 27, 2012. 

In June 2010, EPA proposed national rules for the management of coal ash, which are 

residues from the combustion of coal in power plants that are captured by pollution control 

technologies, like scrubbers. EGUs will be subject to these coal ash specific regulations 

when they are issued. 

Panel Recommendations

SBA recommendations: SBA agrees that EPA should consider relevant factors identified by 

the SERs in development of this rulemaking, including the extent to which other recently 

proposed or finalized regulatory obligations imposed by EPA will impact small entities or 

make compliance with this rulemaking more difficult. However, SBA does not believe that 

the Panel has information necessary make recommendations beyond a restatement of EPA’s 

existing obligations or to evaluate specific regulatory decisions and the impacts of those 

decisions on particular small entities or small entities in general. Therefore, SBA believes 

that the Panel can make no recommendations as to what specific regulatory options would 

"accomplish the stated objectives of applicable statutes and which minimize any significant 

economic impact of the proposed rule on small entities." 

Panel recommendations: Although the requirements of section 112 of the CAA direct EPA 

to establish NESHAP for both major and area sources of HAP and prescribe the processes by 

which the standards are developed, the Panel recommends that the Agency consider the 

various flexibilities within its discretion in developing the proposed standards. The Panel 

recommends that the Agency investigate other potential surrogate pollutants for organic HAP 

in lieu of CO, given the NOX-CO relationship (i.e., when NOX emissions are reduced, CO 

emissions may increase). In developing the NESHAP for EGUs, the Panel recommends that 

the Agency avoid duplicating requirements to the fullest extent possible in order to minimize 

unnecessary costs. 

9.9 Potential Adverse Economic Impacts

SERs commented on a number of concerns they have with respect to small entities’ 

ability to comply with the potential requirements of the Utility NESHAP. SERs inquired as 

to EPA’s authority to (1) move the effective date of the standards, (2) determine when 

implementation begins, (3) allow a phase-in of compliance, and (4) streamline the process for 

petitioning for a fourth year for purposes of complying with the standards. SERs asked that 

EPA consider the implications of EGU reliability versus compliance with the Utility 

NESHAP when establishing the rule’s requirements. SERs expressed concern that, 
37 

depending on the type and stringency of requirements, the regulations could be so expensive 

that they cause extensive plant retirements and job losses. 

Panel Recommendations

SBA recommendation: SBA recommends that EPA propose a streamlined process for 

granting a fourth year, including aiding small entities in gathering the information necessary 

to support such a petition, and recommends that EPA develop, in consultation with the 

Department of Defense and small entities affected by this rule, to develop the information 

necessary to support a recommendation under section 112(i)(4) of the CAA for consideration 

by the President. 

Panel recommendations: The Panel recommends that the Agency weigh the potential burden 

of compliance requirements and consider various options for all regulated entities, especially 

small entities. With respect to dates, EPA does not have the authority to move the effective 

date of the standards (see CAA section 112(d)(10)), to initially provide more than three years 

for compliance (see CAA section112(i)), or to allow a phase-in of compliance. The Panel 

recommends that the Agency investigate the potential for streamlining the process for 

petitioning for a fourth year for purposes of compliance with the standards and consider the 

need to invoke the national security exemption under section 112(i)(4) of the CAA. 

Additionally, the Panel recommends that EPA seek comment in the proposed rule on the 

potential adverse economic impacts of the rule for small entities and recommendations for 

mitigating or eliminating these adverse economic impacts on small entities. 

9.10 Concerns with the Small Business Advocacy Review Process

 

SERs stated that they do not believe they were provided the opportunity for effective 

participation in the Federal regulatory process as required by SBREFA. SERs indicated that 

they were not provided descriptions of significant alternatives to the proposed rule, differing 

compliance or reporting requirements or timetables that take into account the resources 

available to small entities. SERs further indicated that there was no pre-meeting to go over 

information on the rule, there was only one outreach meeting, and SERs were only provided 

14 days to prepare written comments. SERs had various suggestions including that EPA 

schedule additional panel meetings once the Agency has progressed further in its rulemaking 

preparation, that EPA consider starting over with the SBREFA process, and that EPA request 

an extension to allow time to (1) adequately analyze lessons learned in the Boiler MACT rule 

development process, (2) thoroughly analyze the emissions data, (3) continue to meet with 

utility industry representatives, and (4) consider the range of possible emission control 

options that would allow for implementation to take place such that the integrity of the Grid, 

the national economy, and national security will be protected. 

Panel Recommendations

EPA recommendation: EPA appreciates the SERs’ concerns, but believes that it has fulfilled 

its statutory obligations under SBREFA and has afforded SERs sufficient opportunity to 

suggest regulatory alternatives, and thus, makes no recommendations to address these 
38 

concerns. The time constraints of the small business advocacy review process with respect to 

the Utility NESHAP were explained at the beginning of the process. That is, due to the 

regulatory schedule there could only be one SER outreach meeting. The nature of the 

information to be provided was also outlined to the SERs at the start of the process. EPA 

believes that it has provided sufficient information to allow SERs to make suggestions 

concerning regulatory alternatives (e.g., regarding subcategories, HAP and HAP surrogates, 

monitoring requirements, control technologies potentially required to meet standards, CAA 

authorities to establish health-based emission limits and work practice standards) as part of 

the small business advocacy review process, and the SERs have in fact made many 

productive suggestions EPA will seriously consider as part of the rulemaking process. 

OMB recommendation: Although OMB understands the time constraints imposed on this 

rulemaking process, we recommend that once EPA has drafted a set of emissions limits for 

EGUs, they convene another meeting with the SERs to gather insight on the feasibility and 

achievability of those limits for small entities. To the extent feasible, we recommend this 

meeting take place before the proposal is issued. 

SBA recommendations: SBA agrees with the concerns raised by the SERs in their comments 

about the adequacy of the information provided to the Panel and the SERs and about the 

schedule for the Panel. SBA believes that more time is necessary for EPA to develop 

regulatory options and to share them with the SERs, so that the SERs could provide a more 

informed comment and better inform the Panel's recommendations. 

SBA recommends that EPA request an extension of the regulatory deadlines imposed by the 

consent decree. The extension should provide enough time for EPA to: 

 Analyze fully the results of the ICR and other data necessary to understand the 

emissions characteristics of the regulated entities; 

 Develop a robust range of specific regulatory options; 

 Consult with the SERs and provide an additional opportunity for the SERs to provide 

input on the regulatory options; and 

 Allow for the full interagency review required by Executive Order 12866 and 13563. 
39 

Appendix A 

List of Materials EPA Shared With SERs 

(November 2010)

• PowerPoint Presentation entitled “Rulemaking for Hazardous Air Pollutants from Coal-and 

Oil-Fired Electric Utility Steam Generating Units” including: 

• Background 

• Project history 

• Section 112 overview 

• Constraints on rulemaking 

• Affected facilities 

• Data 

• Rulemaking options under consideration 

• Potential control technologies and estimated costs 

• Applicable small entity definitions 

• Small entities potentially subject to regulation 

• Questions for SERs 
40 

Appendix B

Questions for SERs 

Directed Questions for SERs 

Affected Entities 

1. Is EPA’s list of potentially affected small entities on slide A-4 of this presentation 

accurate? If not, do you have suggested additions or deletions? Could you briefly 

explain the reason for each addition or deletion. 

Firm Characteristics

 

1. How many units do you have in your facility or facilities? 

2. What is the capacity of your installed units? 

3. What duty cycles do they run? 

Existing Standards

General: 

1. What Federal/State/local standards are your EGUs currently subject to? 

2. What compliance requirements are associated with the other standards that apply to 

your EGU? 

3. What emissions control technologies do you have installed at your facilities? Under 

what regulatory requirements are they installed? What did they cost to install? To 

operate? 

Recordkeeping and Reporting: 

1. What recordkeeping and reporting requirements are you subject to under other 

standards that apply to your EGU? 

2. Are there recordkeeping and reporting alternatives that would simplify the 

requirements? 

Monitoring: 

1. Do you employ any monitors, for emissions or process parameters, to monitor the 

operation of your EGU? 

2. What type of monitors and how many? 

3. What were the capital costs and what are annual costs for each monitor? 

4. Are these monitors in place for environmental regulatory reasons, insurance reasons, 

or other reasons? 

5. Did you provide any of the monitoring data to the Agency during the recent 

Information Collection Request on Utility Boilers or another information collection 

request? 
41 

6. If your EGU is subject to emission limits, are there alternatives to monitoring 

emissions or stack testing that would be less costly to demonstrate compliance and, if 

so, how much less costly are the alternatives? 

 

Energy Efficiency: 

1. Do you employ measures to ensure that your EGU operates in an energy efficient 

manner? 

2. What are the energy efficient measures you employ? 

3. Are these measures a result of regulatory requirements, initiated voluntarily, or 

employed for other reasons? 

4. What are the estimated emissions reductions associated with the energy efficient 

measures? 

5. What are the costs of implementing the energy efficient measures? 

Regulatory Alternatives

General: 

1. What types of subcategories based on class, type, or size do you think EPA should 

consider and why? 

2. What surrogate standards do you think are appropriate? 

3. What means of determining variability do you think EPA should consider? 

Work Practice Standards: 

1. Which subset(s) of HAP from EGUs, if any, do you think would meet the CAA 

section 112(h) requirements for establishing work practice standards in lieu of 

emission limits and what is the basis for your assertion? 

2. What work practice standards are available to you? 

3. What work practice standards would you consider to be reasonable alternatives to 

emission limits? 

4. What are the costs of those work practices? 

Health-Based Emission Limits: 

1. Do you have the information that would support considering setting health-based 

emission limits under CAA section 112(d)(4) for HAP emissions from EGUs? For 

example, facility-wide HAP emissions, facility configurations, overall fence-line 

characteristics, population proximity to plant, potential adverse environmental effects 

that would otherwise be reduced or eliminated. 

Other Potential Options/Flexibilities: 

1. Are there other regulatory options or small entity flexibilities that EPA should 

consider? 

Cost Estimates

Control Technology: 
42 

1. If you employ any of the control technologies listed on slide 26 of the outreach 

presentation as potentially being required to meet the Utility NESHAP, indicate the 

type of control, its size (e.g., the size EGU that the control is associated with, the 

exhaust gas flow rate being routed through the control), what the capital costs were, 

and what the annual operating costs are. 

2. Do you agree with the control technology and monitoring cost estimates presented on 

slide 27 of the outreach presentation? ? If not, provide your cost estimate(s) along 

with the source(s) of your estimate(s). 

3. Do you employ other control or monitoring technologies that EPA should consider 

when estimating the impacts of the standards? If so, indicate the type of control or 

monitor, the size boiler it is associated with, what the capital costs were, and what the 

annual operating costs are. 

Financial and Production Impacts: 

1. In ideal circumstances, how long would your facility require to finance and install 

new emissions control and monitoring equipment? 

2. How long would be required if there were other regulations requiring similar 

investments that had to be implemented consecutively? 

3. How would new emissions requirements affect your production capacity? 

Other Regulatory Requirements: 

1. Are there other regulatory requirements that could conflict with new emissions 

standards? 

2. Are there other regulatory requirements that could increase the cost of compliance 

with new emission standards? 

Capital Availability: 

1. How does your entity acquire money for capital investments? Is it primarily through 

equity? Or debt? Or a combination of both? 

2. Are you an independent power producer? 

3. Is your entity regulated by a State or local utility commission, or does it operate in 

competitive markets? 

If you had to install additional control equipment that required capital investment, 

would you adjust the rate charged to your customers? 

4. What is the process for adjusting the rate? 

5. What is the expected time for that change to occur? 

6. What are the limits on how much you can raise rates? 

7. What other constraints exist on your ability to raise capital or fund capital investment 

for regulatory compliance?
Appendix C 

Written Comments Received from SERs 

1. Alan Bonderman, Atlantic Municipal Utilities, Atlantic, IA

2. Erik Booth, Marquette Board of Light & Power. Marquette, MI

3. Donald Pauken, Muscatine Power & Water, Muscatine, IA

4. Joe Eutizi, San Miguel Electric Cooperative, Inc., Christine, TX

5. Ken Bapp, Texas Municipal Power Agency, Bryan, TX

6. Robert Tondu, Tes Filer City Station Power Plant - Tondu Corp., Houston, TX

7. James R. French, Wyandotte Municipal Services, Wyandotte, MI

Written Comments Received from non-SER Participants 

8. Theresa Pugh, American Public Power Association (APPA) 

9. Bill Wemhoff, National Rural Electric Cooperative Association (NRECA) 
Comments - Utility MACT - Small Business Review Panel

ABonderman 

to: 

Madeline Barch 

12/16/2010 03:19 PM 

Cc: 

RobertJ Wayland, David.rostker, Mary Johnson, Cortney_Higgins 

Show Details 

History: This message has been replied to and forwarded. 

Ms. Barch: 

 

Attached are comments from Atlantic Municipal Utilities, regarding the promulgation of regulations for 

control of hazardous air pollutants, referred to as the “Utility MACT” rules. 

 

 

Allen Bonderman

General Manager

Atlantic Municipal Utilities

15 West Third Street

P.O. Box 517

Atlantic, IA 50022‐0517

Tel. 712‐243‐1395

Fax 712‐243‐2028

email ABonderman@amu1.net

 

 

Page 1 of 1

file://C:\Documents and Settings\mbarch\Local Settings\Temp\notesFCBCEE\~web3790.htm 1/6/2011
Atlantic Municipal Utilities - 15 West 3rd Street - Atlantic, IA 50022 - Tel. (712) 243-1395 - Fax (712) 243-2028

AMU

Atlantic Municipal Utilities

Madelyn Barch

Regulation Management Division

Office of Policy

U.S. EPA

barch.madeline@epa.gov

Re: Small Business Review Panel for the Electric Generating Unit Hazardous Air 

 Pollutant Emission Standards

I appreciate the opportunity to comment regarding EPA’s rulemaking to set maximum achievable 

control technology (“MACT”) standards for hazardous air pollutant (“HAP”) emissions from coal- and oilfired electric utility steam generating units (“EGUs”). I was listed as a participant on the panel 

convened under the Small Business Regulatory Enforcement Fairness Act of 1996 (SBREFA SER 

panel).

Atlantic Municipal Utilities (AMU) is a small municipally-owned utility system, serving some 4,300 

electric and 3,300 water customers, in and near the community of Atlantic, Iowa. Atlantic is located in 

southwest Iowa, and has a population just over 7,000. AMU has a total annual peak of 26 megawatts, 

and retail sales just over 100 million kilowatthours.

Our power supply resources consist of a purchase power agreement with Western Area Power 

Administration (WAPA) for deliveries of about 7 megawatts summer, and 5 megawatts winter. We are 

a minority owner (2.5%) in a 690 MW coal-fired plant called Walter Scott Unit 3, located near Council 

Bluffs, Iowa, which provides us with 17 megawatts of capacity. All additional power needs are satisfied 

through a power purchase agreement with Missouri River Energy Services (MRES), a municipal joint 

action agency with headquarters in Sioux Falls, SD. Locally, we also own a 4 megawatt dual-fuelled 

Nordberg diesel generator, and a Solar dual-fuelled combustion turbine, which has low-NOx controls.

Our Walter Scott 3 resource has, over the past several years, been upgraded with pollution control 

equipment and systems to decrease emissions, including low-NOx burners, a neural network, scrubber 

and baghouse. Atlantic’s share of these improvements was in the neighborhood of $7 million, which 

exceeded our original investment in the plant back in the late 1970’s. 

As to the MACT standards and SBREFA panel, due to conflicts in my schedule and other workload, I 

was unable to sit in on the meeting via conference call. I did, however, communicate with others on the 

panel, and have received some information and some comments regarding how the session went.
Atlantic Municipal Utilities - 15 West 3rd Street - Atlantic, IA 50022 - Tel. (712) 243-1395 - Fax (712) 243-2028

The EGU MACT rulemaking may be one of the most expensive rulemakings in the history of the electric 

utility industry. Its impact on small systems such as ours could be devastating, as owners of generation 

will be forced to install extensive new pollution control equipment, or to retire units. The SBREFA 

requires that EPA must carefully consider the impact its EGU MACT rule will have on small entities and 

must act to lessen the burden of that rule on those entities. From my perspective, the actions taken 

thus far in no way satisfy that requirement.

The first flaw in the process may be the identification of potential candidates for the Small Business 

Advocacy Review Panel. When telephoned about being selected to participate on this panel, I 

attempted to inform the EPA representative that I was not qualified to serve on a panel such as this, 

due to inadequate knowledge of environmental controls, their costs, and other background related to 

the rulemaking. When I received e-mail correspondence that showed the entire list of candidates, I 

noted that several parties from Iowa were shown as members. Those systems are communities with 

populations of less than 2,000, and the persons named have no more expertise in pollution control than 

I do. I noted participants from similarly sized entities in other states.

Then I discovered that the intention was to hold a single meeting, at which the Agency would explain 

the specific input they wanted, and the format in which their questions should be addressed in filings. A 

great majority of those questions are technical in nature, or require extensive knowledge about costs of 

control technologies. It appeared that few, if any, participants would have that level of knowledge.

Section 609 of SBREFA envisions that small business panels will review “any material the agency has 

prepared in connection with this chapter” including information required to be part of the initial 

regulatory flexibility analysis. A regulatory flexibility analysis typically includes descriptions of 

significant alternatives to the proposed rule, differing compliance or reporting requirements or 

timetables that take into account the resources available to small entities, and the clarification, 

consolidation, or simplification of compliance and reporting requirements for small entities. The SER 

meeting related to these rules involved no preparation and distribution of these clarifications, 

consolidations or simplifications of the EPA regulatory options.

The EPA materials did not include possible rulemaking alternatives, nor any information about possible 

compliance or reporting options. Moreover, the material lacks any results of EPA’s analyses of the data 

from the extensive information collection request (“ICR”) that EPA identified as being critical to the 

promulgation of an EGU MACT rule. It seems obvious that EPA has failed to meet the statutory 

requirements,

As a non-expert, I am unable to address the specific items detailed in the panel’s materials, and which 

were discussed at the meeting. I can, however, and will, make some general comments which do not 

specifically address EPA’s questions.

As a small entity covered under SBREFA, our utility is supposed to receive consideration for any and all 

forms of relief from onerous regulations. AMU is a member of the American Public Power Association 

(APPA), which has also submitted comments. We see APPA as a voice for our system, and for some 

1400 similar small entities, an undetermined number of whom will be directly or indirectly affected by 

the proposed regulations. APPA’s comments should be considered as comments from small entities, 

and APPA should not be precluded as a “viewer” and assigned to the sidelines as a spectator. Doing 

so effectively eliminates any meaningful input from the smallest of the affected entities, who have no 

expertise nor any other means to express their concerns. For a trade association to be disqualified on 

the basis that it itself is not a small business as defined in SBREFA is ridiculous, if not shameful. Who 

else can speak for us?

APPA’s comments, which we completely agree with, include positions such as:
Atlantic Municipal Utilities - 15 West 3rd Street - Atlantic, IA 50022 - Tel. (712) 243-1395 - Fax (712) 243-2028

1.) EPA is not complying with requirements of the Small Business Regulatory Enforcement Fairness 

Act of 1996, for several reasons described in APPA’s filed comments.

2.) Inadequate time was allowed for input from small business.

3.) EPA failed to correctly identify the scope of the HPA’s to be regulated, and did not provide any legal 

analysis for its shift from its 2004 analysis which stated that EPA has authority only to regulate mercury 

emissions from coal-fired EGU’s.

I noted with interest press releases yesterday which stated that on December 7th, EPA announced that 

it had filed a motion in the federal District Court for the District of Columbia. The motion is seeking an 

extension in the current court-ordered schedule for issuing rules that would reduce harmful air 

emissions from large and small boilers and solid waste incinerators. The additional time is needed, the 

agency said, to re-propose the rules based on a full assessment of information received since the rules 

were proposed. Consideration should be given to doing the same with the Utility MACT regulations.

EPA should consider starting over with the SBREF process. The Agency should make a sincere 

attempt to identify participants who not only represent small business but who have sufficient expertise 

– including trade association representation of affected small entities. Sufficient time, and an adequate 

number of meeting opportunities, should be provided so that the participants can provide meaningful 

input. All requirements of the SPREF statute and regulations should be met, not just in spirit, but in 

fact.

Thank you for the opportunity to be heard. 

Allen Bonderman

General Manager

Atlantic Municipal Utilities

15 West Third Street

Atlantic, IA 50022

ABonderman@amu1.net

712-243-1395
RE: EPA Utility MACT Small Entity Outreach Meeting

Erik K. Booth to: Madeline Barch 12/16/2010 11:46 AM

Cc: "Kirby D. Juntila", William Pyle

History: This message has been replied to and forwarded.

Madeline,

Thank you for the opportunity to submit comments (please see attachment) under 

the Small Business Advocacy Review Panel. 

Erik Booth, P.E.

Manager of Utility Compliance

Marquette Board of Light & Power

2200 Wright Street

Marquette, MI 49855

Phone: (906) 228-0335

Fax: (906) 228-0359

email: ebooth@mblp.org

-----Original Message-----

From: Barch.Madeline@epamail.epa.gov [mailto:Barch.Madeline@epamail.epa.gov] 

Sent: Thursday, December 16, 2010 9:41 AM

To: abonderman@amu1.net; bmu@bancroftiowa.com; scott.siddoway@rosi-boise.com; 

rex.butler@cipco.net; crmugas@crmu.net; mike.thatcher@cbpower.coop; 

dhaverland@dutil.com; lopsal@cityofgeneseo.com; dnally@hollandbpw.com; 

skulig@jamestownbpu.com; Erik K. Booth; montelp@zumatel.net; dpauken@mpw.org; 

jeutizi@smeci.net; lhopkins@sipower.org; joe@tonducorp.com; 

kbabb@texasmpa.org; jfrench@wyan.org

Subject: EPA Utility MACT Small Entity Outreach Meeting

Greetings,

This note is a reminder that written comments are due today regarding

the Small Business Advocacy Review Panel for the EPA rulemaking "

National Emission Standards for Hazardous Air Pollutants (NESHAP) for

Coal- and Oil-fired Electric Utility Steam Generating Units."

Please send any comments to me (barch.madeline@epa.gov), and I will

share them with all Panel members. If you plan to send sensitive

information about your company, please clearly mark it as CBI

(Confidential Business Information) so we can handle it appropriately.

Thank you for investing your time and effort to provide us with your

comments and recommendations.

Madeline Barch

Regulatory Management Division, Office of Policy

USEPA #6440EE Ariel Rios North

P: 202.564.0234

F: 202.564.0965

E: barch.madeline@epa.gov
BOARD OF LIGHT AND POWER

CITY OF MARQUETTE

2200 WRIGHT STREET

MARQUETTE, MI 49855-1398

KIRBY D. JUNTILA

EXECUTIVE DIRECTOR

PHONE 906-228-0313

FAX 906-228-0329

PLANT FAX 906-228-0359

Serving Our Community Since 1889

16 December 2010

Re: Small Business Advocacy Review Panel for the National Emission Standards for

Hazardous Air Pollutants (NESHAP) for Coal- and Oil-fired Electric Utility Steam

Generating Units

The Marquette Board of Light & Power was selected on November 17, 2010 to serve as a

Small Entity Representative (SER) to the Small Business Advocacy Review Panel for the

National Emission Standards for Hazardous Air Pollutants (NESHAP) for Coal- and Oilfired Electric Utility Steam Generating Units. The Marquette Board of Light & Power

owns and operates a 44 megawatt pulverized coal-fired boiler and two smaller stokerfired boilers serving turbines less than 25 MW at the Shiras Steam Plant located in

Marquette, Michigan. Our city consists of a population of approximately 21,000 people

with an average household income of $35,000 according to the United States Census

Bureau. Our service area is occupied by mostly residential ratepayers, commercial

facilities, and institutions (the largest two being a hospital and University).

This rule (EGU MACT) along with the Federal Implementation Plans to Reduce

Interstate Transport of Fine Particulate Matter and Ozone (Clean Air Transport Rule), the

National Emission Standards for Hazardous Air Pollutants for Major Sources: Industrial,

Commercial, and Institutional Boilers and Process Heaters (Boiler MACT) , Hazardous

and Solid Waste Management System; Identification and Listing of Special Wastes;

Disposal of Coal Combustion Residuals from Electric Utilities (Coal Ash Disposal Rule),

and the Clean Water Act-Section 316(b) regulations pose a significant financial burden

on non-profit small businesses such as the Marquette Board of Light & Power and small

communities where there is little availability to spread out the cost of compliance.

We have prepared the attached list of comments and concerns that we hope will be

addressed in the proposed rule. We appreciate the opportunity to comment and feel that

reducing hazardous air pollutant emissions is necessary but must be done responsibly,

and in a manner that considers the economic hardships that will be realized in

conjunction with other pending regulatory requirements.

Sincerely,

Erik Booth

Manager of Utility Compliance
Impacts on Small Businesses from Multiple Regulations Proposed Simultaneously

Public power utilities, such as the Marquette Board of Light & Power, are not-for-profit

electric systems owned and operated by the people they serve through a local

government. The Environmental Protection Agency has proposed, within the last couple

of years, a string of rules simultaneously that have tremendous economic impacts on

small public power utilities. Each rule represents a cost burden of millions of dollars

individually. Taken one at a time, compliance with these rules is possible on an

economical basis. However, when the capital cost must be absorbed at once, small nonprofit municipalities and their ratepayers will suffer economic hardships. Municipalities

do not generate profits for shareholders. The municipal rate is set at a level to cover the

cost of service provided. Increased costs cannot be offset by reducing profit margins

because for a municipality there is none. Costs must be passed onto the end user.

The Marquette Board of Light & Power operates a strong competitive business that

providesa“yardstick”forbothconsumers and government officials to measure the cost

of providing wholesale electricity against the rates of local private power companies and

local electric utility cooperatives. Our municipality is located in small community.

Residential ratepayers could not absorb the cost of compliance with these rules if they are

concurrently enacted. Small businesses (such as the local grocery stores, small retailers,

locally owned gas stations, etc) would endure further hardships from a significant

increase in electric rates in an already difficult economic climate. If the EPA continues on

this path of enacting multiple large-scale regulatory requirements, then we strongly urge

you to consider a separate category for small non-profit electric providers.

Timing of Compliance - Inability to Receive Competitive Pricing

If the EGU MACT follows the Clean Air Act section 112(i)(3)(A) timeframe

(compliance within three years from the date the rule is finalized) and is implemented

simultaneously with the Boiler MACT, then the Marquette Board of Light and Power will

be competing with the other 1,200 coal-fired boilers that must comply with the EGU

MACT along with the 578 units designed for coal firing that must comply with the Boiler

MACT (source: pg. 32022 Federal Register/Vol. 75, No. 107/ Friday, June 4, 2010) to

install additional air emission control technologies. Due to the limited number of

manufacturers, the most competitive pricing and attention will go to the large-scale

accounts. Small businesses such as the Marquette Board of Light & Power will not be

able to obtain competitive pricing due to the industry demand on vendors for their

products. This supply demand and limited time for installation must be taken into account

so that small businesses will not be unfairly stuck with a rule that causes an unequal

economic burden. Consideration should be given on the development of a phased (or

staged) approach that require the largest emitters to install control technology,followed

by a second phase for moderate emitters, and lastly followed by a third phase for the

lowest emitters. This will accomplish the goal of reducing pollutants from the largest

sources first and ending with the smallest of emitters.
Timing of Compliance - Inability to Schedule Outages

There will be significant constraint issues with the electric grid if the EPA decides to

proceed with an EGU MACT, which requires all sources to comply within three years

from the date the rule is finalized. This issue will be compounded further if the Boiler

MACT is simultaneously enacted. There will be units that will not be able to schedule the

long term outages necessary to install emission control technologies due to the high

volume of EGU’s that will be competing for an outage schedule. Utilities will be

competing with each other in scheduling outages and the EGU MACT time constraints

will not be flexible enough to take into account the timeframe needed so that each unit

can go down and still satisfy the demands for power. In addition to electric supply

constraints, the Marquette Board of Light & Power has previously had to adjust outage

schedules due to the high demand and low availability of experienced Millwrights. This

demand will increase significantly under the EGU MACT. Compliance within three years

from the date the final rule is published is not achievable due to the competition to

schedule outages while providing enough electricity to satisfy demand along with

balancing the ability to hire experienced Millwrights for installation.

Additional Subcategory for Solid Fuel Boilers

The EPA needs to consider a co-firing subcategory for coal and biomass. A boiler

burning a 50% coal/50% biomass blend may not meet the CO limit for coal (if the EPA

decides to define a coal burning unit as one which burns more than 10% coal). Most

states are moving aggressively to a Renewable Portfolio Standard. We hope that the EPA

takes this into consideration and does not propose a rule that conflicts with the other

national direction of moving away from coal combustion. Essentially, the Boiler MACT

rule as proposed provides no incentive to burn biomass unless a boiler can operate on

biomass alone. Burning biomass alone may not be feasible in existing coal-fired units.

The EPA needs to consider adding a category that offers an incentive to offset the

combustion of coal with biomass meeting limits somewhere between the units designed

to burn coal and units designed to burn biomass. This needs to be taken into consideration

so that the EPA does not implement a rule that would conflict with the Renewable

Portfolio Standards being adopted by many proactive states in an effort to move away

from electricity generated from the combustion of coal.

Particulate Matter (PM) Continuous Emission Monitoring System (CEMS)

Opacity has long been an indicator of good particulate emission controls. Opacity is a

much more economical and proven method of monitoring over a PM CEMS, which

carries an EPA estimated capital investment of $224,000 and annual cost of $63,000. PM

CEMS offers no benefits to units that already have the Best Available Control

Technology (BACT) installed and will already be below the proposed PM limit once

published. Precedent is set from visible emissions limitations currently being used for

compliance determination with particulate emission limits (see Michigan Department of

Environmental Quality Operational Memo No. 14 attached).
Michigan Department of Environmental Quality: Operational Memo No. 14 –May 6,

1997 (page 5).

The EPA estimated annual costs of $48,000-$63,000 for a PM CEMS is more than

double what is currently spent on our annual continuous emission monitoring and

continuous opacity monitoring systems. Installing additional and more burdensome

monitoring puts unnecessary costs burdens to small businesses if compliance could be

verified using more proven and economical options.

Energy Optimization

Energy optimization is a widely popular method of reducing air pollutant emissions and

should be incorporated in the EGU MACT. However, there needs to be some clarity on

the projects that can be completed without fear of litigation. EPA needs to include

guidelines and a project specific list that owners of boilers can use for process changes

and modifications to the facility that will not trigger New Source Review.

As the EPA is most certainly aware, the largest energy optimization steps that can be

made are increasing the efficiency of the combustion units. The biggest gains can be
made be replacing the metal alloys in feedwater heaters, economizers, condenser tubes,

low and high temperature superheaters, install new regenerative air heaters, install more

efficient steam turbine rotors, ect. The ambiguity of the projects that trigger NSR and the

litigious atmosphere surrounding boiler upgrades has provided a disincentive for utility

efficiency improvements. We urge the EPA to take the correct measures to not only set

HAP emission limits, but also to take the substantial steps necessary to ensure that plants

are operating efficiently by providing strong guidance on what repair projects can be

made in the name of energy optimization without fear of NSR litigation. Options such as

performing Energy Star Audits offer little value, even when the cumulative effect is taken

into account, when compared to the cumulative energy efficiency savings that can be

made by upgrading the heat transfer surfaces and process changes in the boilers.

Our concern is that EPA will focus on the nominal energy savings measures such as light

bulb changes, automatic timer switches, or insulation and window replacements while

neglecting the much larger more cumbersome, but significantly more beneficial, energy

efficient projects such as boiler process upgrades that will offer much greater returns and

environmental benefits.
EGU MACT SER Panel - MPW Comments

Don Pauken 

to: 

Bill Maxwell, Mary Johnson, Madeline Barch 

12/16/2010 04:41 PM 

Cc: 

david.rostker, cortney_higgins 

Show Details 

Muscatine Power and Water (MPW) submits the following comments and responses to the "Questions for 

SERs" (See Attachment A).

MPW is a municipal utility that serves the City of Muscatine, Iowa (population 23,000) and certain limited adjacent 

areas with electric, water and telecommunications services. Muscatine is on the eastern side of Iowa along the 

Mississippi River about 200 miles west of Chicago. The utility has three coal fired boilers serving four turbine 

generators and providing process steam to its largest electrical customer. One boiler will be subject to the ICI 

Boiler MACT. The other two boilers will be subject to the EGU MACT.

MPW is a member of the Midwest Independent System Operator. As a participant in this organization, all 

electrical generation is bid into the MISO market and all native system load is purchased from the MISO market. 

MPW energy pricing must be competitive in order to be selected by MISO on a daily basis for supplying energy to 

the MISO region. Revenues from participating in the market contribute to keeping rates low for native system 

customers. Any limitations on market participation will impact revenues.

Specific issues of concern to MPW are:

 Installation of any air pollution control equipment will require downtime for the associated 

generating unit. During that period or periods MPW must continue purchasing power to supply 

native system load. However, revenues from supplying energy to the market will not be received. 

The result is that MPW not only incurs the cost of the pollution control equipment, but also 

experiences lost revenues. These circumstances can aggravate financial issues further when the 

utility is already dealing with the implications of the poor economy. 

 Timing of a new rule will affect the duration and timing of control equipment installation. If 

the effective date is a relatively short period (Three years for a MACT rule.), a shortage of 

labor and materials is likely to exist as a result of numerous generating units being affected 

by the rule. Economics dictates that vendors and contractors will serve large utilities first. 

Therefore small entities may not be able to meet a regulatory deadline and would need to 

cease operating their unit(s) until controls can be installed. This situation places another 

financial burden small entities.

 Financing control equipment can add to the financial burden of the utility because it can be 

a costly and lengthy process. A first step in the municipal bond process is obtaining a rating 

from at least one of the rating agencies. MPW has ratings, but other small utilities may not. 

MPW's past experience for issuing municipal bonds is that the process takes about six 

months. This period must be factored into meeting a compliance deadline.

 MPW envisions the need for subcategories to account for the variability in emissions from 

differences such as boiler types, coal rank, boiler size and unit type. EPA should develop a 

list of realistic subcategories that encompasses those factors that can affect emissions. Any 

MACT limits need to be tailored to subcategories in order to be realistic and equitable.

 A MACT rule should address the variability found in HAP emissions from an individual 

source. Even within a subcategory, variability in HAP emissions occurs. For example, we 

observed one of three stack test runs for Hg that was noticeably higher than the other two. 

The boiler operation remained unchanged while this situation occurred. 



 A complicating factor in Muscatine is that the city has a large industrial base for a relatively 

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small community. These industries contribute to local air quality issues. Specifically, more 

stringent NAAQS for PM2.5, SO2, NOx and probably 03 will result in violations that will need 

to be addressed by industries and MPW. These circumstances compound decisions 

associated with air pollutant emissions controls.

MPW appreciates being able to participate on the SER panel and hopes that EPA gives serious consideration to 

the concerns expressed by small entities. We also believe that an additional meeting or meetings of the SER 

Panel would be beneficial after EPA develops more definitive information that could be incorporated into the 

proposed rule.

Don Pauken

Manager Environmental Affairs

Muscatine Power and Water

3205 Cedar St.

Muscatine, IA 52761

563/262-3394

(See attached file: Questions Responses for SERs.doc)

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Page 2 of 2

file://C:\Documents and Settings\mbarch\Local Settings\Temp\notesFCBCEE\~web2178.htm 1/6/2011
1

ATTACHMENT A

MUSCATINE POWER AND WATER

RESPONSES TO EPA SER QUESTIONS

 Affected Entities

o Is EPA’s list of potentially affected small entities on slide A‐4 of this presentation

accurate? If not, do you have suggested additions or deletions? Could you briefly explain

the reason for each addition or deletion? (Note: The applicable definitions of small

entity are on slide 28 of this presentation.)

Unqualified to answer this question.

 Firm Characteristics

o How many units do you have in your facility or facilities?

Three boilers serving four turbine/generators.  Two of the three boilers will be subject to

the EGU MACT.  (One will be subject to the “Small Boiler” MACT.)

o What is the capacity of your installed units?

293.55 MW

o What duty cycles do they run?

The units do not operate in the historic base load or peaking modes.  Muscatine Power

and Water (MPW) is a member of the Midwest Independent System Operator (MISO).  

MISO dispatches (regulates output) the units in five minute intervals based on a

combination of Day Ahead and Real Time market conditions.  MISO operations are too

complex to describe in this response, but MPW is willing to discuss MISO operations with

EPA verbally.

 Existing Standards

o What Federal/State/local standards are your EGUs currently subject to?

Title V, NSR/PSD, Acid Rain Program, CAIR

o What compliance requirements are associated with the other standards that apply to

your EGU?

Parameter Period Unit 7 Unit 8/8A Unit 9

Opacity 6‐minute 40 % 40 % 20 %

Particulate

Matter (PM)

1‐hour 0.42 lbs./MBtu

121 lbs./hr.

0.30 lbs./MBtu

267 lbs./hr.

0.03 lbs./MBtu

SO2

3‐hour

24‐hour

30‐ day rolling avg.

Annual

6.0 lbs./MBtu

2,772 lbs./hr. 1)

N/A

N/A

6.0 lbs./MBtu

2,772 lbs./hr. 1)

N/A

Adequate

allowances

N/A

0.56 lbs.MBtu

0.45 lbs./MBtu

Adequate

allowances
2

SO2 %

Removal 30‐day rolling avg. N/A N/A 92 % minimum

NOx

30‐day rolling avg.

30‐day rolling avg.

Annual

12‐mo. rolling avg.

Annual

Seasonal

N/A

N/A

N/A

N/A

N/A

N/A

N/A

N/A

N/A

0.86 lbs./MBtu

Adequate Alwnc.

Adequate Alwnc.

0.60 lb./MBtu 2)

0.50 lb./MBtu 3)

0.40 lbs./MBtu

0.235 lbs./MBtu

Adequate Alwnc.

Adequate Alwnc.

CO

1‐hour

24‐hour daily avg.

12‐mo. rolling avg.

N/A

N/A

N/A

432.4 lb./hour

250 ppm

960 ton/yr.

329.2 lb./hour

100 ppm

720 ton/yr.

1)Unit 7 & 8 combined.

2) When combusting bituminous coal.

3) When combusting subbituminous coal.

o What emissions control technologies do you have installed at your facilities? Under

what regulatory requirements are they installed? What did they cost to install? To

operate?

Unit Control Device Reg. Requirement. Capital Cost/Yr. Operating Cost/Yr.

7 Cold side ESP None na/1976 $2,400/2009

8/8A Cold side ESP

OFA

None

PSD

/1999

$2.0M/2008

$24,000/2009

na/2009

9 Cold side ESP

OFA

Wet scrubber

None

PSD

PSD/LAER

na/1982

$3.0M/2008

$33M/1982

$44,000/2009

na/2009

$308,000/2009

o What recordkeeping and reporting requirements are you subject to under other

standards that apply to your EGU?

Title V, Acid Rain Program, 40 CFR Parts 60 and 75, GHG Reporting, Iowa Hg Emissions

Reporting.

o If your EGU is subject to emission limits, are there alternatives to monitoring emissions

or stack testing that would be less costly to demonstrate compliance and, if so, how

much less costly are the alternatives?

Considering the parameters, probably not.

o Are there recordkeeping and reporting alternatives that would simplify the

requirements?

As long as requirements exist to demonstrate continuous compliance, no.
3

o Do you employ any monitors, for emissions or process parameters, to monitor the

operation of your EGU?

Yes, MPW uses gas and opacity stack monitors.

o What type of monitors and how many?

Four SO2, Two NOx, Four CO2, Three flow, Two CO and Three opacity monitors.

o What were the capital costs and what are annual costs for each monitor?

Total annual maintenance costs are about $30,000 for materials and $30,000 for labor.

Monitors Capital Cost ($)

Type Unit 7 Unit 8 Unit 9

Year Cost Year Cost Year Cost

SO2 2005 12,300 2005 12,300 2005 24,600

NOx  ‐  ‐  2005 12,300 2005 12,300

CO2 1995 na 1994 na 1994 na

Flow 1995 na 1994 na 1994 na

CO  ‐  ‐  2008 17,000 2008 17,000

COM 2000 34,000 1997 32,000 1997 32,000

Note: Flow and opacity monitors are scheduled for replacement during 2011.

o Are these monitors in place for environmental regulatory reasons, insurance reasons, or

other reasons?

The monitors are used for demonstrating environmental regulatory compliance.

o Did you provide any of the monitoring data to the Agency during the recent Information

Collection Request on Utility Boilers or another information collection request?

Yes.  MPW provided Hg and non Hg metallic HAPS stack test data for a 75 MWe

nameplate cyclone fired unit.

o Do you employ measures to ensure that your EGU operates in an energy efficient

manner?

Yes.   

o What are the energy efficient measures you employ?

The units have distributive control systems.  These systems use neural network software

that is tuned to operate the boilers most efficiently.  Parasitic power use is minimized.  

Electric motors are replaced with energy efficient ones.  Generating unit building lighting

is currently being evaluated and old fixtures and bulbs are being replaced with energy

efficient ones.  Compressed air systems operation is being optimized.
4

o Are these measures a result of regulatory requirements, initiated voluntarily, or

employed for other reasons?

The measures are initiated voluntarily as good business management practices.

o What are the estimated emissions reductions associated with the energy efficient

measures?

Energy Efficiency Measure Cost ($) kWh Savings/Yr. CO2 Reduction (Tons)/Yr

Neural Network #8/8A 260,000 na na

Neural Network #9 300,000 na na

Plant Lighting 200,000 680,000 850

Plant Motors na 34,262 42.5

#7&8 Compressed Air

System Optimization 157,000 950,000 1,187.5

na = not available

o What are the costs of implementing the energy efficient measures?

See table above.

 Regulatory Alternatives

o What types of subcategories based on class, type, or size do you think EPA should

consider and why?

Boiler technology, coal rank and unit size affect emissions.  One size does not fit all.

o What surrogate standards do you think are appropriate?

Opacity for PM (including PM‐10 and PM‐2.5)

Coal sampling and analysis (CSA) combined with mass balance

o What means of determining variability do you think EPA should consider?

Uncertain.

o Which subset(s) of HAP from EGUs, if any, do you think would meet the CAA section

112(h) requirements for establishing work practice standards in lieu of emission limits

and what is the basis for your assertion?

Uncertain.

o What work practice standards are available to you?

Efficient unit operations and preventive maintenance on pollution control equipment.

o What work practice standards would you consider to be reasonable alternatives to

emission limits?

Preventive maintenance activities that could be specified in T V Operating permit.
5

o What are the costs of those work practices?

Do not have data.

o Do you have the information that would support considering setting health‐based

emission limits under CAA section 112(d)(4) for HAP emissions from EGUs? For example,

facility‐wide HAP emissions, facility configurations, overall fence‐line characteristics,

population proximity to plant, potential adverse environmental effects that would

otherwise be reduced or eliminated.

No.

o Are there other regulatory options or small entity flexibilities that EPA should consider?

Deminimis exemptions.

 Cost Estimates

o If you employ any of the control technologies listed on slide 26 of this presentation as

potentially being required to meet the Utility NESHAP, indicate the type of control, its

size (e.g., the size EGU that the control is associated with, the exhaust gas flow rate

being routed through the control), what the capital costs were, and what the annual

operating costs are.

One of two units (175.5 MW) has a wet scrubber for SO2 removal.  (See table above for

costs.)  Both units have NOx and CO limits.  The units are operated to meet emission

limits for both parameters.  (This is a balancing act because lowering one increases the

other.)

o Do you agree with the control technology and monitoring cost estimates presented on

slide 27 of this presentation? If not, provide your cost estimate(s) along with the

source(s) of your estimate(s).

No basis on which to evaluate costs.

o Do you employ other control or monitoring technologies that EPA should consider when

estimating the impacts of the standards? If so, indicate the type of control or monitor,

the size boiler it is associated with, what the capital costs were, and what the annual

operating costs are.

No

o In ideal circumstances, how long would your facility require to finance and install new

emissions control and monitoring equipment?

Availability of equipment and manpower, and environmental permitting would affect

the timeline.  These factors cannot be projected.  The scope of the project would need to

be defined in order to develop the cost. After the project cost is known, MPW estimates

six months would be needed to obtain funding through municipal bonds.
6

How long would be required if there were other regulations requiring similar

investments that had to be implemented consecutively?

Too many variables exist to provide an estimate.

o How would new emissions requirements affect your production capacity?

Directly by requiring more station service power.  Indirectly by increasing production

costs in a competitive market.  Directly by possibly “forcing” retirement of Unit 8/8A

sooner than planned.

o Are there other regulatory requirements that could conflict with new emissions

standards?

Unknown

o Are there other regulatory requirements that could increase the cost of compliance with

new emission standards?

Yes, more stringent NAAQS.  Muscatine will probably be declared non attainment for the

new SO2 standard.  EPA has declared the state SIP for PM2.5 to be deficient for the

Muscatine area.  Any new project affecting NO2 would probably require reductions to

show modeled compliance.

o How does your entity acquire money for capital investments? Is it primarily through

equity? Or debt? Or a combination of both?

A combination of both.  Smaller projects are generally financed through equity and large

projects are financed through debt.

o Are you an independent power producer?

No.  MPW is a municipal utility.

o Is your entity regulated by a State or local utility commission, or does it operate in

competitive markets? If you had to install additional control equipment that required

capital investment, would you adjust the rate charged to your customers?

MPW is overseen by a locally appointed Board of Trustees.  The utility is a member of the

Midwest Independent System Operator and as such functions in a competitive market.  

All native system load is satisfied by purchases from the market and all generation is bid

into the market.  Capital investment would be recovered through retail rates.   

o What is the process for adjusting the rate?

Utility staff make rate adjustment recommendations to  Board of Trustees.  The Board

takes action at a monthly meeting.

o What is the expected time for that change to occur?

Rates are adjusted whenever the utility budget demonstrates additional revenue is

needed to meet expenses.  Typically rate adjustments take about six months.
7

o What are the limits on how much you can raise rates?

The municipal utility Board of Trustees has rate making authority.  The Board strives to

keep rates reasonable.  High rates would negatively impact local business and the local

economy, which have already been hit by the recession.

o What other constraints exist on your ability to raise capital or fund capital investment

for regulatory compliance?

When regulatory compliance costs become so onerous that wholesale and customer

rates become non‐competitive raising capital will become an issue.  Customers will resist

increases, rating agencies and lenders will also balk and question the Utility’s  ability to

repay the debt.

12/16/10
EPA Utility MACT Small Entity Outreach Meeting comments

Joe Eutizi 

to: 

Madeline Barch 

12/16/2010 04:10 PM 

Cc: 

"Mike Kezar" 

Show Details 

History: This message has been replied to and forwarded. 

Madiline,

Attached are comments submitted by San Miguel regarding EPA’s review panel for the Electric Generating Unit 

Hazardous Air Emissions Rulemaking. Thanks for the opportunity to comment on this very important rule.

Please don’t hesitate to let me know if you have questions or need additional information.

Joseph Eutizi 

San Miguel Electric Cooperative 

830-784-3411 ext. 226 

jeutizi@smeci.net

 

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confidential and privileged information. Any unauthorized review, use, disclosure or distribution is prohibited. If 

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Page 1 of 1

file://C:\Documents and Settings\mbarch\Local Settings\Temp\notesFCBCEE\~web7947.htm 1/6/2011
Madelyn Barch 

Regulation Management Division 

Office of Policy 

U.S. EPA 

barch.madeline@epa.gov

Re: Small Business Review Panel for the EPA rulemaking “ National Emission 

Standards for Hazardous Air Pollutants (NESHAP) for Coal and Oil Fired Utility 

Steam Generators” 

Members of the Small Business Advocacy Review Panel: 

San Miguel Electric Cooperative, Inc. (San Miguel) thanks the Small Business Advocacy 

Review Panel (Panel) for selecting San Miguel to participate as a Small Entity 

Representative in this process. San Miguel submits the following comments to the Panel 

on the EPA rulemaking, National Emission Standards for Hazardous Air Pollutants for 

Coal and Oil Fired Utility Steam Generators (Utility MACT). San Miguel’s comments 

will cover the following topics: 

• Possible areas of regulatory options that would minimize impacts on small entities 

• Concerns on the Small Business Advocacy Review for this particular rule 

• General Comments on Utility MACT 

• Input on Questions from Presentation Packet 

Introduction 

The principal business of San Miguel is the production of electric energy in South Central 

Texas. San Miguel’s electric production comes solely from one mine mouth coal-fired 

power plant in South Central Texas. This one coal-fired unit comprises 100% of San 

Miguel’s generating capacity; average yearly output is 2.9 million megawatt hours. The 

coal-mine, which is adjacent to the generating facility, extracts a Yegua, Lower-Jackson 

lignite (a Group B Lignite). The lignite mine supplies fuel only for the San Miguel 

Generating Station and yearly produces on average 3.3 million tons of lignite. The 

generating unit fires only lignite provided by this mine. The San Miguel electric 

generating station was designed and built specifically for this locally available lignite 

fuel. This unit has been reliably providing power to its customers successful since 1982 

with a yearly availability factor averaging approximately 84%. 

San Miguel is a Generation and Transmission Cooperative (G&T) and power generated 

from the plant is ultimately distributed to 26 member cooperatives that serve 

approximately 570,000 end-user member-owners in 114 Texas counties. As a not-forprofit cooperative, San Miguel does not have shareholders and these member-owners 

bear all of the costs of owning and operating the San Miguel facilities – including the 

costs associated with regulations such as the Utility MACT rule. 

 
San Miguel is a member of the National Rural Electric Cooperative Association 

(NRECA) and supports its comments to the Panel on the Utility MACT. 

Regulatory Options 

San Miguel specifically proposes the following recommendations for regulatory options 

that would minimize impacts on small entities: 

• Coal Subcategorization 

• Either/or Standard of Percent Reduction or Emission Limit 

• Mine Mouth Plant or Transportation Infrastructure Limitations 

• Long Term Rolling Average Due to Variability in Fuel 

• Physical Site Constraints 

• Financing Options 

• Additional Time to Comply 

I. Coal Subcategorization 

San Miguel strongly suggests the use of subcategorization of coal including two lignite 

subcategories – one for Fort Union Lignite (North Dakota area) and one for Gulf Coast 

Lignite (Texas area). A definitive reason for lignite subcategories is the amount of 

mercury in the lignite. The Fort Union Lignite contains approximately one third the 

amount of mercury than the Gulf Coast Lignite, although this was not discovered during 

the 1999 ICR part II fuel sampling. Fort Union Lignite on average contains 6 to 10 

pounds of mercury /TBtu where as the Gulf Coast Lignite on average contains 24 to 34 

pounds per TBtu. The reason this was not discovered during part II of the 1999 ICR was 

the ASTM test method used - by the testing laboratory - method ASTM D 3684 was not 

accurate for coals containing high amounts of mercury. 

San Miguel discovered the error in the amount of mercury in the fuel after we started 

performing monthly composite fuel analysis in the spring of 2003. For the first few 

months the analysis indicated mercury in the 6 to 9 pound/TBtu range, which was similar 

to the values submitted for the 1999 ICR. The laboratory had equipment problems in late 

2003 and purchased different equipment to analyze mercury (the new equipment utilized 

a different method, Method D6416). In March 2004 San Miguel received a letter 

explaining the error in the coal analysis; specifically that the mercury content was 

understated. Using the new analysis method monthly composite samples increased 

mercury to the 21 to 53-pounds/TBtu range, and the average in 2004 was 31.9 pounds/ 

TBtu. San Miguel has continued to perform monthly composite fuel analysis; this 

information can be made available to the Panel if necessary. 

This error in analysis was included with our comments submitted to the EPA on June 22, 

2004 to Docket ID No. OAR-2002-0056 (the 2004 Utility Mercury Reductions Rule 

(UMRR) Proposal MACT alternative). This same laboratory, Advanced Analytical 

Laboratories in Tyler Texas, performed the fuel analysis for TXU Power. TXU also 
commented on the 1999 ICR data error in their letter to the EPA on June 29,2004 to 

Docket ID No. OAR-2002-0056. 

The subcategorization based on coal rank under Section 112 MACT standards was 

recognized by the EPA in its 2004 Utility Mercury Reductions Rule (UMRR) proposed 

MACT alternative. The additional subcategorization for the two lignite types is a simple 

option that could help in minimizing the effect of this rule on this small entity, while still 

achieving significant mercury emission reductions. 

II. Either/Or Standard of Percent Reduction or Emission Limit 

The final rule should include an either/or standard of percent reduction or emission limits 

to allow the source to comply with the least expensive or burdensome option. This 

clearly would be helpful to small entities. The composition of the coal used at many 

facilities varies considerably over time due to several reasons. Coal produced from a 

single mine is diverse as a result of the dissimilarity in coal composition from different 

locations or layers in the mine. At San Miguel over the past six years we have seen 

month to month variations in our monthly composite coal sample that range between 17 

and 48 pounds of Hg /TBtu and yearly averages varying between 24.5 and 31.9 pounds of 

Hg/TBtu. 

San Miguel is a mine mouth facility and was designed to burn the lignite that is close to 

the plant; the infrastructure to unload coal trains is not present at the San Miguel facility, 

but there are many power plants that purchase coal from more than one mine because of 

market based cost and other considerations. In addition, many times coal from various 

sources is blended and, in some cases, even different coal types are combined in varying 

amounts for use in a single generating unit. 

For all these reasons, the option of a percent reduction compliance method may be the 

most reasonable alternative to achieving the desired emission reductions while helping to 

minimize any unnecessary costs of compliance. In other instances, emission limits may 

be less burdensome. San Miguel believes that the source should be allowed to make the 

decision regarding which option to use; this will minimize the effect on the small entity, 

while achieving the desired reduction in mercury emissions. 

III. Mine Mouth Plant or Transportation Infrastructure Limitations 

A mine mouth electric generating station such as San Miguel which was built without 

transportation infrastructure to unload coal via railroad or is not on a navigable waterway 

is at a significant disadvantage to generating facilities that receive coal via railroad or 

river/ocean barge. If the only way to meet the new Utility MACT is to change fuels or to 

blend fuels this small entity will be looking at an additional estimated $70-100 million 

just to build the infrastructure to unload and burn the fuel. This estimate does not include 

the cost required to install the MACT control equipment or the higher cost for the new 

fuel. 
Another factor is the loss of high paying jobs in our rural county if mining operation is 

curtailed (100% replacement fuel) or reduced (blending fuels). This would be a 

significant loss to the local residents, which make up a majority of the 200 employees at 

the mine and the loss of the tax basis to the county. 

Also, as stated in the “Introduction”, San Miguel was designed to burn a specific fuel that 

is located within a few miles of the electric generating facility. The steam generator was 

built especially to handle the specific local lignite fuel – low heat content (average 5250 

Btu/lb), high ash (average 30%) and high moisture (average 30%) – it is unknown at this 

time if a total replacement fuel could be used without a major modification of the boiler. 

San Miguel is very concerned with the possibility of having to change fuel if the mercury 

emissions standard is so low that current control technologies can not meet the required 

removal rate or emission limit. San Miguel has performed full scale tests as part of a 

Department of Energy grant with Energy and Environmental Research Center (EERC) in 

2008 and 2009. The highest removal rate achieved was 81.7%, due to scrubber 

reemission. A scrubber additive was included in the 2009 test and it had little effect on 

the scrubber reemission. Reports can be provided to the Panel if needed. 

In the proposed NESHAP (and in the alternative NSPS) for Electric Utility Steam 

Generators, the EPA decided “fuel switching is not an appropriate criterion for 

identifying the MACT Floor level of control for existing coal-fired units.”(69 Fed. Reg. 

4669, January 30, 2004) . Thus, consideration needs to be given whether each coal rank 

can meet the standard without forcing a unit to switch coal rank. Fuel switching is 

particularly problematic at mine mouth facilities that do not have transportation 

infrastructure to switch or blend fuels. San Miguel recommends the MACT standard not 

be finalized in a manner that would effectively require a fuel change (blending or 

completely), especially for mine mouth coal electric generating stations. 

IV. Longer Term Rolling Averages Due to Variability in Fuel 

 As stated above in the “Either/Or Standard”, the variability of mercury in fuel is 

significant for San Miguel on a month-to-month basis. San Miguel does not have 

knowledge of the other possible HAPs variability, and limit our comments to mercury. In 

order to provide for controls that can adjust for higher levels of mercury in the fuel, a 

longer-term rolling average – a 12-month minimum rolling average- is necessary. In 

addition to the variability in the fuel, the mercury analyzers are unreliable. San Miguel 

installed a mercury CEMS by Thermo Environmental three years ago. We have not seen 

more than 30 consecutive days of reliable information from our CEMS even though the 

OEM has had their best technician troubleshoot the equipment. The OEM has recently 

told us the analyzer installed will not work in our application. The CEMS was removed 

and we are awaiting a recommendation from OEM. Without a real time monitor, changes 

cannot be made to adjust for varying amounts of mercury in the fuel. A method such as 

sorbent traps would be necessary to give an after-the-fact analysis of mercury emissions. 

A longer rolling average may allow increases in the performance of the control device to 

reduce additional mercury in the future avoiding a deviation of a shorter rolling average. 
San Miguel recommends an emissions standard that is a 12-month rolling average due to 

variability of mercury in fuel and the difficulty of measuring minute quantities of 

mercury. 

V. Physical Site Constraints 

This does not affect San Miguel but we understand this is a very real situation that 

electric generating facilities might need to address. Generating facilities such as those 

built in a city or units built along a waterfront may not be physically able to expand its 

footprint, and not able to install the control technology required by the Utility MACT. 

Small entities need to be given the flexibility as well, when hampered by physical site 

constraints. This may result in a limit higher than MACT for a significant time frame, 

something that can be met using a control device that would fit in the physical constraints 

of the site. 

 

VI. Financing Options

San Miguel was financed using REA financing. San Miguel has only required one other 

long-term loan in its 25 years of operations and that was through RUS two years ago 

(mostly for environmental control projects). RUS loans are no longer available for coalfired projects including environmental control upgrades. Small entities such as San 

Miguel will need to find additional sources of financing for major projects including 

environmental projects. 

San Miguel recommends a change to RUS policy to allow loans for coal-fired projects to 

meet environmental regulations. 

VII. Additional Time to Comply 

Small entities are at disadvantage to compete with large electric generating providers in 

obtaining services. Large entities have the ability to sign a contract with a single 

contractor to provide services at multiple plants for both equipment and installation 

services. Many times these are for very large units and at sites with multiple units. 

These types of projects have the potential for good profit margins as compared to single 

or smaller size units. Although San Miguel has a medium size electric generating unit 

(400Mw capacity), it is a single unit site. Over the past few years San Miguel has seen 

lead times increase for both material and installation (manpower). San Miguel believes 

this is due to a combination of the following reasons: utilities installing scrubbers and 

SCRs to meet CAIR; the local effect on limited manpower due to infrastructure repairs, 

including refineries, from hurricane Katrina; and the global effect on materials due to the 

build-up of China and India electric systems. 

This rule will likely increase or sustain the time required for the small entity to obtain the 

services required to meet the rule, since all coal-fired electric generating facilities will be 
vying for the same services including engineering design, control technology 

manufacturing facilities, qualified manpower for installation and financing. 

San Miguel recommends that the small entities be given an additional three years to 

install the required emission controls. 

Concerns on the Small Business Advocacy Review 

San Miguel is very concerned with this review process for the following reasons: 

1) EPA has not provided adequate time to review and comment on a rule of this 

importance. The process from notification of the SERs to the Panel meeting was 

two weeks (which included Thanksgiving holiday). After the meeting with the 

Panel the SERs only had two weeks to prepare written comments. 

2) There was no pre-meeting held to go over information on the rule. 

3) The EPA did not provide usable information or data in a sufficient form that 

would assist the SERs in assessing the potential impact of this rulemaking. 

4) The meeting conference phone failed during the meeting, thus the SERs 

participating by phone missed out on discussions in the meeting room and the 

meeting was not extended to accommodate for the time lost to those on the 

conference call. 

San Miguel understands that the EPA is under a Consent Decree timeline but with a 

regulation that is this important not only to the electric generating companies, but also to 

our national interest in a reliable electric system, the necessary time should be taken even 

if it requires the EPA to file a motion for an extension. The EPA recently requested an 

extension for the Boiler MACT deadline until April of 2012. A similar extension is 

warranted here to process the significant issues raised in public comments, which are 

similar to the issues for this rulemaking. 

General Comments on Utility MACT 

The NRECA has provided general comments to the Panel on Utility MACT. San Miguel 

is in agreement with those comments. We will not duplicate those comments since we 

are co-signing the NRECA comment letter. 

Questions for SERs 

Since time ran out during the Panel meeting on December 2, 2010 San Miguel will 

attempt to provide input on the questions contained in the appendix of the presentation. 

 

Affected Entities 
This topic is covered in the comment letter of NRECA and will not be duplicated 

here. 

Firm Characteristics 

San Miguel has a single generating station with a net capacity of 391 Mw. The 

unit is base loaded as is indicated by our annual capacity factor that is only one to 

two percent lower than our annual equivalent availability factor. 

Existing Standards 

What Federal/State/local standards are your EGUs currently subject to? 

San Miguel is subject to all the standard federal regulations such as Title V 

permit, Title IV Acid Rain regulations, Current CAIR requirements, Texas NSR 

air permit and east Texas regulation on NOx (which limits NOx emissions to an 

average 0.165 lb/MMBtu). 

What emissions control technologies do you have installed at your facilities? 

Under what regulatory requirements are they installed? What did they cost to 

install? To operate? 

The San Miguel generating station was constructed with an electrostatic 

precipitator for control of particulate matter and a wet flue gas scrubber for 

control of SO2. An overfire air system, low NOx burners and a neural network 

control system were added for NOx control to meet the Texas regulations. 

Capital costs for the ESP and WFGD are not provided since they were installed 

during the original construction of the unit. The OFA, LNB and NN total cost 

was $6.3 million. In addition, the WFGD was upgraded to improve SO2 removal 

efficiency from 86% to 94% to meet CAIR regulations at a cost of $8.7 million. 

Operating costs to run the ESP range from $500,000 to $725,000 annually, while 

the WFGD annual operating cost range is between $7.5 million to $10 million. 

What recordkeeping and reporting requirements are you subject to under other 

standards that apply to your EGU? 

Public Utility Commission, EPA CAA, Texas Commission on Environmental 

Quality, and Texas Railroad Commission 

Do you employ any monitors, for emissions or process parameters, to monitor the 

operation of your EGU? What type of monitors and how many? What were the 

capital costs and what are annual costs for each monitor? Are these monitors in 

place for environmental regulatory reasons, insurance reasons, or other reasons? 

A single Continuous Emission Monitor is installed for each of the following: 

CO2, CO, NOx, SO2, Gas Flow, and Hg (currently removed from service). Each 

monitor was installed for environmental reasons. The capital cost of all monitors 

was between $30,000 and $50,000 except for flow and Hg, which were $120,000 

and $390,000 respectfully. 
Did you provide any of the monitoring data to the Agency during the recent 

Information Collection Request on Utility Boilers or another information 

collection request? 

San Miguel did not submit data with the ICR but did indicate we would supply 

electronic records if requested. San Miguel’s generating unit was not selected for 

stack emissions testing. 

 

Regulatory Alternatives 

What types of subcategories based on class, type, or size do you think EPA should 

consider and why? 

1) Coal, including the subcategories for the two primary lignite’s groups – Fort 

Union and Gulf Coast reasons are stated above. 

2) Boiler type, wall fired and tangentially fired - tangentially boilers have lower 

NOx emission rates than wall fired units. Although NOx is not directly 

affected by this rule, CO may be used as a surrogate for other HAPs. NOx 

and CO are inversely related, thus the lower NOx emissions provide an 

advantage to tangentially fired units, as NOx is lowered (for CAIR or the 

Transport Rule) CO increases. 

What surrogate standards do you think are appropriate? 

San Miguel can only provide comments/concerns on alternative surrogates that 

EPA has suggested. 

Using Particulate Matter (PM) as a surrogate is a concern since PM monitors 

would need to be installed and this technology is in its infancy and has not been 

proven to be reliable over varying load ranges. Another problem is with stacks 

that are wet, the PM monitor would need to be installed upsteam of the WFGD 

and this will not account for the PM removal that occurs in the wet scrubber. 

Both of these would lead to inaccurate data. 

Using CO as a surrogate is a concern since NOx has an inverse relationship with 

CO. As an example as to how CO increases as NOx decreases, San Miguel 

installed LNB and an OFA system in the mid 2000s. When these were installed 

NOx dropped by more than 50%, while CO increased. Will this lead to units 

increasing NOx to decrease CO or visa versa? 

 

What means of determining variability do you think EPA should consider? 

As mentioned above a 12-month rolling average for emissions needs to be 

implemented due to the variability of fuel. 

Are there other regulatory options or small entity flexibilities that EPA should 

consider? 

As discussed above, the following regulatory options should be considered: 

Either/or Standard of Percent Reduction or Emission Limit; Mine Mouth Plant or 

Transportation Infrastructure Limitations; Physical Site Constraints; Financing 

Options; and Additional Time to Comply. 
Cost Estimates 

If you employ any of the control technologies listed on slide 26 of this 

presentation as potentially being required to meet the Utility NESHAP, indicate 

the type of control, its size (e.g., the size EGU that the control is associated with, 

the exhaust gas flow rate being routed through the control), what the capital costs 

were, and what the annual operating costs are? 

As tested in February 2009, the WFGD exhaust is 2,738,000 ACFM. Costs are 

covered above in Existing Standards. 

In ideal circumstances, how long would your facility require to finance and install 

new emissions control and monitoring equipment? 

Ideal financing would come through RUS. Since this is currently unavailable for 

coal-fired generating units, San Miguel can only provide a best guess since we 

have never had to go to the market to obtain long term financing. San Miguel 

estimates a minimum of one year to obtain financing. 

San Miguel also estimates the engineering, procurement and construction time to 

be two and one half to three years, for a total time of three and one half to four 

years. Under real world conditions additional time would be required due to the 

competition that will exist when all coal-fired units (approximately 1300) are 

vying for the same services at the same time. As stated above in “additional time 

to comply” the small entity is at a disadvantage when competing with a large 

entity. 

How long would be required if there were other regulations requiring similar 

investments that had to be implemented consecutively? 

San Miguel believes this is dependent on the amount of work and the willingness 

of lenders to provide financing for the new projects. San Miguel believes if all 

the rules were known, it would be easier and more cost effective to engineer for 

all rules at one time and install in a staggered manner so as to optimize and 

minimize the yearly down time of our only unit. 

How would new emissions requirements affect your production capacity? 

This will depend on costs of installing and operating the necessary emissions 

control devices as compared to other generating facilities. This will determine the 

economic dispatch order for our unit. 

Are there other regulatory requirements that could conflict with new emissions 

standards? Are there other regulatory requirements that could increase the cost 

of compliance with new emission standards? 

There are many potential regulations that could potentially conflict and/or 

increase cost of compliance. The list includes: GHG, CCR, NAAQS, TR, SCPP, 

and future effluent regulations. 
How does your entity acquire money for capital investments? Is it primarily 

through equity? Or debt? Or a combination of both? 

Currently, most capitol investment funds are acquired through debt. 

Are you an independent power producer? 

No, San Miguel is a Generation and Transmission Cooperative. 

Is your entity regulated by a State or local utility commission, or does it operate 

in competitive markets? 

Transmission rates are regulated by the PUC of Texas and are based on cost of 

service studies. Cost of services studies can be updated as needed. 

If you had to install additional control equipment that required capital 

investment, would you adjust the rate charged to your customers? What is the 

process for adjusting the rate? 

As stated in the “Introduction” San Miguel is a non-profit cooperative owned by 

the consumers they serve. Since San Miguel does not have stockholders that 

could share the costs of any increased cost, all costs - including any that may be 

required by this proposed rule - must be passed through to the distribution 

cooperatives we serve. 

The Board of Directors, based on the operating budget prepared by management 

and approved by the Board, sets rates for generation annually. The Board can 

change rates during any given year if circumstances warrant. The Board of 

Directors consists of one representative (Director) from each cooperative that San 

Miguel serves. The owner-consumers of each distribution cooperative elect their 

Director. 

San Miguel would like to once again thank the Panel for selecting us as a Small Entity 

representative on this very important industry regulation. We encourage the Panel to give 

further consideration in scheduling an additional Panel meeting once the EPA has 

progressed in its rulemaking preparation. 

If you have any questions concerning these comments please contact me. 

Sincerely, 

Joseph G. Eutizi 

Engineering Manager 

San Miguel Electric Cooperative, Inc. 

830-784-3411 ext. 226 

jeutizi@smeci.net 
Comments to SBA on EGU MACT rule TMPA

Ken Babb 

to: 

Madeline Barch, RobertJ Wayland, Mary Johnson, David.rostker@sba.gov, 

Cortney_Higgins@omb.eop.gov 

12/16/2010 06:32 PM 

Cc: 

Jan Horbaczewski, Charles Chang, "tpugh@appanet.org", "Eleanor Babb - personal 

(twinkee987@hotmail.com)" 

Show Details 

Attached pleased TMPA’s comments following our participation on the SBREFA SER panel for the utility MACT

(oil and coal).

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Comments for Coal and Oil-fired EUSG Units - Rulemaking Process

Caudell, John F. 

to: 

Madeline Barch 

12/17/2010 02:18 PM 

Cc: 

Joe Tondu, Erik Booth, "dnally@hollandpbw.org", "jfrench@wyan.org" 

Show Details 

History: This message has been forwarded. 

Please accept the attached document as a timely comment from Mr. R. J. Tondu concerning the rulemaking process for the

Coal and Oil‐fired Electric Utility Steam Generating Units.  Mr. Tondu has not signed the attached document, but has

reviewed and approved it for distribution.  If you require an official signed copy, please let me know.   

  

Thank you for the opportunity to participate in these important (rules) discussions........John Caudell

  

  

  

  

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December 17, 2010 

To: Madeline Barch, USEPA 

From: John F. Caudell, Representing TES Filer City / Tondu Corporation 

Re: Proposed Small Entity Utility MACT 

Both Mr. Tondu and I appreciate the exchange of information and perspectives from all Small Entity and 

federal conference participants concerning development of the proposed Utility MACT standards. We 

believe your representatives received a clear message that any MACT standard that would require the 

installation of additional emissions control equipment for the Small Entity (EGU) participants would 

require an extended compliance schedule significantly greater than 3 years. The availability of skilled 

labor and access to emissions control systems will likely be scarce, in the event these Small Entities have 

to compete for the same resources as the larger utilities, assuming they will also be attempting to comply 

with a new MACT during this same time period. 

Additionally, the USEPA has recently proposed to extend the deadline to publish a final version of Boiler 

MACT until April 2012, primarily because of the large number of comments opposed to (1) the quality of 

the test data used to set the proposed emission standards and (2) the “cherry picking” of the lowest 

emission rates on a pollutant by pollutant basis without regard for the combustion interrelationships 

between some of the regulated pollutants. Furthermore, it was pointed out by multiple participants during 

our call that there are several conflicting regulations pertaining to GHG, the proposed Clean Air Transport 

Rule, and others that must collectively be considered when attempting to set emission standards under 

MACT. In general, USEPA must develop a more organized, comprehensive effort to regulate multiple 

pollutants from combustion sources. The current hap-hazard approach used by USEPA to regulate 

pollutants from combustion sources is technically flawed and consistently disregards basic combustion 

chemistry. 

We recommend that USEPA stand down on developing proposed Utility MACT regulations until the Boiler 

MACT rules become final and the existing (utility) emissions data base is re-evaluated by experienced 

combustion professionals, to avoid the technical deficiencies noted in the Boiler MACT comments 

received during Y2010. USEPA should immediately request an extension of their voluntary consent 

decree so they may: 

 Adequately analyze those lessons learned in the Boiler MACT rule development process to avoid 

making similar mistakes. 

 Take additional time to thoroughly analyze the emissions data collected during the EGR ICR, 

which will serve as the basis for defining MACT for EGUs. 

 Continue to meet with representatives of the utility industry to discuss the logistical impediments 

to implement MACT on some 1350 coal and oil fired EGUs. 

 Consider the range of possible emission control options that can be used to allow for 

implementation to take place in an orderly fashion that will protect the integrity of the Grid, the 

national economy and national security 

To propose a Utility MACT standard without consideration of the issues would result in a highly flawed 

draft rule, subject to multiple revisions and likely delay final issuance of the rule well beyong the schedule 

that could be accomplished by taking a more logical and thorough approach. 
Wyandotte Comments to SBA on EGU MACT Ruleamaking 12-16-20110

James French 

to: 

RobertJ Wayland, Mary Johnson, Madeline Barch, David.rostker, Cortney_Higgins 

12/16/2010 05:16 PM 

Cc: 

"Melanie McCoy", "Theresa Pugh" 

Show Details 

Attached are WMS’s comments on the Small Business Review Panel for EPA’s Rulemaking for Hazardous Air

Pollutant Emissions from Coal‐ and Oil‐Fired Electric Utility Steam Generating Units. Thank you for allowing

Wyandotte to participate in this process and have the opportunity to have our comments considered. Having a

rule that protects both the environment and the ability of WMS to provide cost completive electricity is critical.  

  

James R. French

Assistant to the General Manager

Wyandotte Municipal Services

3005 Biddle Ave.

Wyandotte, MI 48192

Phone: 734‐324‐7114

Cell: 734‐775‐2777

Email: jfrench@wyan.org

  

  

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Municipal Service Commission 

Gerald P. Cole 

Frederick C. DeLisle 

James S. Figurski 

Leslie G. Lupo

Michael Sadowski 

Melanie L. McCoy 

General Manager and Secretary 

3005 Biddle Avenue, P.O. Box 658 

Wyandotte, MI. 48192-0658 

Telephone: (734) 324-7100 

Fax: (734) 324-7119 Electric, Steam, Water 

Cable Television and High Speed Internet 

Service since 1889 

December 16, 2010 

Mr. Bob Wayland 

Combustion Strategies Group Leader 

U.S. EPA 

Wayland.robertj@epamail.epa.gov 

Ms. Mary Johnson 

U.S. EPA 

Johnson.Mary@epamail.epa.gov 

Ms. Barbara Barch 

Regulatory Management Division, 

Office of Policy (U.S. EPA) 

Barch.Madeline@epamail.epa.gov 

Mr. David Rostker 

Advocacy Counsel 

Office of Advocacy 

U.S. Small Business Administration (SBA) 

David.rostker@sba.gov 

Ms. Courtney Higgins 

OIRA Desk Office- Air Regulations 

Office of Management and Budget (OMB) 

The White House 

Cortney_Higgins@omb.eop.gov

Small Business Review Panel for EPA’s Rulemaking for Hazardous Air 

Pollutant Emissions from Coal- and Oil-Fired Electric Utility Steam 

Generating Units 

Wyandotte Municipal Services 

In December 1889, the Wyandotte Electric Light Company, a private, for-profit company, began 

providing streetlights and retail electric service for the community. In 1892, local residents voted 

to create a municipal electric utility, which initially provided street lighting. In 1896, the 

municipal electric utility began serving retail and became a Department of the City of Wyandotte. 

Today that Department is known as Wyandotte Municipal Services (WMS) and provides not only 

electric services, but water and telecommunication services; including cable television, internet, 

and voice of internet phone (VOIP) services 

Wyandotte's municipal electric utility is one of 41 public power systems in Michigan, and one of 
nearly 2,000 public power systems in the United States. It serves 12,939 consumers, has $36 

million in annual revenues, and sold 282 million kilowatt-hours in 2010. Peak electric demands 

range from 65,000 to 70,000 kilowatts (65 to 70 megawatts). 

The municipal electric system has three sources of supply to provide reliable, affordable service: 

the 70-megawatt municipal power plant, a 28-megawatt interconnection with Detroit Edison's 

40,000-volt transmission system, and a 98-megawatt interconnection with Detroit Edison's 

120,000-volt transmission system. 

 

The municipal power plant consists of three boilers and four generators. Fuels include coal, 

natural gas and tire-derived fuel (TDF). TDF has a higher Btu or heating value than coal, is half 

the price of coal and produces similar emissions. About 26,000 tons of TDF (the equivalent of 3.5 

million scrap tires) were consumed at the Wyandotte municipal power plant in 2006. In addition 

to supplying over 90% of all the electricity need of the residences and businesses in Wyandotte, 

the municipal power plant also supplies 100% of all the steam needs of BASF and Henry Ford 

Wyandotte Hospital. 

 

The Wyandotte municipal electric distribution system consists of 12.5 miles of 69,000-volt 

transmission lines and 75.3 miles of 13,200-volt and 4,800-volt distribution lines. The municipal 

electric utility also installs, maintains and provides electricity for streetlights throughout the 

community without additional charge. 

 

The significance of the EGU MACT standard 

The EGU MACT rulemaking has the potential to be one of the most expensive rulemakings the 

utility industry has ever faced. Its impact on WMS could be enormous forcing us either to install 

extensive new pollution control equipment or even to close certain units. As set out in the statute, 

EPA must carefully consider the impact its EGU MACT rule will have on small entities and must 

act to lessen the burden of that rule on those entities. 

 The Small Business Regulatory Fairness Act (“SBREFA”) was enacted to provide small 

entities a meaningful voice in major federal rulemakings. Among the Act’s goals are to 

encourage the “effective participation” of small business in the federal regulatory process1

 and to 

create a more cooperative regulatory environment among agencies and small businesses that is 

less punitive and more solution oriented.2

 Section 609 of SBREFA envisions that small business 

panels will review “any material the agency has prepared in connection with this chapter” 

including information required to be part of the initial regulatory flexibility analysis.3

 A 

regulatory flexibility analysis typically includes descriptions of significant alternatives to the 

proposed rule, differing compliance or reporting requirements or timetables that take into account 

the resources available to small entities, and the clarification, consolidation, or simplification of 

compliance and reporting requirements for small entities.4 This SER meeting involved no 

preparation and distribution of these clarifications, consolidations or simplifications of the 

EPA regulatory options. 

 The highly abbreviated nature of this particular small business review panel that has been 

established for the EGU MACT rule prevents small WMS members from having the meaningful 

 

1

 5 U.S.C. § 203(3). 

2

 5 U.S.C. § 203(6). 

3

 5 U.S.C. § 609(b)(4); see also 5 U.S.C. § 603(b)(3), (4) and (5) and 603(c). 4 See 5 U.S.C. § 603(c). 
advisory role contemplated by SBREFA.5

 Only one panel meeting was provided and after that 

meeting, panel members were given a mere 14 days to prepare written comments.6

 The materials 

provided by EPA just prior to the only panel meeting are little more than what the Agency 

typically offers in a notice of proposed rulemaking. This is not consistent with the three prior 

SBREFA SER panel meetings where WMS was invited to participate. Those included the Clean 

Water Act Section 316 (b) cooling water intake structures/entrainment and impingement of 

aquatic organisms, the ICI Boiler MACT rulemaking in 2003 (for <25 MW utilities) and others 

held in the last ten years where the WMS has been invited to attend and participate. This SER 

panel meeting held on Dec. 2, 2010 was slightly more consistent with the very unorthodox small 

entity outreach on the GHG Tailoring rule in 2009. WMS accepted the non-SER panel approach 

on GHG because of the unusual circumstances surrounding how CO2 would be regulated and the 

cascade of regulatory actions following the CO2 reductions from the Section 202 of the Clean Air 

Act for tailpipe standards onto the regulated stationary sources of industry. However the EGU 

MACT HAPs regulation and the timing of that regulation required no truncated or 

shortened process for the SER panel. WMS believes that this one meeting makes a mockery 

of the productive goals of SBREFA and the SER panel process that have been so successful 

in identification of regulatory options in other programs. 

 On this EGU MACT rulemaking the EPA materials did not include possible rulemaking 

alternatives nor any information about possible compliance or reporting options. Moreover, the 

material lacks any results of EPA’s analyses of the data from the extensive information collection 

request (“ICR”) that EPA identified as being critical to the promulgation of an EGU MACT rule. 

As a result of the poor and inadequate preparation by the U. S. EPA and failing to meet the 

statutory requirements, WMS can offer only general comments on EGU MACT 

rulemaking. 

WMS urges that additional small business panel meetings be held following a better 

staff review of the data and that small entities (including all of those on this panel) be given 

the opportunity to comment on real regulatory alternatives once EPA reaches that point in 

its rulemaking process. WMS would be pleased to participate in that process. 

General Comments on the EGU MACT Rulemaking 

Listed below is a list of bullet items that WMS believes needs further consideration by EPA and 

that should be presented to the SER panel for comments. 

1. EPA failed to correctly identify the scope of the HAPs to be regulated

 At several places in the presentation material, EPA indicates that it must set emission 

standards that address all HAPs emitted from EGUs.7

 This conclusion is legally incorrect. 

 

5

 The presentation materials suggest that EPA was required to foreshorten the small business review 

process because it is under a consent decree which sets a tight schedule for the EGU MACT rulemaking. 

See Slide 8. However, the SBREFA review process is an important part of any major federal rulemaking. 

EPA should have factored that process into any rulemaking schedule it agreed to and defended before a 

federal district court judge. As a practical matter, the consent decree allows EPA to unilaterally return to 

the judge to request additional time to complete the EGU MACT rulemaking. If EPA feels so constrained 

by the consent decree that it cannot provide an adequate SBREFA review process, then it should ask the 

judge for a schedule extension. 

6

 While providing only 14 days for written comments by panel participants, EPA nevertheless propounds 

six slides of questions for those entities. Many of those questions were answered by all EGUs in response 

to Parts 1 and 2 of the EGU MACT ICR. Others would require far more than 14 days to provide 

meaningful responses. If EPA is serious about wanting input on the questions it posed to panel members, 

then a much longer comment period should be provided. 

7 See Slides 9 and 13. 
Because § 112(n)(1)(A) requires a predicate health finding before EPA can regulate EGUs under 

§ 112, EPA’s December 2000 regulatory determination only gave it authority to set MACT limits 

for mercury emissions from EGUs.

 EPA has offered no explanation or legal analysis for its abrupt shift in its interpretation of 

its legal authority to regulate HAP emissions from EGUs under § 112(d).8 EPA’s 2004 legal 

analysis remains the correct one -- EPA only has authority to regulate mercury emissions from 

coal-fired EGUs.9

2. The SBREFA SER failed to correctly address Setting MACT floors

 In recent § 112(d) MACT rulemakings, EPA has set MACT limits using a pollutant-bypollutant approach. Under this approach, EPA identifies the lowest emitting units to determine 

the MACT floor for a given HAP. EPA then directs its attention to the next HAP, ignoring those 

units it just determined were the “best performing” in setting the MACT floor for the first HAP, 

and establishes the next MACT floor based on a different set of units. EPA repeats this process 

until MACT floors have been set for all HAPs. The end result is a set of MACT floors that do not 

represent the emission controls achieved by an actual, best-performing unit. Instead, they reflect 

the performance of a hypothetical, ideal unit that does not exist in the real world.

 Section 112(d)(3) of the CAA expressly requires that emissions limitation for new units 

should not be less stringent “than the emissions control that is achieved in practice by the best 

controlled similar source.” For existing units, the emission standards “shall not be less stringent, 

and may be more stringent than -- the average emissions limitation achieved by the best 

performing 12 percent of sources.” CAA § 112(d)(3)(A) (emphasis added). Section 112(a) 

defines major and area sources as any “stationary source located within a contiguous area and 

under common control.” That section also defines the term “stationary source” as having the 

same meaning as that term has under CAA § 111(a). That subsection of the CAA defines a 

“stationary source” as “any building, structure, facility, or installation which emits or may emit 

any air pollutant.” CAA § 111(a)(3). 

 These statutory provisions reveal a clear congressional intent that MACT floors must be 

based on the actual performance of an actual source or sources. These statutory provisions do not 

allow MACT floors to be set on the basis of a hypothetical, ideal units nor do they allow the 

“emissions control” achieved by the best sources to be determined using a pollutant-by-pollutant 

approach on a changing group of best performing units.

 As a factual matter, EPA’s pollutant-by-pollutant approach makes no sense when applied 

to EGUs. By myopically focusing of one HAP at a time, EPA misses the antagonistic effects of 

given HAP limit will have on other regulated emissions. For example, the production of Carbon 

Monoxide (CO) during the combustion process in an EGU boiler is inversely related to NOx

production. If EPA were to set a surrogate CO limit for organic emissions, plants could not meet 

that limit if they were also required to minimize its NOx emissions. 

3. Although the SBREFA SER panel did discuss Subcategorization, the discussions of 

Subcategorization were inadequate and overly brief.

 For a source category as broad and diverse as coal- and oil-fired power plants, EPA must 

establish subcategories before setting MACT limits. Section 112(d)(1) allows EPA to distinguish 

among “classes, types and sizes of sources” in setting MACT limits. In the presentation material, 

 

8

 This is another example of why this small business panel process is so deficient. The Agency has 

drastically shifted its legal analysis of § 112 with huge resultant regulatory implications without any 

explanation. Small entities are left to try to divine EPA’s logic. 

9

 Of course, EPA’s legal authority to regulate mercury emissions hinges on the factual adequacy of its 

December 2000 regulatory determination. In 2004, EPA admitted that its December 2000 finding was 

factually in error. As the rulemaking record now stands, that conclusion remains valid. 
EPA explains that it will evaluate a number of possible subcategorization approaches including 

boiler design, coal rank, unit type, oil type, and duty cycle. All of these factors are reasonable 

bases for subcategorization. EPA should add the size of an EGU to the list of 

subcategorization approaches it considers. Beyond this general observation, WMS cannot 

provide more specific comments because of the lack of any analyses of the ICR data. However, 

WMS hopes to identify other subcategorization concepts during a more detailed and effective 

SBREFA panel and during the official comment period after the proposed rule has been 

published. 

 Closely related to the issue of subcategorization is the question of whether EPA should 

set separate § 112 limits for EGUs that are area sources. WMS discusses below why EPA should 

set area source limits for EGUs. 

4. Variability of pollutants:

 The emissions of hazardous air pollutants are highly variable from a given EGU, even the 

best performing ones. The D.C. Circuit in National Lime Ass’n v. EPA held that where a statute 

requires a standard to be “achievable,” it must be achievable “under most adverse circumstances 

which can reasonably be expected to recur.” 627 F.2d 416, 431 n.46 (D.C. Cir. 1980). The court 

expanded on this holding in Sierra Club v. EPA, 167 F.3d 658, 665 (D.C. Cir. 1999), when it 

stated that “[i]t is reasonable to suppose that if an emission standard is as stringent as ‘the 

emissions control that is achieved in practice’ by a particular unit, then that particular unit will 

not violate the standard.” In order to assure that an emission limit is set at a level the best 

performing source(s) will not violate, EPA must assess the variability in emissions of that unit. 

See Mossville Environmental Action Now v. EPA, 370 F.3d 1232, 1242 (D.C. Cir. 2004) (EPA’s 

standard was reasonable because EPA recognized the large variability in emissions and supported 

its standard with record data). In Sierra Club v. EPA, 255 F.3d 855, 864-65 (D.C. Cir. 2001), the 

court instructed EPA to consider the efficiency of control equipment but also non-technology 

factors that may influence the emissions of the best performing units. 

EPA’s ICR required EGUs to conduct stack sampling over a three-day period. That 

snapshot of a unit’s HAP emissions is not indicative or representative of the unit’s emissions over 

longer periods of time. EPA must account for emissions variability in order to determine the 

level of performance achieved by the best performing units. EPA’s presentation materials note 

the need to assess variability and identify three sources of variability that can affect a unit’s HAP 

emissions: (1) fuel variability (both in the coal from a single mine as well as variability at plants 

that burn coals from multiple sources), (2) performance variability and (3) load variability. The 

critical question is how EPA plans to modify the stack emissions reported during the ICR to 

account for all these sources of variability. The presentation material provided by the EPA 

does not provide a detailed answer to this question. It simply notes that EPA used an upper 

predictive level (“UPL”) of 99% in other MACT rulemakings without explaining how it 

would apply a UPL to the specific facts of the EGU MACT rule. WMS cannot provide 

meaningful comments on EPA’s variability adjustments without more detailed information 

from EPA. What remains essential is that EPA properly and fully account for variability in 

setting MACT limits when proposing any rule. 

5. Treatment of non-detects

 Many HAP measurements made during the EGU ICR were at or below method detection 

and method quantitation limits. In addition, detection limit information was inconsistently 

reported by ICR test contractors. How EPA uses these very low measurements will have 

significant impacts on the MACT floors EPA calculates as well as later compliance 

demonstrations. EPA’s presentation material fails to explain how EPA will address 

measurements at or below a methods detection limit and quantitation limit. 

 A large percentage of the dioxin/furan and non-dioxin organics measurements from ICR 
testing were at or below the method detection limit. For those two HAP categories, EPA should 

establish work practice standards instead of setting MACT limits. Section 112(h) of the CAA 

allows EPA to set work practice standards where it is not feasible to prescribe or enforce an 

emission standard. It is not feasible to enforce an emission limit when the uncertainty about the 

accuracy of a compliance measurement is as great as the measurement being report. This is the 

case when actual emissions are near the method detection limit. A work practice standard is the 

best way to avoid compliance issues where actual emissions at or below the detection and 

quantitation limits of a method. 

6. The use of alternative health based limits under § 112(d)(4)

 Section 112(d)(4) is designed to prevent the promulgation of unduly stringent emission 

limits simply for the sake of regulation. Section 112(d)(4) allows EPA to set health-based limits 

for certain HAPs based on established health thresholds as an alternative to promulgating 

technology based limits under § 112(d)(3). Section 112(d)(4) applies to non-carcinogenic HAPs10

for which EPA has established a health threshold such as a reference concentration (“RfC”) or a 

reference dose (“RfD”). EPA defines a reference concentration in its IRIS database as “[a]n 

estimate (with uncertainty spanning perhaps an order of magnitude) of a continuous inhalation 

exposure to the human population (including sensitive subgroups) that is likely to be without an 

appreciable risk of deleterious effects during a lifetime.”11 Thus, human exposures to a HAP at 

levels below its RfC are considered “safe”, particularly given the uncertainty factors that EPA 

uses in its derivation of a RfC. 

 Section § 112(d)(4)’s inclusion in the 1990 CAA Amendments indicates a congressional 

intent to retain the health endpoint of the original § 112 -- protection of public health with an 

ample margin of safety.12 If the emissions of a given HAP from all sources in a source category 

are at a level where public health is protected with an ample margin of safety, then there is no 

practical need for or benefit from further regulation. WMS strongly urges that EPA should set 

health-base standards under § 112(d)(4) when facts support its use, such as for acid gas 

emissions from coal-fired EGUs. 

7. Monitoring

A number of SBREFA provisions recognize the significant impacts monitoring and 

recordkeeping requirements can have on small entities. Federal agencies are encouraged to find 

ways to lessen the impact of monitoring and recordkeeping requirements on those entities. Small 

entities do not possess the monetary resources, manpower, or technical expertise needed to 

operate cutting-edge monitoring techniques such as mercury and PM CEMs. EPA should 

develop more limited monitoring requirements for small EGUs. Unfortunately, EPA’s 

presentation materials do not discuss any monitoring alternatives so more detailed comments are 

not possible. This was a prime example of a failure by the EPA staff to identify monitoring 

alternatives that could have been offered during the SER panel. 

EPA Should Establish Area Source Standards

 Section 112 of the CAA allows EPA to set area source standards for those stationary 

sources that do not emit or have the potential to emit more than 10 tons/yr of any individual HAP 

and 25 tons/yr of all HAPs.13 If EPA decides to set an area source standard, it must use 

 

10 Almost without exception, EPA assumes a linear, no-threshold dose-effect relationship for carcinogens. 

11 The definition for a reference dose is essentially the same except it focuses exposure by pathways other 

than inhalation. 

12 The ample margin of safety concept also underlies the current residual risk provisions of CAA § 112(f). 

13 A “major source” is defined in CAA § 112(a)(1) as a stationary source that emits HAPs above the 10 
“generally available control technologies or management practices by such sources to reduce 

emissions of hazardous air pollutants.”14 Congress included an area source option in § 112(d) as 

recognition that the risks posed by HAP emissions from area sources were far smaller than the 

ones posed by major sources and that less stringent rulemaking standards were appropriate. 

Many EGUs owned by small entities are area sources. Some of these units are small (e.g. less 

than 100 MWs) and thus have relatively low HAP emissions. Others employ combustion 

processes (e.g. fluidized bed technology) or have installed control equipment (e.g. scrubbers) that 

reduce HAP emissions to levels that qualify them as area sources. One of the few positive 

moments of the SER SBREFA panel meeting on December 2, 2010 was the point where we 

discussed the option of using area source standards. WMS strongly encourages the EPA to 

use area source standards for controlling mercury from smaller coal fired power plants.

 EPA should exercise its discretion, as it has done in other § 112 rulemakings,15 and set 

separate area source standards for coal- and oil-fired EGUs.16 Area source rules would lessen the 

regulatory burdens of a § 112 EGU rule on many small entities. 

Small Entities Face Significant Compliance Problems with Any EGU 

MACT Rule

 CAA § 112(i)(3)(A) requires existing sources to comply with a MACT rule no later than 

three years after the effective date of the MACT rule. Other provisions of § 112(i) provide 

possible extensions of the compliance date: one year by the EPA Administrator (or a State if it 

has implementation authority),17 and an additional two years by a Presidential exemption.18 

While the entire utility industry will face great challenges to comply with a MACT standard 

within three years, small municipal EGUs will face far greater problems. It is highly unlikely 

those units will be able to meet a three-year deadline and EPA should extend the compliance 

deadline for those units as part of any final MACT rule. 

 The challenges for WMS is that it is located in an area where from our roof we can see 

three large (greater than 500 MW) coal fired power plants Those plants, simply by their size, will 

absorb all the engineering, suppliers, installers, and other resources necessary to comply with the 

regulations. Recently, MWS investigated converting our hot side ESP to a fabric filter and hired 

Black & Veatch to conduct a preliminary analysis. That anaylsis concluded that it would take a 

minimum of 40 months to complete the project. That analysis did not take into account having to 

compete for resources with 500 – 3200MW power plants. 

Municipal utilities that qualify as small entities typically own one or two EGUs. If 

stringent emission limits are imposed by an EGU MACT rule, utilities across the country will 

 

tons/yr and 25 ton/yr thresholds. An “area source” is defined in CAA § 112(a)(2) as any stationary source 

that is not a major source. 

14 CAA § 112(d)(5). 

15 For example, EPA recently proposed area sources standards for certain industrial boilers. 16 On Slide 7 of EPA’s presentation material, the Agency notes that “[t]he section 112 definition of EGUs 

does not distinguish between area and major sources.” One could interpret this bullet as suggesting that 

EPA believes it lacks legal authority to set area sources limits for EGUs. The definition of an “electric 

utility steam generating unit” in CAA § 112(a)(8) does not limit EPA’s legal authority to set area source 

limits for those facilities. The most obvious reason an EGU definition was included in § 112(a) was 

because one was needed to identify which units were subject to the unique provisions of CAA 

§ 112(n)(1)(A). Furthermore, Congress had already included generic definitions of “major” and “area” 

sources in § 112(a) so there was no need to include those terms in the later definition of an “electric utility 

steam generating unit.” 

17 CAA § 112(i)(3)(B) 

18 CAA § 112(i)(4). The Presidential exemption can be granted more than once. 
scramble to secure the equipment, contractors and skilled craftsmen needed to install new control 

equipment. Large utilities have leverage to get their plants retrofitted first. Small municipal 

utilities will find themselves at the end of a long line, making it highly unlikely that new control 

equipment can be installed within three years. 

 Small municipal utilities face additional daunting problems in complying with a MACT 

rule. The financing of new control equipment will be largely borne by the community served by 

the municipal utility. WMS members that qualify as small entities serve smaller communities 

that do not have large sums of money on hand to pay for extensive plant additions. Most 

municipals will need to seek external funding before beginning any design or construction 

activities 

 Some municipal power plants are also located very close to the population they serve. 

Those plants face space constraints that will prevent them for installing additional control 

equipment. 

 For all these reasons, EPA should provide small entities additional time to comply with 

the EGU MACT rule. 

Conclusion

While WMS appreciates being invited to attend the December 2, 2010 SBREFA SER panel 

meeting as an observer or viewer, we believe that this process was inadequate, hastily convened, 

lacking in any serious regulatory alternatives to be offered for discussion, and lacking in any 

sincere effort to identify ways to reduce the costs and burdens of the largest single regulation in 

the utility sector. WMS also believes that the EPA has given only cursory thought to the 

reliability impacts to all of the various EPA regulations hitting the utility sector from 2013-2020 

that are best identified on the diagram on page 3. WMS believes that the SER panelists should 

be re-convened (by phone or in person) after the EPA has more thoroughly evaluated the 

sampling data and outlined several technical options and regulatory alternatives. These 

regulatory alternatives should include subcategorization and GACT controls and area 

source controls amongst other options. Any regulatory options to reduce the cost to the many 

electric utility small party entities under SBREFA will also benefit the hundreds of thousands of 

commercial customers that are also SBREFA qualified commercial and industrial customers of 

electricity provided by public power. 

James R. French 

Assistant to the General Manager 

Wyandotte Municipal Services 

3005 Biddle 

Wyandotte, MI 48192 

jfrench@wyan.org

Phone: 734-324-7114 
Utility MACT Small Business Review Panel - Comments

Cornwell, Laura 

to: 

RobertJ Wayland, Mary Johnson, Madeline Barch, David.rostker@sba.gov, 

Cortney_Higgins@omb.eop.gov 

12/16/2010 04:05 PM 

Show Details 

Attached are the American Public Power Association’s (APPA) comments on the Small Business Review Panel for

EPA’s Rulemaking for Hazardous Air Pollutant Emissions from Coal‐ and Oil‐Fired Electric Utility Steam

Generating Units.

  

We have also attached the comments of two of our members, Atlantic Municipal Utilities and the Marquette

Board of Light & Power, which were submitted earlier today.

  

Thank you,

  

  

Laura Cornwell 

Engineering & Environmental Assistant 

American Public Power Association 

1875 Connecticut Ave. NW, Suite 1200, Washington, DC 20009-5715 

P: 202.467.2942 

F: 202.495.7459 

LCornwell@publicpower.org

www.publicpower.org

  

Page 1 of 1

file://C:\Documents and Settings\mbarch\Local Settings\Temp\notesFCBCEE\~web9760.htm 1/6/2011
- 1 -

Small Business Review Panel for EPA‟s Rulemaking for Hazardous Air Pollutant Emissions 

from Coal- and Oil-Fired Electric Utility Steam Generating Units

What is APPA

The American Public Power Association (APPA) is the national service organization 

representing the interests of the more than 2,000, not-for-profit municipal and other state and 

local community-owned electric utilities that collectively provide electricity to approximately 45 

million Americans. These utilities, or “public power” systems, are among the most diverse of 

the electric utility sectors, representing utilities in small, medium and large communities in 49 

states (all but Hawaii). Seventy percent of public power systems are located in cities with 

populations of 10,000 or less. APPA was created in 1940 as a non-profit, non-partisan 

organization. Its purpose is to advance the public policy interests of its members and their 

consumers, and to provide member services to ensure adequate, reliable electricity at a 

reasonable price with the proper protection of the environment.

Overall, public power accounts for about 16 percent of all kilowatt-hour sales to retail 

electricity consumers. Approximately 46% of the megawatt hours of electricity produced by 

public power systems are generated using coal. Moreover, more than 90% of public power 

utility systems meet the definition and qualify as small businesses under the Small Business Act 

and the Small Business Regulatory Enforcement and Fairness Act of 1996 (SBREFA).

The significance of the EGU MACT standard

There are many environmental regulations hitting the utility sector in a window roughly 

bounded by 2014-2020 that require enormous investments, retirements, capital expenditures, and 

the raising of financial requirements through both cash and bonds at municipal public power 

utilities. These investments cannot be underestimated. Nor can the reliability issues be 

underestimated. It has been estimated by many that anywhere from 30-50% of the remaining 

coal-fired power plants might make the decision to close those coal fired plants due to the 
- 2 -

combination of MACT standards (likely requiring many control technologies) and scrubbers 

required by 2014 in many of the 31 states covered by Regional Transport (RT) rule‟s inadequate 

state allocations. These regulations will also be amidst a series of tighter ozone, PM 2.5, SO2, 

NOx, and the new regulations for NSPS for Greenhouse gases (including CO2, methane, and 

SF6). Additionally, many power plants will face tighter controls for various water pollutants and 

possibly cooling towers to minimize aquatic organism harms from intake structures. These are 

best exemplified in the following diagram. These do not include other investments by power 

plants such as EPA regulations such as Toxic Substances Control Act (or TSCA) reporting, PCB 

phase out, transformer replacement and NERC‟s costly and time-consuming reliability standards.

Given the importance of these regulations, it is all the more important that the SBREFA 

SER panel for utility MACT (oil and coal) be thorough, thoughtful and valuable to the EPA, 

OMB and to the industry that SBREFA is designed to affect.
- 3 -

Possible Timeline for Environmental Regulatory 

Requirements for the Utility Industry

Ozone

PM2.5

'08 '09 '10 '11 '12 '13 '14 '15 '16 '17

Beginning 

CAIR Phase I 

Seasonal 

NOx Cap

HAPs MACT 

proposed 

rule 

Beginning 

CAIR Phase 

II Seasonal 

NOx Cap

Revised 

Ozone 

NAAQS

Begin 

CAIR 

Phase I 

Annual 

SO2 Cap

-- adapted from Wegman (EPA 2003) Updated 2.15.10 

Beginning CAIR 

Phase II Annual 

SO2 & NOx Caps

Next PM2.5 

NAAQS 

Revision

Next Ozone 

NAAQS Revision

SO2 Primary 

NAAQS 

SO2/NO2

Secondary 

NAAQS

NO2 

Primary 

NAAQS

SO2/NO2

New PM-2.5 NAAQS 

Designations

CAMR & 

Delisting 

Rule vacated

Hg/HAPS

Final EPA 

Nonattainment 

Designations

PM-2.5

SIPs due 

(‘06)

Proposed CAIR 

Replacement 

Rule Expected

HAPS MACT 

final rule 

expected

CAIR 

Vacated

HAPS MACT 

Compliance 3 yrs 

after final rule

CAIR 

Remanded

CAIR

Begin 

CAIR 

Phase I 

Annual 

NOx Cap

PM-2.5 

SIPs due 

(‘97)

316(b) proposed

rule expected

316(b) final rule

expected

316(b) Compliance

3-4 yrs after final rule Effluent 

Guidelines

proposed rule

expected

Water

Effluent Guidelines

Final rule expected Effluent Guidelines

Compliance 3-5 yrs 

after final rule

Begin Compliance 

Requirements under 

Final CCB Rule 

(ground water 

monitoring, double 

monitors, closure, 

dry ash conversion)

Ash

Proposed 

Rule for CCBs 

Management

Final 

Rule for 

CCBs 

Mgmt

Final CAIR 

Replacement 

Rule Expected

Compliance with 

CAIR 

Replacement Rule

CO2

CO2

Regulation

Reconsidered 

Ozone 

NAAQS
- 4 -

The American Public Power Association and its members appreciate the opportunity to 

participate in the small business review panel for EPA‟s rulemaking to set maximum achievable 

control technology (MACT) standards for hazardous air pollutant (HAP) emissions from coaland oil-fired electric utility steam generating units (EGUs) through this panel convened under the 

Small Business Regulatory Enforcement Fairness Act of 1996 (or a SBREFA SER panel). 

APPA has been designated a “viewer” and many of the panel members are from public power 

utilities across the country.

 The EGU MACT rulemaking has the potential to be one of the most expensive 

rulemakings the utility industry has ever faced. Its impact on APPA‟s smaller members could be 

enormous, forcing them either to install extensive new pollution control equipment or even to 

close certain units. As set out in the statute, EPA must carefully consider the impact its EGU 

MACT rule will have on small entities and must act to lessen the burden of that rule on those

entities.

The Small Business Regulatory Fairness Act (SBREFA) was enacted by Congress to 

provide small entities a meaningful voice in major federal rulemakings. Among the Act‟s goals 

are to encourage the “effective participation” of small business in the federal regulatory process1

and to create a more cooperative regulatory environment among agencies and small businesses 

that is less punitive and more solution oriented.2 Section 609 of SBREFA envisions that small 

business panels will review “any material the agency has prepared in connection with this 

chapter” including information required to be part of the initial regulatory flexibility analysis.3 A

regulatory flexibility analysis typically includes descriptions of significant alternatives to the 

proposed rule, differing compliance or reporting requirements or timetables that take into 

account the resources available to small entities, and the clarification, consolidation, or 

simplification of compliance and reporting requirements for small entities.4 This SER meeting 

involved no preparation and distribution of these clarifications, consolidations or 

simplifications of the EPA regulatory options by the EPA.

 

1

5 U.S.C. § 203(3).

2

5 U.S.C. § 203(6).

3

5 U.S.C. § 609(b)(4); see also 5 U.S.C. § 603(b)(3), (4) and (5) and 603(c).

4

See 5 U.S.C. § 603(c).
- 5 -

The highly abbreviated nature of this particular small business review panel that has been 

established for the EGU MACT rule prevents small APPA members from having the meaningful 

advisory role contemplated by SBREFA.5 Only one panel meeting was provided and after that 

meeting, panel members were given a mere 14 days to prepare written comments.6 The 

materials provided by EPA just prior to the only panel meeting are little more than what the 

Agency typically offers in a notice of proposed rulemaking. This is not consistent with the three 

prior SBREFA SER panel meetings on other proposed regulations where APPA was invited to 

participate. Those included the Clean Water Act Section 316 (b) cooling water intake 

structures/entrainment and impingement of aquatic organisms, the ICI Boiler MACT rulemaking 

in 2003 (for <25 MW utilities) and others held in the last ten years where the APPA has been 

invited to attend and participate. This SER panel meeting held on Dec. 2, 2010 was slightly more 

consistent with the very unorthodox small entity outreach on the GHG Tailoring rule in 2009. 

APPA accepted the non-SER panel approach on GHG because of the unusual circumstances 

surrounding how CO2 would be regulated and the cascade of regulatory actions following the 

CO2 reductions from the Section 202 of the Clean Air Act for tailpipe standards onto the 

regulated stationary sources of industry. However the EGU MACT HAPs regulation and the 

timing of that regulation required no truncated or shortened process for the SER panel. 

APPA believes that this one meeting makes a mockery of the productive goals of SBREFA 

and the SER panel process that have been so successful in identification of regulatory 

options in other programs.

On this EGU MACT rulemaking the EPA materials did not include possible rulemaking 

alternatives nor any information about possible compliance or reporting options. Moreover, the 

material lacked any results of EPA‟s analyses of the data from the extensive information

 

5 The presentation materials suggest that EPA was required to foreshorten the small business review process because 

it is under a consent decree which sets a tight schedule for the EGU MACT rulemaking. See Slide 8. However, the 

SBREFA review process is an important part of any major federal rulemaking. EPA should have factored that 

process into any rulemaking schedule it agreed to and defended before a federal district court judge. As a practical 

matter, the consent decree allows EPA to unilaterally return to the judge to request additional time to complete the 

EGU MACT rulemaking. If EPA feels so constrained by the consent decree that it cannot provide an adequate 

SBREFA review process, then it should ask the judge for a schedule extension.

6 While providing only 14 days for written comments by panel participants, EPA nevertheless propounds six slides 

of questions for those entities. Many of those questions were answered by all EGUs in response to Parts 1 and 2 of 

the EGU MACT ICR. Others would require far more than 14 days to provide meaningful responses. If EPA is 

serious about wanting input on the questions it posed to panel members, then a much longer comment period should 

be provided. 
- 6 -

collection request (ICR) that EPA identified as being critical to the promulgation of an EGU

MACT rule. As a result of the poor and inadequate preparation by the U.S. EPA and 

failing to meet the statutory requirements, APPA can offer only general comments on EGU 

MACT rulemaking in these comments.

APPA urges that additional small business SER panel meetings be held following a 

better staff review of the data and that small entities (including all of those on this panel) be 

given the opportunity to comment on real regulatory alternatives once EPA reaches that 

point in its rulemaking process. APPA would be pleased to participate in that process.

General Comments on the EGU MACT Rulemaking

1. EPA failed to correctly identify the scope of the HAPs to be regulated

At several places in the presentation material, EPA indicates that it must set emission 

standards that address all HAPs emitted from EGUs.7 This conclusion is legally incorrect. 

EGUs are treated uniquely under § 112 of the Clean Air Act (CAA). Section 112(n)(1)(A) 

requires EPA to study the hazards to public health reasonably anticipated to occur as a result of 

emissions from EGUs “after the imposition of the other requirements of the CAA.” After 

considering the results of that study, the EPA Administrator must then decide if further 

regulation is “appropriate and necessary.” EPA completed the EPA Utility Study in February 

1998. In December 2000, the EPA Administrator found that regulation of coal- and oil-fired 

EGUs was appropriate and necessary under § 112 and proceeded to list those units under 

§ 112(c).8EPA‟s notice of regulatory finding focused solely on the risks to public health posed 

by mercury emissions from coal-fired power plants. Because § 112(n)(1)(A) requires a predicate 

health finding before EPA can regulate EGUs under § 112, EPA‟s December 2000 regulatory

determination only gave it authority to set MACT limits for mercury emissions from EGUs.

When EPA first proposed MACT limits for EGUs in 2004, it went to great lengths to 

explain why it only had legal authority to set mercury MACT limits for coal-fired EGUs.9 

 

7

See Slides 9 and 13.

8

65 Fed. Reg. 79,825 (Dec. 20, 2000).

9

See 69 Fed. Reg. 4,659-61 (Jan. 30, 2004).
- 7 -

Nothing has changed as a matter of law since EPA offered that analysis of its legal authority to 

regulate EGUs. The D.C. Circuit‟s later vacatur of EPA‟s removal of EGUs from the list of 

§ 112(c) source categories in State of New Jersey v. EPA, 517 F.3d 574 (2008), avoided 

addressing legal arguments about the legality and scope of EPA‟s December 2000 regulatory 

determination. EPA has offered no explanation or legal analysis for its abrupt shift in its 

interpretation of its legal authority to regulate HAP emissions from EGUs under § 112(d).

10

 

EPA‟s 2004 legal analysis remains the correct one -- EPA only has authority to regulate mercury 

emissions from coal-fired EGUs.11

2. The SBREFA SER failed to correctly address Setting MACT floors

In recent § 112(d) MACT rulemakings, EPA has set MACT limits using a pollutant-bypollutant approach. Under this approach, EPA identifies the lowest emitting units to determine 

the MACT floor for a given HAP. EPA then directs its attention to the next HAP, ignoring those 

units it just determined were the “best performing” in setting the MACT floor for the first HAP, 

and establishes the next MACT floor based on a different set of units. EPA repeats this process 

until MACT floors have been set for all HAPs. The end result is a set of MACT floors that do 

not represent the emission controls achieved by an actual, best-performing unit. Instead, they 

reflect the performance of a hypothetical, ideal unit that does not exist in the real world.

Section 112(d)(3) of the CAA expressly requires that emissions limitation for new units 

should not be less stringent “than the emissions control that is achieved in practice by the best 

controlled similar source.” For existing units, the emission standards “shall not be less stringent, 

and may be more stringent, than the average emissions limitation achieved by the best 

performing 12 percent of sources.” CAA § 112(d)(3)(A) (emphasis added). Section 112(a) 

defines major and area sources as any “stationary source located within a contiguous area and 

under common control.” That section also defines the term “stationary source” as having the 

same meaning as that term has under CAA § 111(a). That subsection of the CAA defines a 

 

10 This is another example of why this small business panel process is so deficient. The Agency has drastically 

shifted its legal analysis of § 112 with huge resultant regulatory implications without any explanation. Small entities 

are left to try to divine EPA‟s logic.

11 Of course, EPA‟s legal authority to regulate mercury emissions hinges on the factual adequacy of its December 

2000 regulatory determination. In 2004, EPA admitted that its December 2000 finding was factually in error. As 

the rulemaking record now stands, that conclusion remains valid.
- 8 -

“stationary source” as “any building, structure, facility, or installation which emits or may emit 

any air pollutant.” CAA § 111(a)(3).

These statutory provisions reveal a clear congressional intent that MACT floors must be 

based on the actual performance of an actual source or sources. These statutory provisions do 

not allow MACT floors to be set on the basis of a hypothetical, ideal units nor do they allow the 

“emissions control” achieved by the best sources to be determined using a pollutant-by-pollutant 

approach on a changing group of best performing units.

As a factual matter, EPA‟s pollutant-by-pollutant approach makes no sense when applied 

to EGUs. By focusing on one HAP at a time, EPA misses the antagonistic effects of given HAP 

limit will have on other regulated emissions. For example, the production of Carbon Monoxide 

(CO) during the combustion process in an EGU boiler is inversely related to NOx production. If 

EPA were to set a surrogate CO limit for organic emissions, plants could not meet that limit if 

they were also required to minimize its NOx emissions. 

3. Although the SBREFA SER panel did discuss Subcategorization, the discussions of 

Subcategorization were inadequate and overly brief.

For a source category as broad and diverse as coal- and oil-fired power plants, EPA must 

establish subcategories before setting MACT limits. Section 112(d)(1) allows EPA to 

distinguish among “classes, types and sizes of sources” in setting MACT limits. In the 

presentation material, EPA explains that it will evaluate a number of possible subcategorization

approaches including boiler design, coal rank, unit type, oil type, and duty cycle. All of these 

factors are reasonable bases for subcategorization. EPA should add the size of an EGU to the 

list of subcategorization approaches it considers when proposing the MACT rule. Beyond 

this general observation, APPA cannot provide more specific comments because of the lack of 

any analyses of the ICR data. However, APPA hopes to identify additional subcategorization 

concepts during a more detailed and effective SBREFA panel and during the official comment 

period after the proposed rule has been published.

Closely related to the issue of subcategorization is the question of whether EPA should 

set separate § 112 limits for EGUs that are area sources. APPA discusses below why EPA should 

set area source limits for EGUs.
- 9 -

4. Variability of pollutants:

The emissions of hazardous air pollutants are highly variable from a given EGU, even the 

best performing ones. The D.C. Circuit in National Lime Ass’n v. EPA held that where a statute 

requires a standard to be “achievable,” it must be achievable “under most adverse circumstances 

which can reasonably be expected to recur.” 627 F.2d 416, 431 n.46 (D.C. Cir. 1980). The court 

expanded on this holding in Sierra Club v. EPA, 167 F.3d 658, 665 (D.C. Cir. 1999), when it 

stated that “[i]t is reasonable to suppose that if an emission standard is as stringent as „the 

emissions control that is achieved in practice‟ by a particular unit, then that particular unit will 

not violate the standard.” In order to assure that an emission limit is set at a level the best 

performing source(s) will not violate, EPA must assess the variability in emissions of that unit. 

See Mossville Environmental Action Now v. EPA, 370 F.3d 1232, 1242 (D.C. Cir. 2004) (EPA‟s 

standard was reasonable because EPA recognized the large variability in emissions and 

supported its standard with record data). In Sierra Club v. EPA, 255 F.3d 855, 864-65 (D.C. Cir. 

2001), the court instructed EPA to consider the efficiency of control equipment but also nontechnology factors that may influence the emissions of the best performing units.

EPA‟s ICR required EGUs to conduct stack sampling over a three-day period. That 

snapshot of a unit‟s HAP emissions is not indicative or representative of the unit‟s emissions 

over longer periods of time. EPA must account for emissions variability in order to determine 

the level of performance achieved by the best performing units. EPA‟s presentation materials 

note the need to assess variability and identify three sources of variability that can affect a unit‟s 

HAP emissions: (1) fuel variability (both in the coal from a single mine as well as variability at 

plants that burn coals from multiple sources); (2) performance variability; and (3) load 

variability. The critical question is how EPA plans to modify the stack emissions reported 

during the ICR to account for all these sources of variability. The presentation material provided

by the EPA does not provide a detailed answer to this question. It simply notes that EPA used an 

upper predictive level (“UPL”) of 99% in other MACT rulemakings without explaining how it 

would apply a UPL to the specific facts of the EGU MACT rule. APPA cannot provide 

meaningful comments on EPA’s variability adjustments without more detailed information 

from EPA. What remains essential is that EPA properly and fully account for variability in 

setting MACT limits when proposing any rule.
- 10 -

5. Treatment of non-detects

Many HAP measurements made during the EGU ICR were at or below method detection 

and method quantitation limits. In addition, detection limit information was inconsistently 

reported by ICR test contractors. How EPA uses these very low measurements will have 

significant impacts on the MACT floors EPA calculates as well as later compliance 

demonstrations. EPA’s presentation material fails to explain how EPA will address 

measurements at or below a methods detection limit and quantitation limit.

A large percentage of the dioxin/furan and non-dioxin organics measurements from ICR 

testing were at or below the method detection limit. For those two HAP categories, EPA should 

establish work practice standards instead of setting MACT limits. Section 112(h) of the CAA 

allows EPA to set work practice standards where it is not feasible to prescribe or enforce an 

emission standard. It is not feasible to enforce an emission limit when the uncertainty about the 

accuracy of a compliance measurement is as great as the measurement being report. This is the 

case when actual emissions are near the method detection limit. A work practice standard is the 

best way to avoid compliance issues where actual emissions at or below the detection and 

quantitation limits of a method.

6. The use of alternative health based limits under § 112(d)(4)

Section 112(d)(4) is designed to prevent the promulgation of unduly stringent emission 

limits simply for the sake of regulation. Section 112(d)(4) allows EPA to set health-based limits 

for certain HAPs based on established health thresholds as an alternative to promulgating 

technology based limits under § 112(d)(3). Section 112(d)(4) applies to non-carcinogenic 

HAPs

12 for which EPA has established a health threshold such as a reference concentration 

(RfC) or a reference dose (RfD). EPA defines a reference concentration in its IRIS database as 

“[a]n estimate (with uncertainty spanning perhaps an order of magnitude) of a continuous 

inhalation exposure to the human population (including sensitive subgroups) that is likely to be 

without an appreciable risk of deleterious effects during a lifetime.”13 Thus, human exposures to 

 

12 Almost without exception, EPA assumes a linear, no-threshold dose-effect relationship for carcinogens.

13 The definition for a reference dose is essentially the same except it focuses exposure by pathways other than 

inhalation.
- 11 -

a HAP at levels below its RfC are considered “safe”, particularly given the uncertainty factors 

that EPA uses in its derivation of a RfC.

Section § 112(d)(4)‟s inclusion in the 1990 CAA Amendments indicates a congressional 

intent to retain the health endpoint of the original § 112 -- protection of public health with an 

ample margin of safety.14 If the emissions of a given HAP from all sources in a source category 

are at a level where public health is protected with an ample margin of safety, then there is no 

practical need for or benefit from further regulation. APPA strongly urges that EPA should 

set health-base standards under § 112(d)(4) when facts support its use, such as for acid gas 

emissions from coal-fired EGUs.

7. Monitoring

A number of SBREFA provisions recognize the significant impacts monitoring and 

recordkeeping requirements can have on small entities. Federal agencies are encouraged to find 

ways to lessen the impact of monitoring and recordkeeping requirements on those entities. Small

entities do not possess the monetary resources, manpower, or technical expertise needed to 

operate cutting-edge monitoring techniques such as mercury and Particulate Matter or PM 

CEMs. EPA should develop more limited monitoring requirements for small EGUs. 

Unfortunately, EPA‟s presentation materials do not discuss any monitoring alternatives so more 

detailed comments are not possible. This was a prime example of a failure by the EPA staff to 

identify monitoring alternatives that could have been offered during the SER panel.

EPA Should Establish Area Source Standards

Section 112 of the CAA allows EPA to set area source standards for those stationary 

sources that do not emit or have the potential to emit more than 10 tons/yr of any individual HAP 

and 25 tons/yr of all HAPs.15 If EPA decides to set an area source standard, it must use 

“generally available control technologies or management practices by such sources to reduce 

 

14 The ample margin of safety concept also underlies the current residual risk provisions of CAA § 112(f).

15 A “major source” is defined in CAA § 112(a)(1) as a stationary source that emits HAPs above the 10 tons/yr and 

25 ton/yr thresholds. An “area source” is defined in CAA § 112(a)(2) as any stationary source that is not a major 

source.
- 12 -

emissions of hazardous air pollutants.”16 Congress included an area source option in § 112(d) as 

recognition that the risks posed by HAP emissions from area sources were far smaller than the 

ones posed by major sources and that less stringent rulemaking standards were appropriate. 

Many EGUs owned by small public power entities are area sources. Some of these units are 

small (e.g. less than 100 MWs) and thus have relatively low HAP emissions. Others employ 

combustion processes (e.g. fluidized bed technology) or have installed control equipment (e.g.

scrubbers) that reduce HAP emissions to levels that qualify them as area sources. One of the 

most positive moments of the SER SBREFA panel meeting on December 2, 2010 was the 

point where we discussed the option of using area source standards. APPA strongly 

encourages the EPA to use area source standards for controlling mercury from smaller 

coal fired power plants.

EPA should exercise its discretion, as it has done in other § 112 rulemakings,

17 and set 

separate area source standards for coal- and oil-fired EGUs.18 Area source rules would lessen the 

regulatory burdens of a § 112 EGU rule on many small entities.

Small Entities Face Significant Compliance Problems with Any EGU MACT Rule

CAA § 112(i)(3)(A) requires existing sources to comply with a MACT rule no later than 

three years after the effective date of the MACT rule. Other provisions of § 112(i) provide 

possible extensions of the compliance date: one year by the EPA Administrator (or a State if it 

has implementation authority),

19 and an additional two years by a Presidential exemption.20

 

While the entire utility industry will face great challenges to comply with a MACT standard 

 

16 CAA § 112(d)(5).

17 For example, EPA recently proposed area sources standards for certain industrial boilers.

18 On Slide 7 of EPA‟s presentation material, the Agency notes that “[t]he section 112 definition of EGUs does not 

distinguish between area and major sources.” One could interpret this bullet as suggesting that EPA believes it lacks 

legal authority to set area sources limits for EGUs. The definition of an “electric utility steam generating unit” in 

CAA § 112(a)(8) does not limit EPA‟s legal authority to set area source limits for those facilities. The most obvious 

reason an EGU definition was included in § 112(a) was because one was needed to identify which units were subject 

to the unique provisions of CAA § 112(n)(1)(A). Furthermore, Congress had already included generic definitions of 

“major” and “area” sources in § 112(a) so there was no need to include those terms in the later definition of an 

“electric utility steam generating unit.”

19 CAA § 112(i)(3)(B)

20 CAA § 112(i)(4). The Presidential exemption can be granted more than once. 
- 13 -

within three years, small municipal EGUs will face far greater problems. It is highly unlikely 

those units will be able to meet a three-year deadline and EPA should extend the compliance 

deadline for those units as part of any final MACT rule.

Municipal utilities that qualify as small entities typically often own only one or two 

EGUs. If stringent emission limits are imposed by an EGU MACT rule, utilities across the 

country will scramble to secure the equipment, contractors and skilled craftsmen needed to 

install new control equipment. Large utilities have leverage to get their plants retrofitted first. 

Small municipal utilities will find themselves at the end of a long line, making it highly unlikely 

that new control equipment can be installed within three years.

Small municipal utilities face additional daunting problems in complying with a MACT 

rule. The financing of new control equipment will be largely borne by the community served by 

the municipal utility. APPA members that qualify as small entities serve smaller communities 

that do not have large sums of money on hand to pay for extensive plant additions. Most 

municipals will need to seek external funding before beginning any design or construction 

activities.

Some municipal power plants are also located very close to the population they serve. 

Those plants face space constraints that will prevent them from installing additional control 

equipment.

For all these reasons, EPA should provide small entities additional time to comply with 

the EGU MACT rule.

Conclusion

While APPA appreciates being invited to attend the December 2, 2010 SBREFA SER 

panel meeting as an observer or viewer, we believe that this process was inadequate, hastily 

convened, lacking in any serious regulatory alternatives to be offered for discussion, and lacking 

in any sincere effort to identify ways to reduce the costs and burdens of the largest single 

regulation in the utility sector. APPA also believes that the EPA has given only cursory thought 

to the reliability impacts to all of the various EPA regulations hitting the utility sector from 2013-

2020 that are best identified on the diagram on page 3. APPA believes that the SER panelists 

should be re-convened (by phone or in person) after the EPA has more thoroughly 

evaluated the sampling data and outlined several technical options and regulatory 
- 14 -

alternatives. These regulatory alternatives should include subcategorization and GACT 

controls and area source controls amongst other options. Any regulatory options to reduce 

the cost to the many electric utility small party entities under SBREFA will also benefit the

hundreds of thousands of commercial customers that are also SBREFA qualified commercial and 

industrial customers of electricity provided by public power.

Thank you. For further contact at APPA:

Theresa Pugh

Director

Environmental Services

APPA

202 467 2943

tpugh@publicpower.org or tpugh@appanet.org
EGU MACT SER Review Panel Comments

Wemhoff, Bill G. 

to: 

Madeline Barch 

12/15/2010 03:12 PM 

Cc: 

Cortney_Higgins, david.rostker, RobertJ Wayland, Mary Johnson, "Johnson, Joseph", Mike Thatcher, 

rex.butler, lhopkins, jeutizi 

Show Details 

History: This message has been replied to. 

Madelyn –

Attached are comments submitted by the cooperative SERs regarding EPA’s review panel for the

Electric Generating Unit Hazardous Air Emissions Rulemaking.

By this message I am also copying others on the review panel that may have an interest in these

comments.

Please don’t hesitate to let me know if you have questions or need additional information.

Thanks for the opportunity to comment on this very important rule.

Bill Wemhoff

Sr. Principal, Environmental Policy

NRECA

ph (703) 907‐5824

<<1210SBREFA Cmts.docx>> <<Appendix B Graph.pdf>> <<Appendix B GreenMap.pdf>> <<Appendix C.doc>> 

<<AppendiixB.docx>> <<Appendix A.docx>> 

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EGU MACT SER Review Panel Comments Page 1 of 1

file://C:\Documents and Settings\mbarch\Local Settings\Temp\notesFCBCEE\~web1739.htm 1/6/2011
1 

Madelyn Barch 

Regulation Management Division 

Office of Policy 

U.S. EPA 

barch.madeline@epa.gov

Re: Small Business Review Panel for the Electric Generating Unit 

Hazardous Air Pollutant Emission Standards 

Comments 

Rural Electric Cooperatives 

December 15, 2010 

The nation’s rural electric cooperatives appreciate the opportunity to participate in 

the small business review panel regarding EPA’s rulemaking to set national standards for 

electric generating unit (“EGU”) hazardous air pollutant (“HAP”) emissions based on the 

Clean Air Act’s (“CAA”) maximum achievable control technology (“MACT”) 

provisions. 

Below is a discussion of the many potential issues that cooperatives have expressed 

concern regarding the agency’s EGU MACT rulemaking. Many of these issues were raised 

during our meeting on December 2 and are described in more detail here. 

Overall Concerns

Electric cooperatives are very concerned that EPA has not provided adequate time 

for small entities to sufficiently review a rule of this magnitude and importance. With 

only a single meeting of the review panel that included the small entity representatives 

(“SER”), and with just a two-week timeframe in which SERs are required to submit 

written comments, their input will most certainly fall far short of what was intended by 

Congress when it passed the Small Business Regulatory Enforcement Fairness Act 

(“SBREFA”). 

Furthermore, EPA has not provided rule alternatives or sufficient data and 

information in a useable form that would allow small entities to assess the potential 

impact of this rulemaking. They, therefore, are limited in their ability to provide 
2 

meaningful input on critical issues that could help shape the final rule in a way that would 

minimize the impact on small entities. 

In addition, cooperatives are concerned that EPA’s evaluation of the potential 

impacts of this rulemaking on small entities fails to account for a large number of 

potentially affected small electric cooperatives. While EPA has identified a few small 

cooperatives, we believe this is a gross underestimate of the true impact. We believe as 

many as 572 small cooperatives should be included in a thorough assessment of the 

regulatory and cost impacts of this major rule. Additional information supporting this 

position is included in attachment “A” hereto. 

Finally, in its assessment, cooperatives believe EPA should consider the 

synergistic adverse impacts that this rule will have on small cooperatives in conjunction 

with the many other air-related rulemakings that the agency has ongoing. Cooperatives 

will experience disproportionately higher costs due to their greater dependence on coalfired generation. Being non-profit, all costs will have to be passed on to their consumerowners. Electric cooperative consumer-owners have household incomes about 14 

percent less than the U.S. average and use more electricity, as a percent, when compared 

to residential consumers served by investor owned utilities and municipalities. 

Furthermore, because of the special challenges that cooperatives face, cooperative rates 

are already slightly higher than neighboring utilities. The consequence is that 

rulemakings resulting in increased costs of coal-based electric power, particularly in rural 

areas served by cooperatives, will have significant negative impacts on rural consumer 

owners, economic development and jobs. Included in appendix “B” is additional 

information describing some of the unique challenges facing cooperatives. 

General Concerns Regarding the Potential Form of an EGU MACT Rule

EPA’s final rule should be limited to mercury (“Hg”) control only. The agency 

has not determined that emissions of other hazardous air pollutants in the quantities 

emitted, are detrimental to human health or the environment. In 2004, when EPA 
3 

promulgated its HAPs control rule for electric generating units,1 the agency offered (at 

pages 4659-61), a detailed legal analysis of why it believed it only had authority to set 

MACT standards for mercury under Section 112(d). Cooperatives concur with that 

analysis and believe that nothing has changed legally since that time. EPA, therefore, 

should limit the scope of this EGU MACT rulemaking to controlling Hg only. 

Also, EPA has indicated that it intends to follow in this EGU MACT rulemaking, 

the same methodology it used in setting the HAP emission standards for industrial, 

commercial, and institutional boilers and process heaters2

 (“Ind. Boiler”) rule. 

Cooperatives believe that EPA’s methodology is flawed and fundamental data issues 

exist that compromise the validity of the proposed standards. Indeed, the agency has 

recently announced that it is reviewing its proposed Ind. Boiler rule and will delay 

finalization in order to ensure that the rule is practical to implement. NRECA filed 

extensive comments in response to the agency’s proposal and identified many issues of 

concern. Those comments have been included as appendix “C”, hereto. In addition, 

below is a listing of the major issues that were raised in those comments. 

 The Section 112 MACT standard must reflect the emissions control achieved by 

actual units, not hypothetical composite ones. The proposed Ind. Boiler MACT 

limits were derived by determining independently a MACT floor for each HAP or 

HAP surrogate for each subcategory of sources. Under this approach, EPA 

identified the lowest emitting units to determine the MACT floor for a given 

HAP. EPA then directs its attention to the next HAP, ignoring those units it just 

determined were the “best performing” in setting the MACT floor for the first 

HAP, and establishes the next MACT floor based on a different set of units. EPA 

repeats this process until MACT floors have been set for all HAPs emitted by 

each subcategory of industrial boilers. The end result is a set of MACT floors that 

do not represent the emission levels achieved by an actual, best-performing unit. 

 

1

 Proposed National Emission Standards for Hazardous Air Pollutants; and, in the Alternative, Proposed 

Standards of Performance for New and Existing Stationary Sources: Electric Utility Steam Generating 

Units; Proposed Rule, 69 Fed. Reg. 4652 (January 30, 2004) 

2

 National Emission Standards for Major Sources: Industrial, Commercial, and Institutional Boilers and 

Process Heaters; Proposed Rule, 75 Fed. Reg. 32006 (June 4, 2010) 
4 

Instead, they reflect the performance of a hypothetical, ideal unit that does not 

exist in the real world. As NRECA explains in more detail in its comments,3

Section 112(d)(3) of the CAA expressly requires that emissions limitation(s) for 

new units should not be less stringent “than the emissions control that is achieved 

in practice by the best controlled similar source.” For existing units, the emission 

standards shall not be less stringent than the average emissions limitation 

achieved by the best performing 12 percent of sources. EPA’s methodology for 

setting MACT floors is inconsistent with these requirements. 

 A MACT rule must address in a reasoned manner HAP emissions that are at or 

below the method detection and quantification limits. EPA’s effort to set 

emission limits for all HAPs will be greatly complicated by the fact that a number 

of HAPs are emitted at levels at or below the detection limit of the method that 

was used to collect and analyze HAP emissions during the MACT information 

collection request (“ICR”). Detection limit issues have significant impacts on 

MACT standard setting, as well as later during compliance demonstrations. 

 CAA Section 112(h) provides that if it is not feasible to prescribe or enforce an 

emission standard for control of a HAP pollutant, the Administrator may, in lieu 

thereof, promulgate a design, equipment, work practice, or operational standard. 

Electric cooperatives urge EPA to promulgate work practice standards as a 

replacement for emission limits to the fullest extent allowed. In any event, EPA 

needs to address these non-detect HAP emissions in a comprehensive fashion 

prior to setting MACT standards in its final rule. 

 The rule must account for all variability in HAP emissions. In order for a 

standard to be achievable, it must be achievable under most adverse 

circumstances which can reasonably be expected to recur. In order to ensure that 

an emission limit is set at a level that the best performing source(s) will not 

violate, EPA must assess the variability in emissions of that unit. 

 

3

 Comments by NRECA in response to Ind. Boiler rule, Docket ID No. EPA-HQ-OAR-2002-0058, dated 

August 23, 2010. 
5 

In EPA’s presentation material for its SER outreach meeting, EPA indicated that 

it will evaluate a number of possible subcategorization approaches including 

boiler design, coal rank, unit type, and duty cycle. The broad use of subcategories 

is strongly encouraged. Section 112(d)(1) of the CAA allows the Administrator 

to distinguish among “classes, types, and sizes of sources” in establishing MACT 

standards. This subcategorization language mirrors earlier language found in 

CAA Section 111. In providing EPA discretion to create subcategories, 

Section 112(d)(1) does not restrict subcategorization to cases where the “class,” 

“type” or “size” factors affect HAP emissions. The provision merely requires 

EPA to establish regulations for each category or subcategory on the schedules set 

out in Section 112. Indeed, EPA has not previously subcategorized under 

Section 111 based solely on emission effects. For example, under Section 111, 

EPA has subcategorized boilers on the basis of size (heat input) or the type of fuel 

burned (coal, oil or gas). These subcategorization decisions were based on 

feasibility and/or cost considerations, not on the level of emissions. Moreover, 

historical testing has shown that coal rank has a significant effect on Hg and 

hydrogen chloride (“HCl”) emissions. In addition, we believe the lignite coal 

rank should be subcategorized by recognizing the differences in the characteristics 

of the Gulf Coast lignite and the North Dakota lignite. These coals have 

significantly different composition that will make it very difficult for them to 

comply with a single standard. Similarly, in the Illinois basin, the quality of the 

coal varies considerably even within the basin. 

 MACT determinations must be based on the top 12 percent of all units in the 

category or subcategory and not 12 percent of those units that were tested in that 

category or subcategory. The CAA requires EPA to set MACT limits for existing 

sources based on “the average emissions limitation achieved by the best 

performing 12 percent of the existing sources (for which the Administrator has 

emission information).” For source categories with less than 30 sources, existing 

source MACT floors are to be set based on “the average emission limitation 

achieved by the best performing five sources (for which the Administrator has or 
6 

could reasonably obtain emissions information).” Cooperatives believe these two 

provisions indicate that Congress intended MACT standards to be set on a no less 

than five “best performing” units. It is fair to assume that Congress never 

contemplated the situation were the amount of available data from a large source 

category or subcategory would require EPA to set MACT limits based on the 

performance of only one or two sources as the agency did in the Ind. Boiler rule. 

 HAP emissions during startup/shutdown events (which could produce emissions 

different from emissions during normal operation) should be addressed through 

long-term rolling averages. The EGU ICR did not require any testing during 

start-up, shutdown and malfunction events. Without emissions data during these 

periods, EPA has absolutely no factual basis for concluding that the best 

performing units can achieve the proposed MACT limits during these events. For 

example, operations during boiler start-ups are different than normal plant 

operations. Certain plant components must be started in a specific sequence in 

order to ensure that steady state operations can be achieved. During start-up, not 

all pieces of control equipment will be operating at peak efficiency. Cooperatives 

believe work practice standards are far more appropriate during these periods. 

Similarly, for the same reasons, work practice standards are also more appropriate 

for shutdown and malfunction events. 

 Monitoring, reporting and record keeping requirements should be minimized and 

simplified to the maximum extent possible. At this preliminary stage in the 

rulemaking process, however, and having essentially no detailed information 

regarding specific emission standards or knowing what the agency is considering 

for monitoring and recording methodologies and criteria, it is not possible for 

cooperatives to provide specific recommendations or suggestions as to how to 

minimize the impact on small entities. 

 The final rule should include an either/or standard of percent reduction or 

emission limits to allow the source to comply with the least expensive or 

burdensome option. This clearly would be helpful to small entities and would not 
7 

detract from reducing emissions. The composition of the coal used at many 

facilities varies considerably over time due to several reasons. Coal produced 

from a single mine is diverse as a result of the dissimilarity in coal composition 

from different locations or layers in the mine. Also, many power plants purchase 

coal from more than one mine because of market-based cost and other 

considerations. In addition, many times coal from various sources is blended, and 

in some cases, even different coal types are combined in varying amounts for use 

in a single generating unit. For all these reasons, the option of a percent reduction 

compliance method may be the most reasonable alternative to achieving the 

desired emission reductions while helping to minimize any unnecessary costs of 

compliance. In other instances, emission limits may be less burdensome. 

Cooperatives believe that the source should be allowed to make the decision 

regarding which option to use. 

 Health-based emission limits under Section 112(d)(4) should be used to the 

maximum extent possible. Section 112(d)(4) is designed to prevent the 

promulgation of unduly stringent emission limits simply for the sake of 

regulation. Section 112(d)(4) allows EPA to set health-based limits for certain 

HAPs based on established health thresholds, rather than having to follow the 

technology forcing provisions of Section 112(d)(3). As a practical matter, 

Section 112(d)(4) applies to non-carcinogenic HAPs for which EPA has 

established a health threshold such as a reference concentration (“RfC”) or a 

reference dose (“RfD”). EPA defines a reference concentration in its IRIS 

database as “[a]n estimate (with uncertainty spanning perhaps an order of 

magnitude) of a continuous inhalation exposure to the human population 

(including sensitive subgroups) that is likely to be without an appreciable risk of 

deleterious effects during a lifetime.”4

 Thus, human exposures to a HAP at levels 

below its RfC are considered “safe,” particularly given the uncertainty factors that 

EPA includes as part of its derivation of an RfC. 

 

4

 The definition for a reference dose is essentially the same except it focuses exposure by pathways other 

than inhalation. 
8 

Section 112(d)(4)’s inclusion in the 1990 CAA Amendments indicates a 

Congressional intent to retain the health endpoint of the original Section 112 -- 

protection of public health with an ample margin of safety. If the emissions of a 

given HAP from all sources in a source category are at a level where public health 

is protected with an ample margin of safety, then there is no practical need for or 

benefit from further regulation. Cooperatives encourage EPA to set health-based 

standards under Section 112(d)(4) when facts support its use. 

 Section 112 of the CAA defines a “major source” as a stationary source that emits 

HAPs in amounts greater than 10 tons/yr of any individual HAP or 25 tons/yr of 

all HAPs. Section 112 also allows EPA to set less onerous area source standards 

for any stationary source that is not a major source. Area source standards are 

based on “generally available control technologies or management practices by 

such sources to reduce emissions of hazardous air pollutants.”5 Congress 

recognized that the risks posed by HAP emissions from area sources are far 

smaller than the ones posed by major sources and that less stringent emission 

standards were, therefore, appropriate. Many EGUs owned by cooperatives 

qualify as area sources because they have control equipment installed or for other 

reasons. 

EPA should exercise its discretion, as it has done in the in the Ind. Boiler 

rulemaking, for example, and set separate source standards for those EGUs that 

qualify as area sources, This would have the effect of lessening the regulatory 

burdens on small entities. 

Cooperatives are also concerned that specific units subject to the new EGU MACT 

emission limitation requirements may have site unit-specific special considerations that 

must be addressed in a final rule. For example: 

 Specific units may not have the physical space to add the required control 

equipment. Consideration must be given to alternative compliance for these units 

 

5

 CAA Section 112(d)(5). 
9 

that will avert the otherwise necessity to be shutdown and taken offline 

prematurely. 

 The final rule must include consideration of the fact that for some small entity sources, 

fuel switching is not a reasonable or practical alternative to meeting new emission 

limits. For example, units with mine-mouth operation and having a lack of 

transportation infrastructure may have no option but to shut down if faced with overly 

stringent standards for the coal being used. We believe the CAA was designed to 

require sources to reduce emissions not to force groups of plants to cease operation. 

Furthermore, fuel switching implicitly favors certain fuel types and sources over others. 

A regulatory policy that favors one fuel type over another can have severe impacts on 

electricity reliability and energy security. Cooperatives believe that the potential 

negative impacts on small entities must be considered if the agency sets EGU MACT 

limits at levels that may require fuel switching. Furthermore, cooperatives believe that 

it is absolutely imperative that the EGU MACT rule not adversely impact the reliability 

of the nation’s electric power system. 

 Small entities with few units should be given additional time to comply with an 

EGU MACT rule’s new requirements in order to account for their disadvantage in 

competing for equipment and skilled labor resources in a severely tight 

compliance timeframe. The electric utility industry, in general, will face great 

challenges in complying with an EGU MACT rule within the three year statutory 

deadline. Small cooperatives will find it even more difficult, if not impossible. 

Cooperatives, as a general rule, own few units and if stringent emission limits are 

imposed by an EGU MACT rule, utilities across the country will scramble to 

secure the equipment, contractors and skilled craftsmen needed to install the 

needed new control equipment. Large utilities have leverage to get their plans 

retrofitted first. Small cooperatives will find themselves at the end of a long line, 

making it highly unlikely that the new control equipment can be installed within 

three years. We strongly believe that the compliance deadline for small entities 
10 

must be extended. Without specific compliance requirements to review, however, 

we cannot determine with specificity how much of an extension will be required. 

Similarly, specific units may not have the physical space to add the required 

controls equipment. Consideration must be given to alternative compliance 

methods for these units so that they will not be forced to shut down and be taken 

offline prematurely. 

Conclusion

In conclusion, electric cooperatives remain concerned that EPA has not provided 

adequate time or provided rule alternatives or sufficient data to provide meaningful input 

on a rule of this magnitude and importance. The greatly foreshortened period for small 

business input on the EGU MACT rule is inconsistent with the stated goals of SBREFA 

to encourage the “effective participation” of small business in the federal regulatory 

process6

 and to create a more accommodating regulatory environment among agencies 

and small businesses that is less punitive and more solution oriented.7

 Section 609 of 

SBREFA envisions that the small business panel will review “any material the agency 

has prepared in connection with this chapter” including information required to be part of 

the initial regulatory flexibility analysis.8 The regulatory flexibility analysis typically 

includes descriptions of significant alternatives to the proposed rule, differing compliance 

or reporting requirements or timetables that take into account the resources available to 

small entities, and the clarification, consolidation, or simplification of compliance and 

reporting requirements for small entities.9

The material presented by EPA at the one small business panel meeting does not 

address these issues of greatest importance to small entities. Hence, the ability of 

cooperatives to participate meaningfully in the small business review process has been 

seriously limited. We ask that EPA schedule additional panel meetings, once the agency 

has progressed further in its rulemaking preparation. 

 

6

 5 U.S.C. Section 203(3). 

7

 5 U.S.C. Section 203(6). 

8

 5 U.S.C. Section 609(b)(4); see also 5 U.S.C. Section 603(b)(3), (4) and (5) and 603(c). 9 See 5 U.S.C. Section 603(c). 
11 

If you have questions regarding any of the above, or need additional information, 

please do not hesitate to contact any one of the undersigned cooperative representatives. 

In the meantime, we urge the agency to seriously consider the cooperative concerns 

expressed above as it proceeds forward with this very important rulemaking. 

_______\ S \_________ ______\ S \__________ 

Rex Butler Leonard Hopkins 

Mngr., Environ. & Safety Fuel Procurement & Compliance Mngr. 

Central Iowa Power Co-op So. Illinois Power Cooperative 

(319)366-4512 x 348 (618)964-1448 x 268 

Rex.butler@cipco.net lhopkins@sipower.org 

 

 

_______\ S \_________ ________\ S \_________

Joe Eutizi Mike Thatcher 

Engineering Mngr. Vice Pres. of Generation 

San Miguel Electric Co-op Corn Belt Power Cooperative 

(830)784-3411 x 226 (515)332-2571 x 7775 

jeutizi@smeci.net mike.thatcher@cbpower.coop 

_______\ S \__________

Bill Wemhoff 

Sr. Principal, Environ. Policy 

NRECA 

(703) 907-5824 

Bill.wemhoff@nreca.coop 
IOU

47%

Co-op

5% Muni

9%

Federal

7%

Nonutility

32%

Total U.S. Electric Utility Comparisons, by Sector

Customers

Investor-Owned (IOU)

Municipals (Muni)

Electric Co-ops (Co-op)

Federal

3%

IOU

48%

Muni

7%

Co-op

42%

Generation

Distribution Miles of Line

35% 36%

57%

Co-ops Serve Primarily Farms & Families

(kWh Sales)

Co-op IOU Muni

43%

65% 64%

Other Utilities Serve Primarily Businesses

(kWh Sales)

Co-op IOU Muni

7

47

35

Co-ops Serve the Most Rural Areas & Have

Fewest Consumers Per Mile

Co-op IOU Muni

$62,665

$86,302

$10,565

Co-ops Have Least Revenue Per Mile

Co-op IOU Muni

IOU

73%

Muni

15%

Co-op

12%

Co-op

6%

Muni

6%

Federal

11%

IOU

77%

Transmission Miles of Line

NRECA Feb 2008 Source: 2006 RUS/EIA data
© NRECA, all rights reserved. May not be copied, reprinted, published, translated, hosted or otherwise distributed by any means without explicit permission

America’s Electric Cooperative Ne

America Samoa
A-1 

Small Business Review Panel for the EGU MACT Rulemaking

Comments: Rural Electric Cooperatives, December 15, 2010

APPENDIX “A” 

EPA HAS UNDERESTIMATED THE NUMBER OF SMALL COOPERATIVES 

THAT WILL BE AFFECTED BY THIS RULE 

In evaluating the small business impact of the EGU MACT Rulemaking, EPA 

must account for all potentially affected small cooperatives that qualify as “small 

entities.”1

 In the material distributed by the agency prior to the December 2 meeting, 

EPA did not properly identify all generation and transmission (G&T) cooperatives that 

meet the Small Business Administration (“SBA”) standards and did not recognize the 

relationship between G&Ts and distribution cooperatives. 

Eighty percent of the electric power generated by cooperatives comes from coalfired units. NRECA’s 66 rural electric G&T cooperatives generate and transmit power to 

668 of the 846 distribution cooperatives; 14 of these G&T cooperatives own coal-fired 

generation and qualify as “small entities” under the SBA size standards. 559 distribution 

cooperatives receive their electricity from G&T’s that burn coal and also qualify as 

“small entities.” The G&T cooperatives are owned by the very distribution companies 

they serve (virtually all of which qualify as “small entities”); the distribution cooperatives 

are owned by the consumers to whom they provide electricity. In fact, the Board of 

Directors for any given G&T cooperative is made up of either a member of the board or 

chief executive officer from each distribution cooperative that has an ownership stake in 

the G&T. 

 

1

 The vast majority of NRECA’s members meet the definition of “small” under the Small 

Business Regulatory Enforcement Fairness Act (SBREFA). Regulatory Flexibility Act 

(RFA), 5 U.S.C. §§ 601-612 (as amended Mar. 29, 1996). The RFA incorporates by 

reference the definition of “small entity” adopted by the Small Business Administration 

(SBA). The SBA’s small business size regulations state that entities which provide 

electric services are “small entities” if they dispose of 4 million MWh or less per year. 

13 C.F.R. §121.201, n.1. 
A-2 

In considering the economic impacts that the EGU MACT rulemaking would 

have on small electric utilities, EPA has identified 14 electric cooperatives nationwide 

that will be affected and that meet the SBA’s small business standards. Of those 

identified, however, NRECA suggests that EPA’s list includes some cooperatives that are 

larger than the SBA size standards and omits others that do meet the standards. Listed 

below are 14 coal burning G&Ts that NRECA believes should be included in any 

analysis of the impacts of the EGU MACT rulemaking on small entity cooperative 

G&Ts. 

However, given the closely interwoven nature of the G&T cooperatives and the 

distribution cooperatives, it is clear that the EGU MACT rulemaking will have a direct 

impact on all electric cooperatives generating and/or distributing coal-based power. Any 

expenditure made by the G&T cooperatives in order to comply with the new regulatory 

requirements for the EGU MACT will be borne in tandem by the distribution 

cooperatives; to the extent that the G&T cooperatives can “pass through” their regulatory 

compliance costs, those costs are being passed directly to their consumer/owners – that is, 

to the distribution cooperatives. Because the G&Ts are owned by the distribution co-ops 

they serve, there are no third party shareholders who could help share these costs. And 

because the relationship between the distribution cooperative and their G&T is governed 

by an “All Requirements” contract, the distribution cooperative must receive its 

electricity from the G&T and there can be no market forces to moderate the price 

increases to consumers. 

Also, EPA appears to believe that the “residential, commercial, industrial, and 

transportation sector economic demand for (i.e., consumption of) electricity is relatively 

price inelastic, which suggests that electric utility plants may succeed in passing through 

most or all regulatory costs to their electricity customers.” The reality is that these 

mechanisms do not operate for not-for-profit cooperatives. As explained above, there is 

no “market” for the electricity that distribution cooperatives receive from the G&Ts. 

Neither does the concept of “rate hike petitions to public utility commissions” readily 

transfer to the cooperative business model. G&T cooperatives deliver power to their 

members at cost-based rates determined by the Boards of the G&T, and the Boards are 

made up by representatives of the distribution cooperatives that own the G&T. All 
A-3 

additional costs borne by the cooperative (and paid for by the distribution cooperative 

member-owners) affect the financial well-being of the G&T cooperative, rendering the 

discussion of a cost pass-through a moot issue for our members. The notion that “passing 

through” regulatory compliance costs to customers will somehow avoid or mitigate their 

impact does not apply to consumer-owned cooperatives. The business is the consumer 

and the consumer is the business. 

The information presented in appendix “B” shows that distribution cooperatives 

have a higher percentage of residential consumers and those consumers use a higher 

percentage of electricity but have lower household income than the U.S. average. As 

cooperatives are forced to pass on the higher costs of power, these consumers will find it 

ever more difficult to pay for that power and may have to sacrifice other necessities. 

Furthermore, increasing cost of power has significant negative impacts on economic 

development and jobs in depressed rural areas. 

G&T Cooperatives that Qualify as Small Entities

Sunflower Electric Power Cooperative 

Square Butte Electric Cooperative 

Northeast Texas Electric Cooperative 

San Miguel Electric Cooperative, Inc. 

Arizona Electric Power Cooperative, Inc. 

Central Iowa Power Cooperative 

Southern Illinois Power Cooperative 

Kansas Electric Power Cooperative 

Corn Belt Power Cooperative 

Sam Rayburn G&T, Inc. 

Prairie Power, Inc. 

East Texas Electric Corporation 

Northwest Power Cooperative 

Power Resources Cooperative 
NRECA B-1 May 2010 

America’s Cooperative Electric Utilities 

The Nation’s Consumer Owned Electric Utility Network

Electric cooperatives are an integral part of the $364 billion U.S. electric utility industry. They play a 

critical role in our nation's economy and in local communities. 

Electric cooperatives are:

 private independent electric utility businesses 

 owned by the consumers they serve 

 incorporated under the laws of the states in which they operate 

 established to provide at-cost electric service 

 governed by a board of directors elected from the membership, which sets policies and 

procedures that are implemented by the cooperatives’ professional staff 

Distribution cooperatives deliver electricity to the consumer. Generation and transmission 

cooperatives (G&Ts) generate and transmit electricity to distribution co-ops. 

In addition to electric service, electric co-ops are involved in community development and 

revitalization projects, e.g., small business development, jobs creation, improvement of water and 

sewer systems and assistance in delivery of health care and educational services. 

Facts at a Glance

 864 distribution and 66 G&T cooperatives 

 serve 42 million people in 47 states 

 18 million businesses, homes, schools, churches, farms, irrigation systems, and other 

establishments in 2,500 of 3,141 counties in the U.S. 

 12 percent of the nation's population are customers of rural electric co-ops 

To perform their mission, electric cooperatives:

 own assets worth $112 billion (distribution and G&T co-ops combined) 

 own and maintain 2.5 million miles, or 42%, of the nation’s electric distribution lines, covering 

three quarters of the nation's landmass 

 deliver 10 percent of the total kilowatt-hours sold in the U.S. each year 

 generate nearly 5 percent of the total electricity produced in the U.S. each year 

 employ 70,000 people in the U.S. 

 retire $545 million in capital credits annually 

 pay $1.4 billion in state and local taxes 

 

Compared with other electric utilities: 

 Co-ops serve an average of 7 consumers per mile of line and collect annual revenue of 

approximately $10,565 per mile of line 

 Investor-owned utilities average 35 customers per mile of line and collect $62,665 per mile of line 

 Publicly owned utilities, or municipals, average 46.6 consumers and collect $86,302 per mile of line 
NRECA B-2 May 2010 

Cooperative Electric Utilities ‐ Additional Facts

 G&T co‐ops are owned and integrated with their member distribution co‐ops.

 G&T co‐ops generate approximately 50 percent of the electric energy they provide to

their distribution co‐op owners and purchase the remaining 50 percent in the

wholesale market.  

 Approximately 80% of co‐op’s self‐generation is from coal‐fired plants as compared to

45% for the electric utility industry.

  

 Nearly 60% of co‐ops’ kWh sales are to residential consumers.  Other utilities (IOUs

and Munis) serve primarily businesses.  In comparison:

o Only about 35% of IOU’s (and 36% of Muni’s) end‐use sales are to residential

consumers.

o About 40% of co‐op kWh sales are to commercial and industrial customers.

o Commercial and industrial customers account for 65% and 64% percent of IOU

and Muni kWh sales.

 The median co‐op serves 12, 500 consumers compared to 400,000 consumers for IOUs.

 Co‐op residential consumers also use more electricity – 35% and 20% more than

residential consumers served by IOUs and municipals, respectively.

 Despite these barriers, the (median) co‐op residential rate is only about 7.5% higher

than their neighboring IOU.   

 This challenge of higher residential rates, though, is amplified by relatively low

household income in the rural communities served by co‐ops – which is about 14%

less than the U.S. average.

 Cooperatives are non‐profit and operate “at cost” with no stockholders, all costs,

therefore, that are borne by G&Ts must be passed on to distribution co‐ops, and

ultimately, end‐use consumers.

 Because cooperatives have a disproportionate amount of coal‐fired generation when

compared to the electric utility industry as a whole, increases in costs of coal‐fired

generation could be disproportionately higher for cooperatives and their consumer‐

owners.  
Appendix “C” [Small Business Review Panel for EGU MACT Rulemaking] 

The National Rural Electric 

Cooperative Association 

Comments 

On 

National Emission Standards for Major Sources: 

Industrial, Commercial, and Institutional Boilers 

 and Process Heaters; Proposed Rule 

75 Fed. Reg. 32006 (June 4, 2010) 

 

Submitted Electronically to: 

The Environmental Protection Agency Air Docket 

Attention: Docket ID No. EPA-HQ-OAR-2002-0058 

August 23, 2010 

Bill Wemhoff – Sr. Principal, Environmental Policy 

(703) 907-5824 / bill.wemhoff@nreca.coop 

4301 Wilson Boulevard, EU 11-249 

 Arlington, VA, 22203-1860 
- 2 - 

Introduction 

The National Rural Electric Cooperative Association (“NRECA”) offers the following 

comments on the U.S. Environmental Protection Agency’s (“EPA” or “Agency”) Proposed Rule: 

National Emission Standards for Major Sources; Industrial, Commercial, and Institutional Boilers 

and Process Heaters (“Ind. Boiler”) or (“IB”).1

 

NRECA has an interest in the outcome of this rulemaking. NRECA is the national 

service organization for more than 900 not-for-profit rural electric utilities that provide electric 

energy to approximately 42 million consumers in 47 states or 12 percent of the nation’s 

population. Kilowatt-hour sales by rural electric cooperatives account for approximately 11 

percent of all electric energy sold in the United States. NRECA members generate 

approximately 50 percent of the electric energy they sell and purchase the remaining 50 percent 

from non-NRECA members. The vast majority of NRECA members are not-for profit, 

consumer-owned cooperatives. NRECA’s members also include approximately 66 generation 

and transmission (“G&T”) cooperatives, which generate and transmit power to 668 of the 846 

distribution cooperatives. The G&Ts are owned by the distribution cooperatives they serve. 

Remaining distribution cooperatives receive power directly from other generation sources within 

the electric utility sector. Both distribution and G&T cooperatives were formed to provide 

reliable electric service to their owner-members at the lowest reasonable cost. 

NRECA’s members and their consumer-owners operate and own industrial boilers and 

process heaters. Also importantly, EPA is developing maximum achievable control technology 

(“MACT”) standards for electric utility steam generating units (“EGU”) under the Clean Air Act 

(“CAA”) Section 112(d) and has indicated in the information collection request (“ICR”) for 

EGUs that it intends to follow a similar approach in setting MACT limits in that rulemaking as it 

has followed in the IB MACT rulemaking. 

NRECA believes that finalization of rules to control emissions from these sources using the 

approach as proposed will result in increased costs that cooperatives, being not-for-profit, will be 

forced to pass along to their consumer-owners. Increased costs of electric power, particularly in 

rural areas served by cooperatives, have negative impacts on economic development and jobs. 

 1 75 Fed. Reg. 32006 (June 4, 2010) 
- 3 - 

NRECA urges the agency to include in its consideration the negative impacts of increased electric 

power costs as it finalizes its proposed rule. 

NRECA is an active member of the Utility Air Regulatory Group ("UARG")2

 and fully 

supports the comments submitted by UARG in this rulemaking. UARG’s comments include a 

more expansive discussion of many of the issues described below. 

Summary 

NRECA believes that the proposed standards are far more stringent than needed to assure 

protection of public health and the environment from industrial boiler hazardous air pollutant 

(“HAP”) emissions. As explained below, EPA’s approach to setting the standards is flawed and 

fundamental data issues exist that compromise the validity of the proposed standards. 

NRECA also believes that EPA has both the need and the opportunity to make significant 

changes to the proposed standards. The agency has the legal discretion and the technical 

justification to substantially reduce the burden of the standards while still providing ample 

protection. NRECA provides recommendations in that regard in several key areas below. 

Section 112 Standards Must Reflect the Emissions Control Achieved by Actual Units, Not 

Hypothetical Composite Ones

 The proposed Ind. Boiler MACT limits were derived by determining independently a MACT 

floor for each HAP or HAP surrogate for each subcategory of sources. Under this approach, EPA 

identified the lowest emitting units3 to determine the MACT floor for a given HAP. EPA then 

directs its attention to the next HAP, ignoring those units it just determined were the “best 

performing” in setting the MACT floor for the first HAP, and establishes the next MACT floor 

based on a different set of units. EPA repeats this process until MACT floors have been set for all 

HAPs emitted by each subcategory of industrial boilers. The end result is a set of MACT floors that 

 2

 UARG is a voluntary, nonprofit group of electric generating companies and organizations and 

four national trade associations (NRECA, the Edison Electric Institute, the American Public Power 

Association, and the National Mining Association). UARG’s purpose is to participate collectively on 

behalf of its members in EPA rulemakings, related litigation, and other Clean Air Act proceedings that 

affect the interests of electric generators.

3 In the case of new units, EPA bases the MACT floor on the best performing source.
- 4 - 

do not represent the emission levels achieved by an actual, best-performing unit. Instead, they 

reflect the performance of a hypothetical, ideal unit that does not exist in the real world. 

 As UARG explains in more detail in its comments, Section 112(d)(3) of the CAA 

expressly requires that emissions limitation(s) for new units should not be less stringent “than the 

emissions control that is achieved in practice by the best controlled similar source.” For existing 

units, the emission standards shall not be less stringent than the average emissions limitation 

achieved by the best performing 12 percent of sources. 

 NRECA believes that Congressional intent is clear that MACT standards promulgated 

under § 112(d) must be based on the actual performance of an actual source or sources. MACT 

standards are not to be based on hypothetical, ideal units nor do they allow the “emissions 

control” achieved by the best sources to be determined using a pollutant-by-pollutant approach 

on a shifting group of best performing units. 

 NRECA believes EPA’s standard-setting approach violates the express language of 

§ 112(d)(3) for setting new source MACT limits. New MACT source limits look to the level of 

performance “achieved in practice by the best controlled similar source.” This language directs 

EPA to use a single “source” to set new source MACT limits. It does not direct EPA to use a 

collection of “sources” to set the lowest possible emission limit for each HAP for new sources. 

Similar logic applies for existing units because MACT standard setting is again premised on the 

performance of “sources.” 

 As UARG describes in more detail in its comments, EPA’s MACT standard-setting 

approach in the IB MACT rulemaking produces emission limits that fail to reflect the 

performance of actual sources. For example, in the biomass subcategory, the source with the 

lowest particulate matter (“PM”) emissions had hydrogen chloride (“HCl”) emissions that were 

over two orders of magnitude higher than the source with the lowest HCl emissions. Likewise, 

the source with the lowest mercury (“Hg”) emissions had PM emissions 10 times greater than the 

best performing PM unit and 146 times higher than the best performing HCl unit. 

 EPA’s approach for setting MACT floors in the proposed rule should not be used in the 

IB rulemaking and should not be used in subsequent § 112(d) rulemakings. MACT standards 

must be set based on the level of performance achieved by actual sources. EPA needs to 

develop a weighting approach for identifying the best performing units in MACT rulemakings 
- 5 - 

where the sources in the category emit multiple HAPs and set the MACT standards based on the 

best performance by a single set of sources. 

The Proposed Rule Fails to Address in a Reasoned Manner HAP Emissions That Are At or 

Below the Method Detection Limit 

 EPA‘s effort to set emission limits for all HAPs emitted by industrial boilers is greatly 

complicated by the fact than a number of HAPs are emitted at levels at or below the detection 

limit of the method that was used to collect and analyze HAP emissions during the IB MACT 

ICR. Detection limit issues have significant impacts on MACT standard setting as well as later 

during compliance demonstrations. 

 A discussion of detection limit issues must begin with a clear definitional framework for 

two important terms -- “detection limit” and “quantitation limit.” The detection limit defines the 

threshold below which a test method cannot distinguish whether a substance is present or not. In 

EPA’s prior efforts to implement the Clean Water Act, the agency defined the term “detection 

limit” to mean “the minimum concentration of an analyte (substance) that can be measured and 

reported with a 99 percent confidence that the analyte concentration is greater than zero.” 40 

CFR § 136.2(f). Stated differently, a measured value at the detection limit has an error band as 

large as the value being reported. One does not have great confidence in the quantity of material 

measured because the error band is so large; one simply knows it is more likely than not that the 

substance is actually present. 

 By contrast, the “quantitation limit” is the smallest detectable concentration of analyte 

greater than the detection limit where the accuracy, including both precision and bias, achieves 

the objectives of the intended purpose of the measurement. Target objectives are generally 

stated in terms of the precision of the measurement expressed as a relative standard deviation 

(“RSD”). There is no single agreed approach for determining the quantitation limit of a method. 

The quantitation limit for a given method can be three to 10 times higher than that method’s 

detection limit depending on method-specific factors such as matrix effects and purity of 

reagents. One does not have confidence in the accuracy of a measured value unless that value is 

at or above the quantitation limit for the method. 

 Testing accuracy, reliability, and representativeness are vital in setting MACT standards 

because those limits must reflect the level of performance “achieved in practice” by the best 
- 6 - 

performing units. They are also vital to permittees because test results, once they are sworn to be 

“accurate” on a monitoring report, are virtually unassailable in an enforcement action. Emission 

limits must not be set below the quantitation level of the method chosen for demonstrating 

compliance. 

 In the proposed IB MACT rule, EPA has established MACT emission limits based on 

reported detection limits. EPA’s approach is flawed for several reasons. First, the agency failed to 

provide a clear and proper definition of detection limit in the IB ICR. As a result, the detection 

limits reported in the ICR responses are inconsistent and are not even based on a common 

understanding of the term “detection limit.” It is likely that most IB owners seem to have reported 

the “detection limit” value they were provided by the laboratory analyzing the ICR samples. A 

cursory review of the ICR data shows that some “reported” values are actually below the detection 

limit values reported in other ICR tests. NRECA believes this could have been prevented if EPA 

had properly determined the detection limit for each method before issuing the IB ICR. 

 Second, EPA’s focus on the method detection limit reported by a given laboratory 

ignores many sources of measurement error that can affect a reported result. Accuracy 

considerations are not limited to the ability of a single laboratory to precisely measure the 

amount of a substance in a given sample it receives. Measurement errors also occur during the 

collection of a sample at the stack, the transfer of that collected sample to whatever means are 

used to transport the sample to an analytical laboratory, and the interlaboratory inaccuracies of 

different laboratories testing the same sample. EPA’s proposed rule does not address these areas 

of collection and analytical error. As a result, EPA’s detection limit analysis is fatally flawed. 

 In its proposed rule, EPA has recognized some of the issues related to its use of detection 

limits (See 75 Fed. Reg. 32,020-21), and has requested comments on whether it should adjust the 

representative detection limit by applying a multiplier of three to account for measurement 

variability. While EPA’s suggested adjustment is a step in the right direction, the remaining 

uncertainty is too large and therefore a larger multiplier is needed. More importantly, a method 

detection limit supplied by a given laboratory does not account for all sources of variability in 

sample collection nor interlaboratory variability in analyzing a given sample. EPA needs to 

address these issues in a comprehensive fashion prior to setting MACT standards in its final rule. 
- 7 - 

The Short Time EPA Took to Review the IB MACT ICR Data Has Resulted in Flawed 

MACT Standards 

 EPA’s rush to comply with the unrealistic rulemaking schedule it agreed to in the IB 

MACT rulemaking has resulted in obvious and multiple flaws in the proposed MACT standards. 

EPA does not appear to have conducted its own quality assurance analysis of the ICR stack 

testing data. As UARG describes in its comments, even a cursory review of the IB MACT data 

by its consultant has revealed several important problems with EPA’s analysis of the ICR data. 

 The fact that UARG was able to identify such obvious errors in a very limited review of 

the IB MACT database raises troubling questions about EPA’s apparent blind acceptance of the 

IB ICR data given time limitations. EPA needs to conduct a thorough quality assurance review 

of the IB ICR data and only after that review repropose IB MACT limits. 

 The lesson for the upcoming EGU MACT rulemaking is that EPA must conduct a thorough 

analysis of the information it receives from its EGU ICR request. If more time is needed for EPA 

to perform a proper review, it must ask the court to revise the rulemaking schedule. 

The Proposed Rule Fails to Account for All Variability in HAP Emissions 

 In order for a standard to be achievable, it must be achievable under most adverse 

circumstances which can reasonably be expected to recur. In order to assure that an emission 

limit is set at a level that the best performing source(s) will not violate, EPA must assess the 

variability in emissions of that unit. 

In the proposed IB MACT rule, EPA has determined MACT floors based on a variability 

adjustment using an upper prediction limit (“UPL”). EPA’s UPL equation attempts to identify 

an interval that will, with a specified degree of confidence, contain the next randomly selected 

observation from the population distribution. In theory, EPA’s statistical analysis is reasonable 

provided the mean and standard deviations are computed from a distribution of values that reflect 

all operating conditions. Unfortunately for IBs, EPA lacks sufficient data to perform a 

meaningful UPL calculation. 

As UARG explains more fully in its comments, EPA computes the within-source 

variance on the basis of three short-term (snapshot) tests. Three snapshot tests cannot possibly 

capture the level of performance that a unit will achieve “under the most adverse circumstances 
- 8 - 

which can reasonably be expected to recur” -- the condition the D.C. Circuit has repeatedly said 

must be considered in setting MACT floors. Actual emissions variability for the best performing 

unit(s) results from a variety of factors, including different plant operating conditions, different 

control equipment settings, and different trace element constituents in the process raw materials. 

The fortuitous chance that each and every one of these variables would be present in the worst 

possible way for a short-term emissions test is miniscule, at best. The problem with EPA’s 

variability adjustment is that it does not guarantee a proper assessment of the 99th percentile 

performance of a given unit if the emissions data from three days of testing of that unit are not 

representative of all the unit’s operating conditions over an extended period of operation. The 

three ICR test runs for each boiler were performed hours apart and most likely under identical 

operating conditions. As a result, EPA lacks the data needed to determine whether the best 

performing units could ever perform as well as they did during the ICR testing. 

 The lesson for future MACT rulemakings is that if EPA fails to obtain a complete picture 

of operating conditions of the best performing units over a sufficiently extended period of time, it 

cannot hope to develop an accurate assessment of the level of performance those plants will 

achieve under the worst reasonably foreseeable circumstances. No amount of statistical handwaving can solve a lack of appropriate data. 

EPA Needs to Consider Additional Subcategories for Industrial Boilers 

 Section 112(d)(1) of the CAA allows the Administrator to distinguish among “classes, 

types, and sizes of sources” in establishing MACT standards. This subcategorization language 

mirrors earlier language found in CAA § 111. In providing EPA discretion to create 

subcategories, § 112(d)(1) does not restrict subcategorization to cases where the “class,” “type” 

or “size” factors affect HAP emissions. The provision merely requires EPA to establish 

regulations for each category or subcategory on the schedules set out in § 112. Indeed, EPA has 

not previously subcategorized under § 111 based solely on emission effects. For example, under 

§ 111 EPA has subcategorized boilers on the basis of size (heat input) or the type of fuel burned 

(coal, oil or gas). These subcategorization decisions were based on feasibility and/or cost 

considerations, not on the level of emissions. 

 NRECA commends EPA for creating a large number of subcategories in the proposed IB 

MACT rule. However, NRECA believes EPA should have created even more subcategories. 
- 9 - 

Historical testing has shown that coal rank has a significant effect on Hg and HCl emissions. 

Also, as discussed below, a limited use subcategory should be created for IBs that are operated 

infrequently because of their specialized nature and use. 

EPA Should Use Section 112(d)(4) Whenever Appropriate in Setting Emission Limits 

 EPA has requested comments on whether it should impose a health-based standard under 

§ 112(d)(4) for HCl and other acid gas emissions from IBs. Section 112(d)(4) is designed to prevent 

the promulgation of unduly stringent emission limits simply for the sake of regulation. Section 

112(d)(4) allows EPA to set health-based limits for certain HAPs based on established health 

thresholds, rather than having to follow the technology forcing provisions of § 112(d)(3). As a 

practical matter, § 112(d)(4) applies to non-carcinogenic HAP for which EPA has established a 

health threshold such as a reference concentration (“RfC”) or a reference dose (“RfD”). EPA 

defines a reference concentration in its IRIS database as “[a]n estimate (with uncertainty spanning 

perhaps an order of magnitude) of a continuous inhalation exposure to the human population 

(including sensitive subgroups) that is likely to be without an appreciable risk of deleterious effects 

during a lifetime.”4 Thus, human exposures to a HAP at levels below its RfC are considered “safe,” 

particularly given the uncertainty factors that EPA includes as part of its derivation of a RfC. 

 Section § 112(d)(4)’s inclusion in the 1990 CAA Amendments indicates a Congressional 

intent to retain the health endpoint of the original § 112 -- protection of public health with an 

ample margin of safety. If the emissions of a given HAP from all sources in a source category 

are at a level where public health is protected with an ample margin of safety, then there is no 

practical need for or benefit from further regulation. NRECA encourages EPA to set health-base 

standards under § 112(d)(4) when facts support its use. 

MACT Limits Should Be Based on Emission Limitations Achieved by No Fewer Than Five 

Units 

 In the proposed IB MACT rule, EPA has based the MACT floor for certain subcategories 

on emissions data from less than five sources even though the subcategory contains more than 30 

 4

 The definition for a reference dose is essentially the same except it focuses exposure by 

pathways other than inhalation. 
- 10 - 

units. EPA has requested comments on whether it should set existing source MACT limits based 

on the emissions of at least five “best performing” units in larger subcategories (more than 30 

units) when only limited emissions data are available. NRECA believes it should. 

 The CAA requires EPA to set MACT limits for existing sources based on “the average 

emissions limitation achieved by the best performing 12 percent of the existing sources (for 

which the Administrator has emission information).” For source categories with less than 30 

sources, existing source MACT floors are to be set based on “the average emission limitation 

achieved by the best performing 5 sources (for which the Administrator has or could reasonably 

obtain emissions information).” NRECA believes these two provisions indicate that Congress 

intended MACT standards to be set on a no less than five “best performing” units. It is fair to 

assume that Congress never contemplated the situation were the amount of available data from a 

large source category or subcategory would require EPA to set MACT limits based on the 

performance of only one or two sources. 

HAP Emissions During Startup and Shutdown Should Not Be Treated the Same as HAP 

Emissions During Normal Operations 

The IB ICR did not require any testing during start-up, shutdown and malfunction events. 

Without emissions data during these periods, EPA has absolutely no factual basis for concluding 

that the best performing units can achieve the proposed MACT limits during these events. For 

example, operations during boiler start-ups are different than normal plant operations. Certain 

plant components must be started in a specific sequence in order to ensure that steady state 

operations can be achieved. During start-up not all pieces of control equipment will be operating 

at peak efficiency. NRECA believes work practices standards are far more appropriate during 

these periods. Similarly, for the same reasons, work practice standards are also more appropriate 

for shutdown and malfunction events. 

 If EPA insists, however, on setting emission limits for these periods of operation then the 

agency must obtain emission data during these periods of operation and properly analyze those 

data in order to set MACT emission limits. 

Also, NRECA is concerned about the potential for enforcement of operating parameter 

and opacity limits during periods of startup, shutdown, and in the event of equipment 

malfunction. When EPA finalized its rule in 2004 with enforceable operating parameters, it did 
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so with a rule that also made clear that those limits did not apply during periods of “startup, 

shutdown, and malfunction.” 40 C.F.R. § 63.7505(a), 69 Fed. Reg. at 55,254. EPA’s current 

proposal contains no such exception, but instead would allow enforcement of deviations from 

operating parameters during these periods, when controls would not be expected to be operating 

at the same levels as during performance tests, and due solely to equipment malfunctions. In its 

proposed rule, EPA asserts that it has taken startup and shutdown periods into account by using 

continuous emissions monitoring system (“CEMS”) data from best performing units that include 

periods of startup and shutdown, and by proposing use of “daily or monthly averages.” 

Regarding malfunctions, EPA asserts that it would use a variety of information to determine an 

appropriate response to exceedance caused by equipment malfunction. 

NRECA believes EPA’s assertions regarding startup and shutdown are inapplicable to 

control device operating parameter limits, which are based on 12-hour averages (not daily or 

monthly averages) established during performance test (not based on CEMS data that include 

startup and shutdown). Even a daily block average, as proposed for opacity, does not provide 

sufficient protection if the unit does not startup or shutdown at exactly midnight, since there might 

not be sufficient data under normal operating conditions to compensate for the startup or shutdown 

period. In short, NRECA believes EPA has not made sufficient allowance in its rules for periods 

of startup and shutdown. To the contrary, EPA has proposed to require sources to establish control 

device operating parameter levels that are dependent upon load during periods of “maximum 

normal operating load,” and then maintain those levels during periods other than maximum normal 

operating load, including startup and shutdown. NRECA thinks EPA’s proposal is unreasonable 

and the agency must address these periods by allowing sources to identify alternative parameters 

or by establishing simple work practice standards for these periods. 

EPA’s promise to address periods of equipment malfunction by considering other 

information before enforcing exceedance of operating limits also provides little comfort, 

especially given the risk of citizen suits. Although NRECA appreciates EPA’s proposal to make 

clear that “deviations” of operating limits are not necessarily violations, nothing in EPA’s 

proposal would prevent EPA, a state, or a plaintiff in a citizen suit from simply determining in 

their “discretion” that any particular exceedance constitutes a violation. MACT standards are 

technology-based standards, and NRECA believes the agency must recognize that even the best 

performing technology occasionally fails. 
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The Facility Averaging Provisions Should be Modified 

The proposed IB MACT rule allows emission averaging in certain circumstances. While 

emission averaging can, in theory, provide operational flexibility to sources, the emission 

averaging provisions of the proposed rule are so restrictive and highly conditioned that they are 

unlikely to be used. The proposed rule would apply a 10 percent “discount factor” on any source 

seeking to average emissions across units at a facility. This discount factor will deter averaging. 

As noted elsewhere in these comments, EPA’s proposed IB MACT standards are so low that 

there are real questions about whether sources can even comply with them using state-of-the-art 

control equipment. By effectively lowering those standards further by 10 percent for sources 

that average emissions, it makes an impossible situation even more impossible. Also, there is no 

legitimate reason for imposing a 10 percent penalty on sources that seek to average emissions. 

Total emissions from a single facility have the same health effects on public health regardless of 

whether each unit at the facility meets the MACT limits or all units meet the MACT limits in the 

aggregate -- the total emissions from the facility are the same. The 10 percent penalty on 

operational flexibility has no public heath benefit. 

 Other onerous provisions in EPA’s proposed averaging program include the detailed 

averaging plan a facility would need to prepare and the cap on unit emissions would not allow 

any unit participating in the averaging to have emission any higher then it had on the effective 

date of the proposed rule. If EPA is serious about providing operational flexibility to facilities, 

then it must make substantial revisions to its proposed averaging provisions. 

Biomass Limits Are Flawed and Will Impede the Construction of EGU Biomass Units 

As a matter of public policy, EPA should encourage the combustion of biomass as 

substitute fuel for coal or oil. The combustion of biomass will become increasingly important to 

utilities as renewable energy standards are adopted by more states and are possibly applied to all 

states as a result of federal mandates. The combustion of biomass has the beneficial effect of 

conserving natural resources. Unfortunately, the stringent MACT limits EPA has proposed for 

IBs burning biomass will greatly inhibit the combustion of biomass in the future. 
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 The proposed biomass emission limits are exceedingly low because of errors in standardsetting discussed above. The PM limit for biomass units does not account for fuel-related 

variability. PM emissions are directly related to the ash content of a fuel. The ash content of 

unadulterated wood is highly variable. Similarly, EPA does not appear to have made any fuelrelated adjustments for chlorides or Hg in biomass. 

EPA Should Promulgate Work Practice Standards for Utility Auxiliary Boilers and 

Expand the Practice to All Gas-Fired Units 

 Electric utilities that operate auxiliary boilers will be subject to the IB MACT rule 

because they are not steam generating units that produce electricity. Auxiliary boilers operate 

infrequently, normally during plant start-ups, and combust either natural gas or distillate fuel. As 

a result, the HAP emissions from the auxiliary boilers are exceedingly low and do not pose any 

risk to public health. 

 Under the proposed rule, gas-fired auxiliary boilers are subject to work practice standards 

requiring an annual tune up. NRECA supports EPA’s decision to set a work practice standard 

for this group of gas-fired IBs. The HAP emissions from these units are so low they are 

impossible to measure accurately. Furthermore, these vanishingly small emissions do not pose 

risks to public health and the cost of controlling emissions from these units dwarfs whatever 

minute benefits may result. 

 This work practice standard should be extended to IB units burning coal-derived gas. 

Utilities are increasingly being asked to consider constructing integrated gas combined cycle 

(“IGCC”) units. These units include a coal gasifier that produces gas for later combustion in a 

gas turbine. The gas from an IGCC unit is cleaned prior to combustion so in terms of trace 

HAPs it is little different than natural gas or refinery gas. NRECA believes EPA should add 

coal-derived gas to the fuels in the Gas 1 category. 

By contrast, the proposed IB MACT rule requires oil-fired auxiliary boilers to comply 

with stringent emission limits and demonstrate compliance with those limits by following 

expensive monitoring requirements. The distinction between these two different types of 

auxiliary boilers is unnecessary and does not produce environmental benefits. 

 NRECA also believes EPA should create a limited use subcategory for boilers 

combusting distillate fuel that would subject those units to the same work practice standards as 
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gas-fired units. The limited use subcategory should have a 10 percent capacity factor threshold. 

Eligibility for this subcategory would be determined based on 10 percent of the maximum hourly 

heat input of the boiler multiplied by 8,760 hours per year. Providing a limited use category with 

the limitations described above, would not pose any risk to human health but would provide 

substantial economic and administrative relief to owners of these sources. 

Proposed Compliance Demonstration Provisions 

EPA proposes several compliance demonstration methods depending upon the size of the 

unit and whether controls are required to meet the proposed limit. UARG includes in its 

comments extensive discussion regarding various issues and concerns regarding EPA’s proposed 

compliance provisions. NRECA supports UARG’s comments and also makes the following key 

points: 

 NRECA supports the use of stack testing and the fuel analysis option for Hg and 

HCl, but as described in detail in UARG’s comments, is concerned with EPA’s 

proposed implementing rules. NRECA has concerns regarding the use of carbon 

monoxide (“CO”) CEMS to make compliance determinations at some of the 

proposed emission limits, and has objections to EPA’s proposed use of PM 

CEMS. 

 NRECA does not object to EPA’s general approach of using operating parameters 

to assure compliance in between stack tests. EPA has previously used this 

approach in the Compliance Assurance Monitoring (CAM) rule to assure 

continuous compliance with standards that do not already specify continuous 

compliance methods. NRECA does object, however, to EPA’s proposed use of 

operating parameters as enforceable limits, and questions the achievability of the 

proposed 10 percent opacity standard, particularly in the absence of any exception 

for startup, shutdown, or malfunction. NRECA also objects to several provisions 

related to proposed bag leak detection systems and the lack of clarity in EPA’s 

proposed requirements for periodic fuel analysis. 

 NRECA generally supports EPA’s proposal to use periodic performance tests, 

rather than CEMS, as the primary method for determining compliance with 
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emission limits when limits cannot be met based on fuel analysis. NRECA 

believes that such periodic tests will ensure on an ongoing basis that the air 

pollution control device is operating properly and its performance has not 

deteriorated. NRECA also supports EPA’s proposal for reduced periodic testing, 

but objects to the restrictions EPA would impose. In addition, NRECA suggests 

that EPA provide options for use of several additional well established test 

methods not included in the proposed rule, and other options that would allow for 

reduced run length when appropriate. 

 NRECA supports the option to use fuel analysis to demonstrate compliance where 

possible, and does not object to a requirement to perform a new fuel analysis for 

Hg and chlorine when a new fuel is combusted. However, NRECA does not 

support EPA’s proposed requirement for monthly fuel analysis for sources that 

have not changed fuel type, or the agency’s proposal regarding how that analysis 

is used. 

Proposed Recordkeeping and Reporting Requirements 

The proposed rule includes a multitude of recordkeeping and reporting requirements. 

NRECA believes many of these requirements are not sufficiently justified and will impose 

unreasonable costs. Specifically, NRECA objects to EPA’s proposed requirement to report using 

the electronic reporting tool (“ERT”) and disagrees with EPA’s assertions regarding the impact 

of that requirement on reporting and on emission factor development. As UARG notes in its 

comments, while experience with the ERT has been limited, industry nonetheless has identified a 

number of shortcomings in the programs. Furthermore, use of ERT is burdensome (easily 

adding 10-20 percent to the cost of compliance testing), requiring manual inputting of significant 

amounts of information much of which is not relevant to performance test results. It also is 

subject to significant performance issues, including software crashes and shutdowns, inoperable 

features (like report generation), and inadequate identification of errors preventing data analysis. 

In short, even if EPA can justify a requirement to report performance test data electronically, 

EPA cannot justify requiring sources to use this program. 
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The Recordkeeping and Reporting Provisions Are Overly Burdensome 

EPA’s proposal includes requirements for the tracking of numerous data points, including 

fuel consumption; operating hours, startups, shutdowns including dates and times; equipment 

malfunctions including dates and times; numerous operating parameters including dates and 

times of deviations; CEMS, COMS, and CPMS calibration and quality assurance/quality control 

data; CEMS, COMS and CPMS maintenance information; CEMS, COMS, and CPMS out of 

control periods including reasons, dates and times; performance test reports; fuel sampling 

reports; vendor reports; and a number of other pieces of information. Records must be kept of 

virtually all information referenced in the proposal, including all CPMS data required to be 

collected, for five years. Unfortunately, much of these data gathering requirements cannot be 

automated, but instead will have to be collected manually. Once the data are gathered, decisions 

will have to be made regarding what has to be reported and a report will have to be generated 

and certified. This will be a massive undertaking and the possibility of making an error during 

the process will be a virtual certainty. 

To reduce manpower requirements most sources will likely attempt to automate as much 

of the reporting and record keeping as possible. The equipment costs alone for implementing an 

automated (to the extent possible) data collection and report generation system for a unit with 

multiple controls is likely to be very high and there may be little opportunity for standardization 

of the software. In short, NRECA does not believe that EPA, in proposing its enforceable 

operating limit approach, has adequately estimated or considered the data management costs of 

its proposal and requests that the agency do so. 

Conclusion 

In conclusion, NRECA believes EPA’s proposed approach to setting MACT standards is 

flawed and will result in standards that reflect the performance of a hypothetical, ideal unit that 

does not exist in the real world. The emission limits are far more stringent than needed to assure 

protection of public health and the environment, and may not be achievable by actual sources. 

 The agency has failed to appropriately address emissions that are below the detection 

limits, failed to account for variability in HAP emissions, and has inappropriately established 

standards below the quantitation limits. There are real questions regarding whether sources can 
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even comply with these low limits as well as how they will meet the requirements for 

compliance demonstrations. Furthermore, NRECA has many concerns regarding the proposed 

compliance demonstration provisions and believes that the recordkeeping and reporting 

provisions are overly burdensome. 

 Finally, NRECA urges the agency to consider additional subcategories of sources, to 

promulgate work practice standards for utility auxiliary boilers, and set standards for biomassfired electric generating units that do not impede the construction of new units. 

 NRECA appreciates the opportunity to provide comments on this important rulemaking 

and would be happy to answer any questions EPA may have regarding these comments, or 

provide to the agency additional information that it may desire.