# 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, 20112 

### 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 ....................................................................................................1 6

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 Smal l 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 ...................................................................313 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 Materi als EPA Shared with SERs ......................................................39

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

Appendix C: Written Commen ts Received from SERs ......................................................434 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 Elect ric 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 Nationa l Emission Standards for Hazardous Air Pollutants (NESHAP) for Coal - and Oil-Fired Elec tric Utility Steam Generating Units (Utility NESHAP) currently being developed by the U.S. Environmental Protection Agency (EPA). Under section 609(b) of the Regulatory Flex ibility Act (RFA) as amended by the Small Business Regulatory En forcement Fairness Act of 1996 (SBREFA), a Panel is required to be convened prior to publ ication of the initial regulatory flexibility analysis (IRFA) that an agency may be require d 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 with in 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 propo sed rule being developed;

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

• a description of efforts made to obt ain 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 re port on the comments of small entity representatives and make findings on issues re lated to identified el ements of IRFA under
RFA section 603. Those elements of an IRFA are:

• a description of and, where f easible, 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 th e classes of small entities which will be subject to the requirements and the type of professi onal skills necessary for preparation of the report or record;5 • an identification, to the extent practicab le, of all other relevant Federal rules which may duplicate, overlap, or co nflict with the proposed rule; and

• any impacts on small entities and any signifi cant 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 repo rt is provided to the ag ency issuing the planned proposed rule and included in the rulemaking reco rd. In light of the Panel report, and where appropriate, the agency is to make changes to the draft proposed ru le, 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 developmen t and its report should be considered in that light. At the same time, the report provides th e Panel and the Agency with an opportunity to identify and explore potential ways of shapi ng 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 reduc ing the rule’s regulatory impact on small entities may require further analysis and/or da ta collection to ensure that the options are practicable, enforceable, environmentally s ound, 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 el ectric utility steam generating units (EGUs) under CAA section 112 and listed EGUs pursuant to CAA secti on 112(c). On March 29, 2005 (70 FR 15994), EPA published a final rule (Section 112(n) Revi sion 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 C AA (Clean Air Mercury Rule (CAMR), May 18, 2005, 70 FR 28606). The Sec tion 112(n) Revision Rule was vacated on February 8, 2008, by the U.S. Court of Appeals fo r 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 determin ation, EPA made a finding that it was appropriate and necessary to regulate E GUs under CAA section 112. The February 2008 vacatur of the Section 112(n) Revision Rule re verted the status to that of the December 2000 regulatory determination. CAA section 112( n)(1)(A) and the 2000 determination do not6 differentiate between EGUs located at major ve rsus area sources of h azardous 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 po tential to emit 10 tons pe r year (tpy) or more of any one HAP or 25 tpy or mo re 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 generati ng 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 mo re 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 coope ratives, among others. These units provide electricity for commercial, indus trial, and residential uses. Currently, coal-fired generating units typically supply “base-lo ad” electricity, which means th ese units operate continuously throughout the day and meet the pa rt 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 thr oughout the day or when people return home from work and run appliances and heating/air-con ditioning, versus late at night or very early morning when demand for electricity is reduc ed). Coal- and oil-fired EGUs have the potential to emit many HAP.

Coal-fired EGUs include units that burn co al, coal refuse, or a synthetic gas derived from coal either exclusively, in any combinati on together, or in any combination with other supplemental fuels. Examples of supplemen tal 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, bery llium, cadmium, chromium, cobalt, mercury, manganese, nickel, lead, and selenium.

In developing the vacated CAMR, EPA iden tified a total of 81 potentially affected
small entities with coal-fired EGUs and determ ined 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.7 Additionally, CAMR did not esta blish requirements applicable to existing small entities
because the final rule made allowances availa ble to each State; the States were then to
distribute their allowances to the EGUs with in 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” sour ce category includes
those units that combust coal or oil for the purpose of generating el ectricity 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 Institutiona l Boilers (Area and Major Source Boiler NESHAPs), which were proposed on J une 4, 2010 (75 FR 31896 and 75 FR 32006).
Combustion units that burn a solid waste as de fined by the Administrator will be covered as
solid waste incineration units under CAA secti on 129. However, combustion units that burn a homogeneous solid waste and are qualifying un its 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 fo ssil fuel and meet th e size and electric distribution requirements of CA A 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 particul ate matter (PM), sulfur dioxide (SO 2 ), and nitrogen oxides (NO X ) from boilers constructed after J une 2007. EPA is currently working on additional revisions to the PM, SO 2 , and NO X 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 thos e 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 fi nal 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 facili ties (the Tailoring Rule). The final rule
addresses emissions of six GHGs: carbon dioxide (CO 2 ), methane (CH 4 ), nitrous oxide (N 2 O), hydrofluorocarbons (HFCs), perfluorocar bons (PFCs), and sulfur hexafluoride (SF 6 ). As of January 2, 2011, large industrial source s, including power plants, are subject to8 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 pe rformance for GHGs for new and modified EGUs as well as issuing a proposed rule unde r CAA section 111(d) that includes emission guidelines for GHGs from existing EGUs . Th e rules would establish NSPS for new and modified EGUs and emission guidelines fo r existing EGUs. In addition to the NSPS requirements established for ne w and modified sources under se ction 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 devel op plans for reducing emissions from existing sources. The guidelines includ e targets based on demonstrated controls, emission reductions, costs and expected timefra mes 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 Ma y 26, 2012. At this time the Agency has not formulated a final approach for regulating GHGs from EGUs; however, th ere is the potential that compliance with requirements of the NE SHAP 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 signi ficantly improve air quality by reducing power plant emissions that contribute to ozone and fine particle pollution in ot her states (the Clean Air Transport Rule). Specifically, the proposal would require reductions in SO 2 and NO X emissions that cross state lines. In respons e 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-ye ar 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, incl uding 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 opera tions and wastewater from FGD systems because these sources compri se 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 imp acts 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 FR9 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 th e Phase III regulations covering existing EGU plants using less than 50 MGD of coo ling water. Those regulations also were challenged, and EPA requested, and was grante d, a partial remand. EPA plans to issue regulations that address both Ph ase II and III facilities. EP A signed a settlement agreement that requires those regulations to be propos ed 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 a nd are captured by pollution contro l 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 ha s not yet been determined.

3. OVERVIEW OF PROPOS AL 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 ar e not available for these standards. The proposed standards must set technology-based lim its as appropriate, but we will explore the viability of other rulemaking options, such as work practices standards and health based standards. A work practice st andard, instead of emission st andards, may be proposed for major sources if it is not feasible to prescrib e 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 establis h 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 th at the health threshold will not be exceeded, with an ample margin of safety.

CAA section 112(d)(2) requires standards fo r 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. Fo r 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 fl oor is “the emission control achieved in practice by the best controlled similar source....” Costs may not be considered when determining MACT floors. EPA must cons ider regulatory options more stringent than10 the MACT floor and may regulate “beyond th e floor” where justified. Beyond-the-floor options can include additional control technolog ies, 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 MA CT 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 en tails determining the best performing unit or units in the category fo r each HAP and establishing the MACT floor separately for each HAP (or group of HAP if a surr ogate standard is established). Under this approach, the units on which the MACT floor ar e 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 esta blished using a facility -wide approach. The
concerns associated with th e facility-wide approach are discussed below.

The court has ruled that “no emission re duction” MACT floors (resulting in no emission limits being set) are unl awful. 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 matt er (PM) (as a surrogate for non-mercury HAP metals), mercury, hydrogen chloride (HCl) or sulfur dioxide (SO 2 ) (as a surrogate for HAP acid gases), dioxin/furan, a nd carbon monoxide (CO) or ot her 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 Ceme nt Manufacturing Industry includes emission limits for PM, mercury, HCl, dioxin/furan, a nd THC (75 FR 54970, September 9, 2010). In addition, the proposed Major Source Boiler NE SHAP 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/institu tional boilers and EGUs, the Major Source Boiler NESHAP proposal provides an estimatio n of potential control technologies that may represent those predominantly us ed by EGUs in the MACT floor and that may result in the emission reductions necessary to meet the sta ndards 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 perfor ming EGUs is likely to be based on a fabric filter-controlled EGU, and use of a fabric filt er will likely achieve the PM emission limit. For the various pollutants likely to be regul ated under the Utility NESHAP, the estimated control technologies are:



### • PM/non-mercury HAP metals = Fabric Filters



### • Mercury/dioxin/furan = Ac tivated carbon injection



### • HCl/SO 2 /acid gas HAP = Wet or dry scrubber



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

The court also indicated that when determ ining variability, sour ces outside the MACT floor may not be considered unless a demonstr ated relationship between the variability of11 sources outside the floor and th e variability of sources within the floor can be shown. In characterizing variabilit y of the best performing EGUs, we may include fuel variability and performance variability. In a ddition, we will look at load variability. Recent regulatory actions (e.g. the Major Source Boiler NESH AP proposal, final NESHAP for Portland Cement Manufacturing Industry) as sessed variability based on the 99 th percentile upper predictive limit (UPL). The 99 th 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 stan dards. However, there must be a basis for distinguishing between subcategories (e.g., de sign differences, opera ting mode (continuous or batch), or other characterist ics). Data necessary to establ ish MACT floors are required for each subcategory that is identified.

In order to make the determinations n ecessary 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 tes ting). To date, facility information and available emissions data from the past 5 year s have been received from almost all of the
units. Emissions test results have been rece ived from over 99 percent of the EGUs required to conduct testing.

3.2 Options Likely to be Proposed

EPA is still developing the pr oposal. 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 woul d, 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 addr essed by the Utility NESHAP. Surrogate
standards are allowed if reasonable. Re gardless of whether emission standards are established for HAP or for surrogate pollutants, the same control tec hnologies (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 mon itoring and testing costs imposed on affected entities.

One likely option is to establish subcat egories based on boile r 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., p eaking units versus base-load units),12 subcategorizing coal-fired EGUs by coal rank (e.g., bituminous, subbituminous, lignite) and/or unit type (e.g., fluidized bed, pulverized coal), and sub categorizing oil-fired EGUs by oil type (e.g., residual, distillate). Additio nal potential options include the use of work practice or management practice standards, health-based emission levels, emissions averaging within a facility, re duced monitoring/testing require ments, or allowing more time for compliance, as long as they are consis tent with the provisions of the CAA.

Although emission standards are often struct ured in terms of numerical emissions limits, alternative approaches are sometimes necessary and authorized pursuant to CAA section 112. In some cases, physically measur ing 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, equipm ent, work practice, or operational standard, or combination thereof, consistent with the prov isions 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 prev iously explained, secti on 112(h)(2) provides that the phrase “not feasible to prescribe or enforce an emission standard” includes the
situation in which the Administrator determ ines that the appli cation 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 contro l technologies and management practices that are generally
available to the area sources in the source category. The st andards applicable to major sources in the analogous source category also are considered to dete rmine if the control technologies and work practices are transferable and generally available to area sources. In appropriate circumstances, tec hnologies and practices at area and major sources in similar categories may be considered to determine whet her such technologies an d 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 sta ndards 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 esta blished health thresholds, the Administrator has the discretionary authority to consider such health thresholds wh en 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 th at the health threshold will not be exceeded, with an ample margin of safety. To exercise this discreti on, 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 thres hold to set an emission sta ndard. 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 ca tegories, including the emissions standards
issued in 2004 for commercial and industrial bo ilers and process heater s, which were vacated13 on other grounds by the D.C. Circuit Court. In both the Pulp and Paper NESHAP, 63 FR 18765 (April 15, 1998), and Lime Manufactur ing 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 li ght of the absence of evidence of carcinogenic risk, the availability of in formation on non-carcinogenic effect s, and the limited potential
health risk associated with the discrete uni ts being regulated, EPA concluded that it was appropriate to exercise its discretion under CAA secti on 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 emi ssions 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 ot her HAP acid gases of hydrogen fluoride (HF), chlorine (Cl 2 ), and hydrogen cyanide (HCN).

EPA has a general policy of encouraging th e use of flexible compliance approaches where they can be properly monitored and en forced. 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 th e emission limits by averaging the emissions
from an individual affected unit that is emitti ng above the emission limits with other affected units at the same facility th at 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 pollutant s; no averaging between sources that are not part of the same affected source; no averag ing 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 achieve d without significant additional burden for facilities that must impl ement the rule. For example, use of surrogate pollutants may result in reduced compliance cost s because testing would only be required for the surrogate pollutants (e.g., PM) versus th e HAP (e.g., all non-mercury HAP metals). Continuous monitoring of contro l device parameters, rather th an continuous monitoring of emissions, results in reduced monitoring cost s. Standards based on work practices or management practices in lieu of emission limits also result in reduced compliance costs because testing and continuous monitori ng 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 reconstruc ted 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 ma y 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 complian ce with the Utility NESHAP, EPA believes that 3 years for compliance is likely necessary to a llow adequate time to design, install and test control systems. Section 112( i)(3)(B) of the CAA allows f acilities to request a one-year extension to any MACT complian ce schedule if such additional time is necessary for the14 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 sour ce 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 availa ble 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 extende d 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 th e 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 sma ll 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 opera ted 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 sma ll business size standards: NAICS Sect or 92 – Small business size standards
are not established for this sector. Establishments in th e 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 pr ivate sector industry that best describes the activities to be performed. For exampl e, if a government agency issues a procurement for law enforcement services, the re quirement 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 colle ction 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 Br adstreet, Standard & Poor’s, American Business Information, the En ergy Information Administration (EIA) within the U.S. Department of Energy, th e 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 sm all State/local governme nts and 14 small nongovernment entities. These numbers reflect a dditions 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 aw are of any EGUs owned by Tribal entities. Potentially affected small entities ar e 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 Powe r 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 entit ies includes electricity generators. SERs
believe that this list should also include distribution coope ratives that own electricity generation and transmission (G&T ) cooperatives and that qualif y as small entities. SERs stated that the Utility NES HAP will have a direct impact on all electric cooperatives generating and/or distributing coal-based power given the closely inte rwoven nature of the G&T cooperatives and the distri bution cooperatives. SERs expl ained 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 coopera tives they serve. EPA ac knowledges that small entity distribution cooperatives that own generation processes would be impacted in some way by the Utility NESHAP because generation processe s will be regulated by the standards, but the extent to which small entity distribution coope ratives 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 upc oming rulemaking to provide an opportunity for discussion of their questions and concerns re garding the upcoming rulemaking. The outreach consisted of meeting with some organizations that represent and include small entities, including the American Public Power Associa tion (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 SE R with background inform ation on the Utility NESHAP rulemaking process. An outreach mee ting with the SERs was held on December 2,

2010.

6.2 Summary of Panel’s Outreach Meetin g 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 pro cess participated in the meeting (in person and by phone). There were five non-SER participan ts from organizations representing power producers. The Outreach Meeting was held to solicit input/suggestions from the SERs regarding the upcoming rulemaking. The meeti ng was opened by Ken Munis, acting in place of Alex Cristofaro, EPA’s Small Business Advoc acy Chair, with a short introduction to the Regulatory Flexibility Act (R FA) and SBREFA process, the purpose of the Outreach Meeting, and the importance of the SERs’ comm ents. Following this was a presentation by EPA staff. Information presented included:

• Background17 • Project history

• Section 112 overview

• Constraints on rulemaking

• Affected facilities

• Data

• Rulemaking options under consideration

• Potential control technol ogies and estimated costs

• Applicable small entity definitions

• Small entities potentially subject to regulation

• Questions for SERs

A discussion of issues related to the NE SHAP program in general, the potential requirements of the Utility NESHAP, and the re gulatory areas where EPA has discretion and could potentially provide flexibility follo wed the presentation (see section 8.5 for discussions/comments raised during the EPA Outr each 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 Am erican Public Power Associat ion (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 Ge neseo Municipal Utilities* Dalton, GA Geneseo, IL Tim Long

Holland Board of Public Works Ja mestown Board of Public Utilities Holland, MI Jamestown, NY Daniel Nally Steve Kulig18 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, Ed ison Electric Institut e (EEI), Hunton & Williams, and J.E. Cichanowicz, Inc. partic ipated as viewers/technical backup that augmented the SERs and provided comment but di d 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 SMA LL ENTITY REPRESENTATIVES

8.1 Number and Types of Entities Affected

The table in Chapter 5 of this report, wh ich 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 outre ach meeting, SERs indicated that they believe19 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 i ndicated that in addition to small entity G&T cooperatives, there are small entity distributi on cooperatives that own G&T entities that could be potentially impacted.

Written comments indicate that cooperative s 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. B ecause the G&Ts are owned by the distribution cooperatives they serve, SERs believe that th e Utility NESHAP will ha ve a direct impact on all electric cooperatives gene rating and/or distributing coal -based power. NRECA provided a list of the 14 G&T cooperatives that own co al-fired generation and that NRECA believes qualify as small entities under the SBA size stan dards. NRECA’s list includes cooperatives
that NRECA believes meet the SBA size standa rds and were not on EPA’s list, and omits some cooperatives that were on EPA’s list a nd 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 th e following four issues with respect to determining MACT floors and assessing variab ility: (1) pollutant -by-pollutant ranking approach, (2) pollutants to be regulated, (3) floor determin ation methodology for existing units, and (4) assessment of emissions variabil ity, 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 faci lity-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 (NO X ) was discussed. SERs explained that minimizing CO to meet its limit could actually lead to
an increase in NO X 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 un it 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 NO X production and, therefore, it may be diffi cult to meet a CO limit if NO X reductions are also required). One SER explained that, in fact, using CO as a surrogate is a concern because of the inverse relationship between NO X and CO.20 In written comments, SERs stated their belief that the Utility NESHAP should be limited to mercury control only. EPA has not dete rmined that emissions of other HAP in the quantities emitted are detrimental to human heal th 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 inventor y 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 situa tion where the amount of available data from a large source category or subcategory would requ ire 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, a nd institutional boilers and process heaters).

With respect to estimating variability associated with emissions of the best performing EGUs, during the outreach meeting, SE Rs asked that EPA consider establishing percent reduction limits (i.e., required emissions reduction between the EGU inlet and the stack) as an alternative to comp lying with an emissions limit (i.e., an emissions value at the stack). They believe that percent reduction lim its 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 star tup 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 shutdo wn 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 peri od, especially for CO, would prevent a single spike in emissions fromcausing a well performing unit to be in noncompliance.

SERs stated in written comments that in orde r 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 variab ility 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 em issions of the best performing units. That SER also explained that thre e-day stack sampling provides a snapshot of a unit’s HAP emissions and is not indicative or representati ve 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 th eir recommendation that the rule should include an either/or standard of percent reduction or emission limits to allow the source to comply with the least21 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 mo re than one mine, and to the blending of various sources, types, or amounts of coal. One SER pointed out th at, over the past six years, variation in their monthly composite coal sa mple from a single mine has ranged between 17 and 48 pounds of mercury per trillion Btu, and ye arly averages have ranged between 24.5 and 31.9 pounds of mercury per trillion Btu. Th at SER recommended an emissions standard based on a 12-month rolling average due to th e variability of mercury in fuel and the difficulty of measuring minute quantities of me rcury. SERs representing cooperative entities believe that work practice standards are mo re appropriate during periods of startup, shutdown, and malfunction than are HAP em ission limits based on long-term rolling

averages.

One SER indicated that de minimis exem ption is a regulatory option/small entity flexibility that EPA should consider.

8.3 Monitoring, Reporting, and Recordkeeping

During the outreach meeting, SERs made se veral observations in response to EPA’s estimated costs for mercury and PM conti nuous 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 th an $260,000). A SER explained that their mercury CEMS worked for about one m onth and has presented numerous problems in the two and a half years since th at time. For these reasons, SE Rs believe that mercury CEMS should not be a requirement of the Utility NE SHAP. SERs stated that PM CEMS are not widely deployed within the utility sector. SERs expressed a c oncern regarding the ability of PM CEMS to operate properly in stacks containi ng moisture (i.e., EGUs with wet scrubbers). One SER suggested that requiri ng opacity monitoring and periodi c emissions testing is more appropriate than requiring PM CEMS. Another SER stated that if PM CEMS are required by the Utility NESHAP, opacity monitoring requirem ents (i.e., continuous opacity monitors) of other Federal regulations should no longer apply.

In written comments, SERs recomm ended that monitoring, reporting, and recordkeeping requirements should be minimi zed 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 ne ed to install PM monitors upstream of wet
scrubbers rather than in the stack as is typical. Upstream in stallation 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 pa rticulate 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) installe d and will already be below what the SER posits the PM limit may be.22 8.4 Subcategorization

One SER commented during the outreach m eeting that EPA should subcategorize lignite-fired EGUs from other coal-fired EGUs. The SER further commented that separate subcategories should be established for the tw o types of lignite-fired EGUs (i.e., North Dakota lignite and Gulf Coast lignite). The SE R indicated that not only do lignite-fired EGUs differ from other coal-fired EGUs, but E GUs 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 practic e. An option mentioned to address the practice of coal blending is to establish se parate subcategories for bituminous coal-fired EGUs, sub-bituminous coal-fired EGUs, and blended bituminous/sub-bituminous coal-firedEGUs. 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 standard s. 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 poten tially 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 time s. Some SERs requested that EPA consider establishing a subcategory for combined heat an d power (CHP) units that meet the definition of EGU (i.e., generate enough el ectricity). 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 peaki ng units. Similar comments were not made with regard to consideration of base-load oi l-fired EGUs and peaki ng 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, secti on 112(d)(1) of the CAA does not restrict subcategorizati on to cases where the class, type or size fact ors affect HAP emissions. As an example, SERs expl ained that, under CAA section 111, EPA has subcategorized boilers on the basis of size (heat input) or the type of fu el burned (coal, oil or gas) and that these subcategor ization decisions were based on feasibility and/or cost considerations, not on the le vel 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 ra nk has a significant eff ect on mercury and HCl emissions. In addition to recognizing the differe nces in the characterist ics of the Gulf Coast lignite and the North Dakota lignite , SERs pointed out that the qua lity of coal in the Illinois basin varies considerably even within the basin. One SER st ated that subcategories should be established for base-load EGUs and peak ing EGUs. The SER supported subcategories
based on whether an EGU burns Powder River Ba sin (PRB) coal, lignite, fuel oil, or other fuel types. The SER further stated that the abil ity to change subcategory with changes in fuel type will be important. A nother SER recommended that wall-fired EGUs and tangentiallyfired EGUs should be separate subcategories. The SER explained th at tangentially-fired
units have lower NO X emission rates than wall-fired units. NO X is not directly affected by23 the Utility NESHAP but CO ma y be used as a surrogate for organic HAP. Because NO X and CO are inversely related, the SER further explained that the lower NO X 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 re gulations. One SER also stated that EPA should consider a co-firing subcategory fo r 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 s uggested that EPA establish separate
emission standards for EGUs located at area s ources of HAP and for EGUs located at major sources of HAP. SERs suggested that the st andards for EGUs at area sources be based on GACT rather than MACT, as allowed under sect ion 112(d)(5) of the CAA. Specifically, SERs recommended that EPA establish manage ment practice standards for natural area source EGUs as well as synthetic area s ource EGUs. EPA estimates that there are approximately three natural area source EGUs a nd 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 be lieve that separate
standards would have the effect of lesseni ng the regulatory burdenon small entities.

8.6 Work Practice Standards

During the outreach meeting, SERs recommended that EPA establish work practice standards for major source EGUs. This r ecommendation was further detailed in written comments. SERs urged EPA to promulgate wo rk 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 percen tage of the dioxin/furan and non-dioxin organics measurements) from EGUs are emitted at or below detection limits. Therefore, in these instances, SERs belie ve that CAA section 112(h) allows the Administrator to promulgate a design, equipmen t, work practice, or operational standard.

8.7 Health Based Emission Limits

SERs commented during the outreach meeti ng that EPA should consider using its CAA section 112(d)(4) authority to set a health based emissi on 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, Cl 2 , 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 t echnologies when developing the Utility NESHAP. They expressed concern with how ot her regulatory actions would imp act EGUs’ emissions profiles and if those impacts would be accounted fo r when determining requirements of the NESHAP. Specifically, SERs questione d what the impact of controlling SO 2 and NO X emissions as a result of complying with th e Transport Rule will do to the level of CO emissions, given the NO X -CO relationship (i.e., when NO X emissions are reduced, CO emissions may increase). SERs commented that if CO emissions are, in fact, elevated in the future due to controlling NO X emissions as required by the Tr ansport Rule, those higher CO emissions won’t be reflected in the Utility NESHAP emission limit calculations because
those calculations will be based on current em issions data that don’t reflect the potential future emissions profiles imp acts of other regulatory requireme nts. The SERs are concerned with the degree to which multiple Federal rules may have cumulative impacts on small
entities.

In written comments, SERs st ated that EPA should consid er the synergistic adverse impacts that the Utility NESHAP will have on small cooperatives in conjunction with the many other air-related rulemakings that are ongoi ng. 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 entitie s estimated that anywhere from 30-50% of the remaining coal-fired power plants might d ecide 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 possi ble on an economical basis. However, when the capital cost must be absorbed at on ce, 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 ca nnot 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 faci lities with minimal planning staff (e.g., the SER’s facility has three environmental posi tions that are responsible for monitoring regulatory developments and planning to impl ement them, in addition to the day-to-day environmental responsibilities).

8.9 Potential Adverse Economic Impacts

SERs commented during the outreach meeti ng on a number of concerns they have with respect to small entities’ ability to comply with the potential requi rements of the Utility NESHAP. Those concerns included (1) mark et 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 ag ainst large companies for loans, engineering services, equipment vendor services, emissions testing contractors, etc., (7) the lack of infrastructure, (8) physical constr aints (i.e., footprint availability ), (9) the lack of necessary25 implementation time (SERs estimated that 5 to 8 years will be necessary for planning and engineering, financing, delivery and installation, emissions testi ng, etc.), and (10) a potential permitting delay caused by entities making ot her 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 conc erns, as well as the overall concern that compliance with the Utility NE SHAP will complicate the SERs’ ability to finance and plan ahead for meeting other future rules impacti ng 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 st andards, (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 implicati ons of EGU reliability versus compliance with the Utility NESHAP when establishing the rule’s requirem ents. To comply, each EGU will be required to go offline for a period (or se veral 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 approve d and may not be allowed for the time period requested. In written comments, SERs repres enting 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 sti ll 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 su pplying 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 pollu tion control requirements should be designed to utilize existing equipment to the greatest exte nt possible. The SER i ndicated that the lack of back-up generation is a part icular concern for small entitie s. If the addition of a new pollution control device requires electricity ge neration to end for many months, the member municipalities would lose their primary sour ce of electric power for that entire time.

SERs expressed concern that, depending on th e type and stringency of requirements, the regulations could be so expensive that th ey cause extensive plant retirements and job losses. In written comments, SERs represen ting cooperative entities e xplained that because the G&T cooperatives are owned by the distribut ion cooperatives they serve, there are no third party shareholders who c ould help share the costs of co mpliance. All additional costs borne by the cooperative (and paid for by the dist ribution cooperative me mber-owners) affect the financial well-being of the G&T cooperativ e. 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 incr eased costs cannot be offset by reducing profit margins and costs must be passed on to th e end user. One SER indicated that capital
investment would be recovered through retail rates, and that t ypically rate adjustments take
about six months. SERs stated that in addi tion 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 cer tain 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., th rough 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 switc hing may not be a reasonable or practical alternative to meeting emission limits. One SE R suggested that EGUs at sites hampered by physical site constraints may need a limit highe r than MACT (i.e., a limit that can be met using a control device that would f it in the physical constr aints 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 disa dvantage in competing with large electric generating providers for equipment and skilled la bor resources in a severely tight compliance
timeframe. SERs believe that the most co mpetitive 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 Ru ral Utilities Service (RUS ) electric loan policy be changed to allow loans for coal-fired projec ts to meet environmenta l regulations. Another
SER estimated that six months will be need ed to obtain funding through municipal bonds once the project cost is known. One SER r ecommended 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 filte r, 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 respec t 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 th at the ambiguity of what triggers NSR and the litigious atmo sphere surrounding boiler upgrades provides a disincentive for utility ef ficiency improvements.

8.10 Concerns with the Small Business Advocacy Review Process

In written comments, SERs st ated that they do not believe they were provided the opportunity for effective partic ipation in the Federal regulat ory process as required by27 SBREFA. Specifically, SERs indicated that they were not provided descriptions of significant alternatives to th e proposed rule, differing compli ance or reporting requirements
or timetables that take into account the res ources available to small entities, and the clarification, consolid ation, or simplification of complia nce 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 meeti ng, and SERs were only provided 14 days to prepare written comments. Thus, the highl y abbreviated small business review panel prevents small entities from having the meaningf ul advisory role contemplated by SBREFA. SERs requested that EPA schedule additional panel meetings once the Agency has progressed further in its rulemaking prepar ation. One SER indicat ed that EPA should consider starting over with the SBREFA pro cess. 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 allo w for implementation to take place such that the integrity of the Grid, the national econom y, and national security will be protected.

9. PANEL FINDING S 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 repr esenting public power entities made the point that joint action agencies could be small entities potentially im pacted by the Utility NESHAP. SERs representing cooperatives pointed out that a la rge number of small distribution cooperatives that ow n 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 Mi nnesota Municipal Power Agency, are included on the list of potentially impacted small entitie s. The RFA guidance directs EPA to estimate direct impacts at the highest level of owners hip (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 divide d 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 re gulated by the Utility NESHAP, impacts to entities that own those processe s 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 accounte d for in the small entity analysis. The Panel acknowledges that small entity distribution cooperatives that ow n generation processes would be impacted in some way by the Util ity NESHAP because generation processes will be regulated by the standards, but the extent to which small entity distribution cooperatives28 would be impacted is unclear w ithout more detailed informati on on these entities. It should be noted that some small entity distribu tion cooperatives own small entity generation cooperatives, but other small entity distribut ion cooperatives own ge neration cooperatives that are not small entities, or other distribution co operatives 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-pol lutant ranking approach, (2) po llutants 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 fo r each of these issues in succession below.

SERs stated that the end result of dete rmining 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 repr esent the emission levels achieved by an actual, bestperforming EGU. SERs believe that th is methodology for setting MACT floors is inconsistent with the requiremen ts 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-b y-pollutant approach for determining MACT standards for each HAP or HAP surrogate, while taking into account poten tial direct conflicts between pollution control technologies

As noted above, there are concerns with resp ect 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 floo rs reflecting mediocre or no control, rather than perf ormance which, for existing sources, is the average of what the best performing sources have achieved. For ex ample, if the best performing 12 percent of facilities for HAP metals did not control orga nics as well as a different 12 percent of facilities, the floor for organi cs and metals would end up not reflecting best performance. This fact pattern has come up in every rule wh ere EPA investigated a facility-wide approach. See, e.g. 75 FR at 54999 (Sept. 10, 2010). Thus, u tilizing the single-facili ty 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 st atute. Moreover, a single-facility approach would require EPA to make value judg ments 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 appr oaches to setting the MACT floor, which account for achievement in prac tice for control of all HAP.

SERs stated their belief that the Util ity 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 s ection 112(d) standards for all HAP emitted from major source EGUs consistent with the statut e and case law from the Court of Appeals for the D.C. Circuit. Specifically, CAA secti on 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 li sted HAP emitted by major sources, the most recent pronouncement coming three years after th e proposed NESHAP for EGUs. See Sierra
Club v. EPA , 479 F.3d 875, 883 (D.C. Cir. 2007). (“EPA ha s 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 t echnology.’” quoting Nat’l Lime Ass’n v. EPA , 233 F.3d 625, 634 (D.C. Cir. 2000)); see also Na tural Resources Defense Council v. EPA , 489 F.3d 1364, 1371 (D.C. Cir. 2007) (affirming that EP A must establish emission standards for listed HAP emitted from a category, citing Sierra Club and National Lime ). For these reasons, EPA rejects the proposed interpreta tion 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 200 4 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 ti me, 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 NO X production, it may be difficult to meet a CO limit if NO X 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 resu lt in technical infeasibility with respect to
CO and NO X may argue against using CO as the surrogate pollutant for organic HAP.

SERs commented that the MACT floor for ex isting 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 av ailable 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 collect ed. If EPA proposed the latter, OMB and SBA recommend that they clearly expl ain why the subset of sources for which they have data is representative of the entire se t of sources.

SERs asked that EPA consider establishing percent reduction limits as an alternative to complying with an emissions limit as a mean s 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 star tup and shutdown could present problems with meeting emission limits and suggest ed 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 provi des a snapshot of a unit’s HAP emissions and is not indicative or repres entative of the unit’s emissions over longer periods of time. SERs pointed out that a critic al question is how EPA plans to modify the stack emissions reported during the ICR to account for fuel, pe rformance, and load variability. One SER suggested that use of a longer-term rolli ng 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 op tion/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 establish31 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 thatthe Agency consider the inclusion of percent reduction standards given the legal cons traints and the lack of data necessary to establish such standards. Regarding the SE Rs’ concerns with meeting emissions limits during periods of startup and shutdown, EPA panel members recommend that the Agency base the proposed emission limits on reasona ble averaging times where appropriate. In determining reasonable averaging times, EPA pa nel members recommend that in addition to considering performance during periods of star tup and shutdown, the Agency also consider fuel and load variability. In addition, EP A panel members recommend that the Agency use all data gathered thr ough the ICR for EGUs that comprise the MACT floor, to the maximum extent possible consistent with the CAA requirements and as a ppropriate, 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 se t emission standards for each listed HAP,’ which
does not allow it to ‘avoid sett ing standards for HAPs not c ontrolled 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 lis ted 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 f acility 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. Th e Panel recommends that EPA consider fuel variability when deriving the emissions sta ndards. The panel members recommend that the Agency evaluate whether establishing work practice requirements duri ng periods of startup
and shutdown would be consistent with CAA section 112(h) and inve stigate whether there are technical bases for establishing sepa rate 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 simplifie d 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, period ic stack testing, etc.) and consider requiring PM CEMS only for the largest EGUs or allo w use of PM CEMS as an alternative to32 conducting opacity monitoring and periodic emi ssions 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 availa ble alternatives and options to the current opacity provisions.

OMB recommendations : OMB recommends EPA propose alternative monitoring approaches (e.g., parameter monitoring in li eu of requiring the use of mercury CEMS, sorbent traps, periodic stack testing) for small entities a nd 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 consid er relevant factors identified by the SERs in developing this rulemaking, but it do es 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 th ese are flexibilities wo rthy of consideration, and perhaps proposal, but without information n ecessary to evaluate specific regulatory alternatives or the impacts of those decisions on particular sma ll entities or small entities in general, SBA believes that the Panel can ma ke 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 subcategor izing 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 co al-fired EGUs are not primarily base-load, as in the past, but may alternate between opera ting as base-load units and peaking units. Similar comments were not made with regard to consideration of ba se-load oil-fired EGUs and peaking oil-fired EGUs as separate subcategories.

Panel Recommendations

EPA recommendations : EPA recognizes subcategorizati on may be necessary and we will consider whether subcategoriza tion 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 adopt ing the following subcategories for EGUs:

 Fuel type
► North Dakota lignite
► Gulf Coast lignite
► Bituminous coal
► Sub-bituminous coal
► Blended bituminous/sub-bituminous coal33 ► 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 op erating 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 memb ers and OMB recommend that EPA consider these subcategories and adopt a set of standards that is cons istent with the CAA and which effectively reduces burden on small entities.

SBA recommendations : SBA agrees that EPA should c onsider various subcategorization options in developing this rulemaking, but it do es not believe that the Panel has sufficient information to recommend a particular subc ategorization option th at would minimize the significant economic impact of the proposed rule on small entities. While a large number of subcategories may serve to establish standard s that minimize the economic impacts on some particular small entities, it could also disadva ntage 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 standard s 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 panel34 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 propos e 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 a nd 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 th at 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 feas ible 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 technol ogical 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, in cluding 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 prac tice 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 pr opose 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 sp ecify 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 enc ouraged 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 Recommendations35 EPA recommendation : EPA panel members recommend that the Administrator consider her discretionary authority to propose a HBEL fo r acid gas HAP emissions as a regulatory flexibility option.

OMB and SBA recommendations : OMB and SBA recommend th at 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 fo r 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 NES HAP. EPA is currently working on revisions to the PM, SO 2 , and NO X 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 indu strial 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 en tered into a settlement agreement to
issue rules that will address GHG emissions from fossil fuel-fir ed 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 wh at the impact of controlling SO 2 and NO X emissions as a result of complying with th e Transport Rule will do to the level of CO emissions. The Transport Rule, as propose d, would require 31 states and D.C. to significantly improve air quality by reducing powe r plant emissions that contribute to ozone and fine particle pollution in ot her states. Specifically, the pr oposal would require reductions
in SO 2 and NO X emissions that cross stat e lines. The Transport Rule is expected to be finalized in late Spring 2011 and, to the extent th at 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-ye ar study of the Steam Electric Power Generating industry, EPA plans to revise the curr ent 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 establis hed best technology
available standards to minimize adverse enviro nmental impacts from cooling water intake36 structures. In developing th ese standards, EPA divided its effort into three rulemaking phases. Phase I standards, for new EGU plants using cooling water, we re 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 re quested, and was granted, a partial remand of the Phase III rule. EPA signed a settlement ag reement 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 fo r 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 consid er relevant factors identified by
the SERs in development of this rulemaking, includi ng the extent to wh ich other recently proposed or finalized regulatory obligations imposed by EPA will impact small entities or make compliance with this rulemaking more diff icult. However, SBA does not believe that the Panel has information necessary make r ecommendations 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 en tities 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 propos ed 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 de veloping the proposed standards. The Panel recommends that the Agency investigate other potential surrogate pollutants for organic HAP in lieu of CO, given the NO X -CO relationship (i.e., when NO X emissions are reduced, CO emissions may increase). In developing the NE SHAP for EGUs, the Panel recommends that the Agency avoid duplicating requi rements to the fullest extent possible in order to minimize
unnecessary costs.

9.9 Potential Adverse Economic Impacts

SERs commented on a number of concerns th ey have with respect to small entities’ ability to comply with the pot ential requirements of the Util ity 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 comp lying with the standards. SERs asked that EPA consider the implications of EGU relia bility versus compliance with the Utility NESHAP when establishing th e rule’s requirements. SE Rs expressed concern that,37 depending on the type and stringency of require ments, the regulations could be so expensive that they cause extensive plan t 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 th at 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 sec tion 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 co nsider various options for all regulated entities, especially small entities. With respect to dates, EPA doe s 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 th e potential for streamlining the process for petitioning for a fourth year for purposes of co mpliance with the standa rds and consider the
need to invoke the national security exemption under sec tion 112(i)(4) of the CAA. Additionally, the Panel recomme nds that EPA seek comment in the proposed rule on the potential adverse economic impacts of the ru le 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 proce ss as required by SBREFA. SERs indicated that they were not provided descriptio ns of significant alternatives to the proposed rule, differing compliance or reporting requirements or timetab les that take into account the resources
available to small entities. SERs further in dicated that there was no pre-meeting to go over information on the rule, there was only one out reach 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 Agen cy has progressed further in its rulemaking preparation, that EPA consider starting over with the SBREFA pr ocess, and that EPA request an extension to allow time to (1 ) adequately analyze lessons le arned in the Boiler MACT rule development process, (2) thorough ly analyze the emissions data, (3) continue to meet with utility industry representatives, and (4) cons ider the range of possible emission control options that would allow for implementation to ta ke 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 SE Rs sufficient opportunity to suggest regulatory alternativ es, and thus, makes no recommendations to address these38 concerns. The time constraints of the small bus iness advocacy review process with respect to the Utility NESHAP were explained at the begi nning of the process. That is, due to the regulatory schedule there coul d only be one SER outreach m eeting. 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 inform ation to allow SERs to make suggestions concerning regulatory alternativ es (e.g., regarding subcategor ies, HAP and HAP surrogates, monitoring requirements, contro l technologies potentially requi red to meet standards, CAA
authorities to establish health-based emission li mits and work practice st andards) as part of the small business advocacy review process, and the SERs have in fact made many productive suggestions EPA will seriously consid er as part of the rulemaking process.

OMB recommendation : Although OMB understands the time constraints imposed on this rulemaking process, we recommend that once EP A has drafted a set of emissions limits for EGUs, they convene another meeting with the SE Rs 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 in formation provided to the Pane l and the SERs and about the
schedule for the Panel. SBA believes that mo re 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 info rm the Panel's recommendations.

SBA recommends that EPA request an extensio n 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 addi tional 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 “Rulemak ing 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 technol ogies and estimated costs

• Applicable small entity definitions

• Small entities potentially subject to regulation

• Questions for SERs40 

### 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 addi tions or deletions? Could you briefly explain the reason for each addition or deletion.

Firm Characteristics

1. How many units do you have in you r 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 ar e your EGUs currently subject to?

2. What compliance requirements are associated with the other standa rds that apply to your EGU?
3. What emissions control technologies do you ha ve 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 require ments are you subject to under other standards that appl y 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 environmen tal regulatory reasons, insurance reasons,
or other reasons?

5. Did you provide any of the monitoring da ta to the Agency during the recent Information Collection Request on Utility Bo ilers or another in formation collection request?41 6. If your EGU is subject to emission limits , are there alternatives to monitoring emissions or stack testing that would be le ss 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 cl ass, 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 variabil ity 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 establishi ng 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 consid er 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, fac ility configurations, overall fence-line characteristics, population proximity to plan t, potential adverse e nvironmental effects
that would otherwise be reduced or eliminated.

Other Potential Options/Flexibilities:

1. Are there other regulatory options or sm all entity flexibilities that EPA should
consider?

Cost Estimates

Control Technology:42 1. If you employ any of the control technol ogies 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 a nd monitoring cost estimates presented on slide 27 of the outreach presentation? ? If not, provide your co st 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 re quire to finance and install new emissions control and monitoring equipment?

2. How long would be required if there we re other regulations requiring similar
investments that had to be implemented consecutively?

3. How would new emissions requirement s 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 capita l 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 commi ssion, or does it operate in competitive markets? If you had to install additional control equipment that required capital investment, would you adjust the rate ch arged 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 f und capital investment for regulatory compliance?

### Appendix C

Written Comments Received from SERs

1. Alan Bonderman, Atlantic Muni cipal Utilities, Atlantic, IA

2. Erik Booth, Marquette Board of Light & Power. Marquette, MI

3. Donald Pauken, Muscatine Powe r & Water, Muscatine, IA

4. Joe Eutizi, San Miguel Electric C ooperative, 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 Mu nicipal Services, Wyandotte, MI



### Written Comments Received fr om 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 Utilit ies, regarding the promulgation of regulations for control of hazardous air pollutants, referred to as the “Utility MACT” rules.

A llen 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

1/6/2011 file://C:\Documents and Settin g s\mbarch\Local Settin g s\Tem p \notesFCBCEE\~web3790.htmA tlantic Municipal Utilities

- 15 West 3 rd 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 regardi ng EPA’s rulemaking to set maximum achievable control technology (“MACT”) standards for hazardous air pollu tant (“HAP”) emissions f r o m coal

- and oil

fired electric utility steam generating units (“EGUs”) . I was listed as a participant on th e panel convened under the Small Business Regulatory Enforce ment 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 locate d 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 satis fied through a power purchase agreement with Missouri River Ener gy Services (MRES), a municipal joint action agency with headquarters in Sioux Falls, SD. Locally, w e also own a 4 megawatt dual

- fuelled Nordberg diesel generator, and a Solar dual

- fuelled combustion turbine, which has low

- NO
x controls.

Our Walter Scott 3 resource has, over the past several years, been upgraded with pollution con trol equipment and systems to decrease emissions, including low

- NO
x burners, a neural network, scrubber and baghouse. Atlantic ’ s share of these improvements was in the neighborhood of $7 million , which exceeded our original inv estment in the plant back in the late 1970 ’ s.

As to the MACT standards and SBREFA panel, d ue 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.A tlantic Municipal Utilities

- 15 West 3 rd Street

- Atlantic, IA 50022

- Tel. (712) 243

- 1395

- Fax (712) 243

- 2028 Th e EGU MACT rulemaking may be one of the most expensive rulemaking s in the history of the electric utility industry . Its impact on small systems such as our s 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 bur den of th at 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 le ss 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 exte nsive 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 panel s will rev iew “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 alternat ives 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 s mall entities. Th e SER meeting related to these rules involved no preparation and distribution of these clarifications, consolidations or simplifications of the EPA regulatory options.

The EPA material s did not include possible rulemaking alternatives

, nor any information about possible compliance or reporting options

. Moreover, th e material lacks any results of EPA’s analys e s of the data
from the extensive information collection request (“ICR”) that EPA identified as being criti c al to the promulgati o n of a n EGU MACT rule

**.** It seems obvious that EPA has fail ed to meet the statutory requirements,

As a non

- expert, I am unable to address the specific items detailed in the panel ’ s materials, and wh ich were discussed at the meeting. I can , however, and wil l, 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 Asso ciation (APPA), wh ich has also submitted comments. We see APPA as a voice for our system, and for s ome 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 comment s 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, wh o 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 u s?

APPA ’ s comments, which we completely agree with , include positions such as:A tlantic Municipal Utilities

- 15 West 3 rd Street

- Atlantic, IA 50022

- Tel. (712) 243

- 1395

- Fax (712) 243

- 2028 1.) EPA is not complying with requirements of the Small Business Regulatory Enforce ment Fairness
Act of 1996

, for several reasons described in APPA ’ s filed comments.

2.) Inadequate time was allowed for input from small busines s.

3.) EPA failed to correctly identify the scope of the HPA ’ s to be regulated , and did not provide any lega l 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 t hat on December 7 th

, 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 M ACT 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 exper tise

– including trade association representation of affe cted 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.

T hank you for the opportunity to be heard

.

Allen Bonderman General Manager Atlantic Municipal U t ilities 15 West Third S t reet Atlantic, IA 50022 ABonderman@amu1.net

712

- 243

- 1395RE: 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 1 889 1 6 December 2010

Re: Small Business Advocacy Review Panel for the National Emission Standards for Hazardous Air Pollutants (N ESHAP) 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 Emis sion Standards for Hazardous Air Pollutants (NESHAP) for Coal

- and Oil

fired Electric Utility Steam Generating Units. The Marquette Board of Light & Power owns and operates a 44 megawatt pulverized coal

- fired boiler and two smaller stoker

fired boilers ser ving 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 ar ea is occupied by mostly residential ratepayers , commercial facilities, and institutions (the largest two b eing a hospital and University).

This rule (EGU MACT) along with the Federal Implementation Plans to Reduce Interstate Transport of Fine Particulate Matter an d 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; Identific ation and Listing of Special Wastes; Disposal of Coal Combustion Residuals from Electric Utilities (Coal Ash D isposal 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 l ittle 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 pollut ant 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 ComplianceImpact s on Small Businesses from Multiple R egulations 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 Enviro nmental Protection Agency has proposed

, within the last couple of years

, a s tring of rules simultaneously that have tremendous economic impacts on small public power utilities . Each rule represents a cost burden of millions of dollars
indi vidually. Taken one at a time, compliance with these rules is possible on an
economic al basis. However, when the capital cost must be absorbed at once , small non

profit municipalities and their ratepayers will suffer economic hardships. M unicipalities
do n ot 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 provi d e s a “ y a r d s t i c k ” f

o r b o t h consumers and government officials to measure the cost of providing wholesale electricity against the rates of local private power companie s and local electric utility cooperatives. Our municipal ity is located in small communit y

. Residential ratepayers could not absorb the cost of compliance with these rules if they are concurrently enacted. S mall busin esses (such as the local grocery store s , small retailer s , locally o wned 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

, th en we strongly urge you to consider a separate category for small non

- profit electric providers.

Timing of Compliance

- I nability to Receive Competitive Pricing
If the EGU MACT follows the C lean 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 th e 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. D ue to the limited number of manufacturers, the most competitive pricing and attention will go to the large

- scale

accounts

. Small business es 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 i f the EPA decides to proceed with a n EGU MACT, which requires all sources to comply within three years
from the date the rule i s f inalized

. 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 tec hnologies 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 demand s 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 M illwrights. 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 provid ing enough electricity to satisfy demand along with balancing the ability to hi re 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 r ule that conflicts with the other national direction of moving away from coal combustion. Essentially, th e B oiler MACT rule as proposed provides no incentive to burn biomass unless a boiler can operate on biomass alone. Burning biomass alone may not be fea sible in existing coal

- fired u nits. 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 co al.

P articulate Matter (PM) Continuous Emission Monitori ng System (CEMS) Opacity has long been an indicator of good particulate emission control s

. Opacity is a
much more economical and proven method of monitoring over a PM CEMS

, which
carries an EP A 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 v isible emissions limitations currently being used for compliance determination with particulate emission limits (see Michigan Department of Environmental Quality Operational Memo No. 14 attached)

.M ichigan Department of Environmental Quality: Operational Memo No. 14

– May 6,

1997 (page 5).

The EPA estimated an nual costs of $48,000

- $63,000 for a PM CEMS is more than
double what is currently s pent 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 option s

.

Energy Optimization Energy optimization is a widely popular method o f reducing air pollutant emissions and should be incorporated in the EGU MA CT. 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 t hat 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 bemade be replacing the metal alloys in feedw ater 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 surroundi ng boiler upgrades ha s prov ided 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 efficientl y 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

p erforming 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 change s in the boilers

.

Our concern is that EPA will focus on the nominal energy savings measures such as light bulb changes, a utomatic 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
environme ntal 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 followi ng comments and responses to the "Questions for SERs" (See Attachment A).

MPW is a municipal utility that serves the City of Musca tine, 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 proc ess steam to its largest electrical cust omer. 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 Op erator. 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 sele cted by MISO on a daily basis for supplying energy to the MISO region. Revenues from partic ipating in the market contribute to keeping rates low for native system customers. Any limitations on mark et participation will impact revenues.

Specific issues of concern to MPW are:

 Installation of any air polluti on 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, reve nues from supplying e nergy to the market will not be received. The result is that MPW not only incurs the co st 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 im plications of t he poor economy.

 Timing of a new rule will affect the duration and timing of control equipm ent 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 re sult of numerous generating units being affected by the rule. Economics dictates that vendors and contractors will serv e large utilities first. Therefore small entities may not be able to meet a regulatory deadline and would need to cease operating their unit(s) unt il controls can be installed. This situation places another financial burden small entities.

 Financing control equipment can add to the financ ial burden of the utilit y 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 variabilit y 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 f ound in HAP emissions from an individual source. Even within a subcategor y, variability in HAP emission s occurs. For example, we observed one of three stack test runs for Hg t hat 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 Page 1 of 2

1/6/2011 file://C:\Documents and Settin g s\mbarch\Local Settin g s\Tem p \notesFCBCEE\~web2178.htmsmall community. These industries contribute to local air qualit y issues. Specifically, more stringent NAAQS for PM 2.5 , SO 2 , NOx and probably 0 3 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 p anel and hopes that EPA gives serious consideration to the concerns expressed by small entities. We also belie ve that an additional meeti ng or meetings of the SER
Panel would be beneficial after EPA devel ops 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)

____________________________________________ This message contains information for use only by th e intended recipient and may be legally privileged, confidential, and/or exempt from disclosure. If you received this message in error, notify the sender immediately and permanently delete this message . Any unauthorized review, use, disclosure or distribution is strictly prohibited. Unle ss explicitly stated otherwise, this e-mail is not a contract offer, amendment, nor acceptance. Page 2 of 2

1/6/2011 file://C:\Documents and Settin g s\mbarch\Local Settin g s\Tem p \notesFCBCEE\~web2178.htm1 

## 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

SO 2 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

allowances2 SO 2 %

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 SO 2 , Two NOx, Four CO 2 , 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. CO 2 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 SO 2 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 SO 2 standard. EPA has declared the state SIP for PM 2.5 to be deficient for the

Muscatine area. Any new project affecting NO 2 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.

12/16/10EPA Utility MACT Small Ent ity 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,
A ttached are comments submitted by San Miguel regarding EPA ’s review panel for the El ectric Generating Unit Hazardous Air Emissions Rulemaking. Thanks for the opp ortunity to comment on this very important rule.

Please don’t hesitate to let me know if y ou have questions or need additional information.

Joseph Eutizi San Miguel Electric Cooperative
830-784-3411 ext. 226 j eutizi@smeci.net

This e-mail message, including any attachments, is for the sole use of the intended recipient(s) and may contain confidential and privileged information. Any unauthorized review, use, disclosur e or distribution is prohibited. If you are not the intended recipient, please contact the sender by reply e-mail and destroy all copies of the original

message. Page 1 of 1

1/6/2011 file://C:\Documents and Settin g s\mbarch\Local Settin g s\Tem p \notesFCBCEE\~web7947.htmMadelyn 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 serveapproximately 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 subcat egorization 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 alsocommented 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 ra nk under Section 112 MACT standards was recognized by the EPA in its 2004 Utility Mercury Reductions Rule (UMRR) proposed MACT alternative. The additional subcategori zation 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 variabilit y, 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 bevying 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 notificati on of the SERs to the Panel meeting was two weeks (which included Thanksgiving ho liday). 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 EntitiesThis 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 CA IR 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 requireme nts 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 th e ICR but did indicate we would supply electronic records if requested. San Migue l’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/con cerns 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 y our 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 requirement s 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.netComments 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@a ppanet.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). Page 1 of 1

1/6/2011 file://C:\Documents and Settin g s\mbarch\Local Settin g s\Tem p \notesFCBCEE\~web9820.htmComments 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 Page 1 of 1

1/6/2011 file://C:\Documents and Settin g s\mbarch\Local Settin g s\Tem p \notesFCBCEE\~web4184.htmDecember 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 info rmation 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 mess age that any MACT standard that would require the installation of additional emissions control equipmen t 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 likel y be scarce, in the event these Small Entities have to compete for the same resources as the larger ut ilities, assuming they will al so 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 larg e number of comments opposed to (1) the quality of the test data used to set the proposed emission standar ds and (2) the “cherry picking” of the lowest emission rates on a pollutant by pollu tant basis without regard for t he combustion interrelationships between some of the regulated pollutant s. 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 organiz ed, comprehensive effort to regulate multiple pollutants from combustion sources. The current hap-hazard approach us ed by USEPA to regulate pollutants from combustion sources is technically fl awed 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) em issions data base is re-evaluated by experienced combustion professionals, to avoid the technica l deficiencies noted in the Boiler MACT comments received during Y2010. USEPA should immediately r equest 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 ut ility 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 inte grity of the Grid, the national economy and national security

To propose a Utility MACT standard without considerati on 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 Page 1 of 1

1/6/2011 file://C:\Documents and Settin g s\mbarch\Local Settin g s\Tem p \notesFCBCEE\~web3372.htmMunicipal 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 EP A’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 Co mpany, 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 in itially provided street lighting. In 1896, the municipal electric utility began serving retail and b ecame a Department of the City of Wyandotte. Today that Department is known as Wyandotte M unicipal 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 ofnearly 2,000 public power systems in the United States. It serves 12,939 consumers, has $36 million in annual revenues, and sold 282 milli on 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-me gawatt interconnection with Detroit Edison's 40,000-volt transmission system, and a 98-mega watt interconnection with Detroit Edison's 120,000-volt transmission system.

The municipal power plant consists of three bo ilers 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. Ab out 26,000 tons of TDF (the equivalent of 3.5 million scrap tires) were consumed at the Wyando tte municipal power plant in 2006. In addition to supplying over 90% of all the electricity n eed 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 provi des 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 E GU 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 process 1 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 h as 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 requir ements or timetables that take into account the resources available to small entities, and the clar ification, consolidation, or simplification of compliance and reporting requirements for small entities. 4 This SER meeting involved no preparation and distribution of these clarificatio ns, 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 inv ited to participate. Those included the Clean Water Act Section 316 (b) coo ling water intake structures/entrainment and impingement of aquatic organisms, the ICI Boiler MACT rulema king in 2003 (for <25 MW utilities) and others held in the last ten years where the WMS has b een 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 CO 2 would be regulated and the cascade of regulatory actions following the CO 2 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 preparat ion 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 pa nel meetings be held following a better staff review of the data and that small entities (i ncluding 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 sco pe 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 comment s by panel participants, EPA nevertheless propounds six slides of questions for those entities. Many of t hose 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 hea lth finding before EPA can regulate EGUs under § 112, EPA’s December 2000 regulatory determinat ion 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 performi ng” in setting the MACT floor for the first HAP,
and establishes the next MACT floor based on a di fferent 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 un it that does not exist in the real world. Section 112(d)(3) of the CAA expressly requi res 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, f acility, 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 sour ce 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-po llutant 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 exam ple, the production of Carbon Monoxide (CO) during the combustion process in an EGU boiler is inversely related to NO

x production. If EPA were to set a surrogate CO li mit for organic emissions, plants could not meet that limit if they were also required to minimize its NO

x emissions.

3. Although the SBREFA SER panel did discuss Subcategorization, the discussions of Subcategorization were inad equate 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 setti ng MACT limits. In the presentation material,

8 This is another example of why this small busines s 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 mercur y emissions hinges on the factual adequacy of its December 2000 regulatory determina tion. 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 c oncepts 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 subcategor ization 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 th at an emission limit is set at a level the best performing source(s) will not violate, EPA must as sess 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 th e 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 emi ssions 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 indicativ e 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 id entify three sources of variabilit y 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) perform ance 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 questio n. 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 ad justments 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 E GU ICR were at or below method detection and method quantitation limits. In addition, de tection 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 a nd non-dioxin organics measurements from ICRtesting 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 wher e it is not feasible to prescribe or enforce an
emission standard. It is not feasible to enforce an emission lim it 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 det ection 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. Secti on 112(d)(4) allows EPA to set health-based limits
for certain HAPs based on established health th resholds as an alternative to promulgating technology based limits under § 112(d)(3). S ection 112(d)(4) applies to non-carcinogenic HAPs 10

for which EPA has established a health threshold such as a reference concentration (“RfC”) or a reference dose (“RfD”). EPA defines a referenc e concentration in its IRIS database as “[a]n estimate (with uncertainty spanning perhaps an or der of magnitude) of a continuous inhalation exposure to the human population (including sensitiv e 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”, partic ularly 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 orig inal § 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 w ith 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 entitie s. Federal agencies are encouraged to find ways to lessen the impact of monitoring and r ecordkeeping requirements on those entities. Small entities do not possess the monetary resources, manpower, or technical expertise needed to operate cutting-edge monitoring techniques su ch as mercury and PM CEMs. EPA should develop more limited monitoring requiremen ts 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 b een 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 th e 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 ma nagement 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 lo w HAP emissions. Others employ combustion processes ( e.g. fluidized bed technology) or ha ve 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 MA CT 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 f ace 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 sour ces 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 sour ces 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 we re subject to the uni que 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 exempt ion 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 th eir 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 qua lify 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 fundi ng 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 sm all entities additional time to comply with
the EGU MACT rule.



### Conclusion

While WMS appreciates being invited to atte nd 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) aft er the EPA has more thoroughly evaluated the sampling data and outlined several technica l options and regulatory alternatives. These regulatory alternatives should include subcat egorization and GACT controls and area source controls amongst other options. Any regulatory options to re duce 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: 734-324-7114Utility MACT Small Busine ss Review Panel - Comments Cornwell, Laura

to: RobertJ Wayland, Mary Johnson, Made line 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

1/6/2011 file://C:\Documents and Settin g s\mbarch\Local Settin g s\Tem p \notesFCBCEE\~web9760.htm- 1

-

Small Business Review Panel for EPA‟s Rulemaking for Hazardous Air Pollutant Emissions

from Coal

- and O i l

- 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” system s, 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 wi th 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 genera ted 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 t he 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 allocation s. These regulations will also be amidst a series of tighter ozone, PM 2.5, SO 2 , NOx, and the new regulations for NSPS for Greenhouse gases (including CO 2 , methane

, and

SF 6 ). Additionally

, many power plants will face tighter controls for various water pol lutants 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 Cont rol 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 coa l) be thorough, thoughtful and valuable to the EPA,

OMB and to the industry that SBREFA is designed to affect.- 3

-- 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 f r o m coal

and oil

- fired electric u tility 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.

Th e EGU MACT rulemaking has the potential to b e one of the most expensive

rulemaking s 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 th e statute, EPA must carefully consider the impact its EGU

MACT rule will have on small entities and must act to lessen the burden of th at rule on those

entities.

The Small Bus iness 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 process 1

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 panel s 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 resou rces 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

si mplifications 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 th is particular small business review panel that has been

established for th e EGU MACT rule prevent s small APPA members from having the meaningful

advisory role conte mplated 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 T he

materials pr ovided by EPA just prior to the only panel meeting a re 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 wate r 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 CO 2 would be regulated and the cascade of regulatory actions following the

CO 2 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 requir ed 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 material s did not include possible rulemaking

alternatives nor any information about possible compliance or reporting options

. Moreover, the

material lack ed any results of EPA‟s analys e s 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 con sent 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 an d 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 t hat 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 me mbers, then a much longer comment period should be provided.- 6

-

collection request (ICR ) that EPA identified as being criti c al to the promulgati o n of a n EGU

MACT rule . As a result of the poor and inad equate preparation by the U. S. EPA and

failing to meet the statutory requirements, APPA can offer only ge ne r al comments on EGU

MACT rule making 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 reach e s that

point in its r ulemaking process. APPA would be pleased to participate in that process

.

General Comments on the EGU MACT Rule making

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 unique ly und er § 112 of the Clean Air Ac t (CAA ). Section 112(n)(1)(A)

requires EPA to study the hazards to public health reasonably anticipated to occur as a result of

emission s from EGUs “after the imposition of the other requirements of the CAA. ” After

considering the results of th at study

, the EPA Administrator must then decide if further

regulation is “ appropriate and necessary.” EPA completed the EPA Utility Study in February

1998

. I n December 2000

, the EPA Administrator found that regulation of coal

- and oil

- fired

EGUs was appropriate and necessary und er § 112 and proceeded to list those units under

§ 112(c). 8 EPA‟s notice of regulatory finding focused solely on the risk s to public health posed

by mercury emissions from coal

- fired power plants. Because § 112(n)(1)(A) requires a predic ate

health finding before EPA can regulate EGUs under § 112, EPA‟s December 2000 regulatory

determination only g a ve 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 len gths 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 rem oval of EGUs from the list of

§ 112(c) source categories in State of New Jersey v. EPA , 517 F.3d 574 (2008), avoided

address ing 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

- fire d 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

- by

pollutant 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 hyp othetical, 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

controll ed 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). Se ction 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. T he 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 hinge s 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 § 11 1 (a)(3).

These statutory provisions reveal a clear congressional intent that MACT floors must b e
based on the actual performance of an actual source or sources. These statutory provisions do

not allow MACT floors to be set on the bas is o f a hypothetical, ideal units nor do they allow the

“emissions control” achieved by the best sources to be determ ined 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 effec ts 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 NO

x production. I f

EPA were to set a surrogate CO limit for organic e missions, plant s could not meet th at limit i f

they were also required to minimize its NO

x emissions.

3. Although the SBREFA SER panel did discuss Subcategorization, the discussions of

Subcategorization were inadequate and overly brief.

For a source cate gory 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” i n setting MACT limits. In the

presentatio n 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 can not provide more specific comments because of the lack of

any analys e s of the ICR data

. However, APPA hopes to i dentify 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 achi eved 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 t hat 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 , 25 5 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 b y 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 variabilit y 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 p resentation 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 appl y a UPL to the specific fact s 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 proposi ng 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 limit s

. In addition, d etection limit information was in consistently

reported by ICR t est contractors. How E PA 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 th o se 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 c ompliance 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 dete ction 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

HAP s 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 assu mes 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 unce rtainty 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 o f 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 t hat 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 require ments 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 nee ded 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 alterna tives 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
“gen erally 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 risk s posed by HAP emissions from area sources w er e 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 relati vely 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 th e 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 shou ld 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 Entitie s 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 exten sions 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 distingu ish 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 l imit 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.

M unicipal 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 craftsme n 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 c an be installe d with in 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 m e mbers that qualify as small entities serve smaller communities

that do not have large sums of money on hand to pay for extensive plant addit i ons. Most

municipals will need to seek external funding before beginning any design or construction

activit i es

. Some municipal power pl ants are also located very close to the population they serve.

Those plants face space constraints that will prevent them f rom installing additional control

equipment.

For all these reasons, EPA should provide small entities addit i onal time to comply wit h

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 altern atives 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 reliabilit y impacts to all of the various EPA regulations hitting the utility sector from 2013

-

2020 that are be st 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 thorough ly

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 re duce

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

.

T hank you. For further contact at APPA:

Theresa Pugh

Director

Environmental Services

APPA

202 467 2943 tpugh@publicpower.org or tpugh@appanet.orgEGU MACT SER Revi ew Panel Comments Wemhoff, Bill G.

to: Madeline Barch
12/15/2010 03:12 PM
Cc: Cortney_Higgins, david.rostker, RobertJ Wayland, Ma ry Johnson, "Johnson, Joseph", Mike Thatcher, rex.butler, lhopkins, jeutizi
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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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contact the sender b y repl y e-mail and destro y all copies of the ori g inal messa g e. Page 1 of 1 EGU MACT SER Revi ew Panel Comments

1/6/2011 file://C:\Documents and Settin g s\mbarch\Local Settin g s\Tem p \notesFCBCEE\~web1739.htm1 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 appr eciate the opportunity to participate in

the small business review panel regarding EP A’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 achie vable control technology (“MACT”)

provisions.

Below is a discussion of the many potential issues that cooperatives have expressed

concern regarding the agency’s EGU MACT rule making. Many of these issues were raised

during our meeting on December 2 and ar e described in mo re 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 re view 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 certain ly fall far short of what was intended by

Congress when it passed the Small Busine ss Regulatory Enforcement Fairness Act

(“SBREFA”).

Furthermore, EPA has not provided rule alternatives or sufficient data and

information in a useable form that would al low small entities to assess the potential

impact of this rulemaking. They, therefore, are limited in thei r ability to provide2 meaningful input on critical issues that could help shape the fi nal rule in a way that would

minimize the impact on small entities.

In addition, cooperatives ar e concerned that EPA’s evaluation of the potential

impacts of this rulemaking on small entitie s 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 underes timate 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 a ttachment “A” hereto.

Finally, in its assessment, cooperativ es believe EPA should consider the

synergistic adverse impacts th at this rule will have on sm all 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 consume r-owners have household incomes about 14

percent less than the U.S. average and use mo re electricity, as a percent, when compared

to residential consumers served by invest or owned utilities an d municipalities.

Furthermore, because of the special challeng es that cooperatives face, cooperative rates

are already slightly higher than neighboring utilities. The consequence is that

rulemakings resulting in increa sed costs of coal-based electri c power, particularly in rural

areas served by cooperatives, will have si gnificant negative impacts on rural consumer

owners, economic development and jobs. Included in appendix “B” is additional

information describing some of the unique challenges f acing cooperatives.

General Concerns Regarding the Pote ntial Form of an EGU MACT Rule

EPA’s final rule should be limited to me rcury (“Hg”) control only. The agency

has not determined that emissions of othe r hazardous air polluta nts in the quantities

emitted, are detrimental to human health or the environment. In 2004, when EPA3 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 th e HAP emission standards for industrial,

commercial, and institutional boilers and process heaters 2 (“Ind. Boiler”) rule.

Cooperatives believe that EPA’s methodology is flawed and fundamental data issues

exist that compromise the va lidity of the proposed standard s. 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 identi fied many issues of

concern. Those comments have been include d as appendix “C”, hereto. In addition,

below is a listing of the major issues th at were raised in those comments.

 The Section 112 MACT standard must re flect 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 Standard s for Hazardous Air Pollutants; a nd, in the Altern ative, 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 expl ains 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 inconsis tent with these requirements.

 A MACT rule must address in a reasone d 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 la ter during compliance demonstrations.

CAA Section 112(h) provides that if it is not feasible to pres cribe or enforce an

emission standard for control of a HAP po llutant, the Administrator may, in lieu

thereof, promulgate a design, equipment, work practice, or operational standard.

Electric cooperatives urge EPA to prom ulgate work practic e 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 standa rds 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 variabil ity 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 s ubcategorization 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 disc retion to create subcategories,

Section 112(d)(1) does not restrict subcategorization to cases where the “class,”

“type” or “size” factors affect HAP emi ssions. The provision merely requires

EPA to establish regulations for each categ ory or subcategory on the schedules set

out in Section 112. Indeed, EPA has not previously subcategorized under

Section 111 based solely on emission eff ects. 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 subc ategorization 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 recognizi ng the differences in the characteristics

of the Gulf Coast lignite and the No rth Dakota lignite. These coals have

significantly different compos ition 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 th at were tested in that

category or subcategory. The CAA requires EPA to set MACT limits for existing

sources based on “the average emissi ons limitation achieved by the best

performing 12 percent of the existing s ources (for which the Administrator has

emission information).” For source categor ies with less than 30 sources, existing

source MACT floors are to be set base d on “the average emission limitation

achieved by the best performing five sources (for which the Administrator has or6 could reasonably obtain emissions informa tion).” 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 I CR 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 achiev e 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 operati ons can be achieved. During start-up, not

all pieces of control equipment will be opera ting at peak efficiency. Cooperatives

believe work practice standards are far more appropriate during these periods.

Similarly, for the same reasons, work pract ice 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 possibl e. At this preliminary stage in the

rulemaking process, however, and havi ng 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 recommenda tions 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 not7 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 th e mine. Also, many power plants purchase

coal from more than one mine becau se of market-based cost and other

considerations. In additi on, many times coal from vari ous sources is blended, and

in some cases, even different coal type s are combined in varying amounts for use

in a single generating unit. For all thes e reasons, the option of a percent reduction

compliance method may be the most r easonable alternative to achieving the

desired emission reductions while helpi ng to minimize any unnecessary costs of

compliance. In other instances, emission limits may be less burdensome.

Cooperatives believe that the source s hould be allowed to make the decision

regarding which option to use.

 Health-based emission limits under Sec tion 112(d)(4) should be used to the

maximum extent possible. Section 1 12(d)(4) is designed to prevent the

promulgation of unduly stringent emissi on 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 Secti on 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 c oncentration in its IRIS

database as “[a]n estimate (with uncer tainty spanning perh aps an order of

magnitude) of a continuous inhala tion 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,” partic ularly given the uncer tainty factors that

EPA includes as part of its derivation of an RfC.

4 The definition for a reference dose is essentially th e same except it focuses exposure by pathways other
than inhalation.8 Section 112(d)(4)’s inclusion in th e 1990 CAA Amendments indicates a

Congressional intent to reta in the health endpoint of the original Section 112 --

protection of public health with an ample ma rgin of safety. If the emissions of a

given HAP from all sources in a source cate gory are at a level where public health

is protected with an ample margin of safe ty, then there is no practical need for or

benefit from further regulation. Cooperati ves 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 so urce” 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 t echnologies 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 s ources and that less stringent emission

standards were, therefor e, appropriate. Many EGUs owned by cooperatives

qualify as area sources because they have control equipment installed or for other

reasons.

EPA should exercise its di scretion, 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 less ening the regulatory

burdens on small entities.

Cooperatives are also concer ned that specific units subj ect 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 pract ical alternative to meeting new emission

limits. For example, units with mine-mouth operation and having a lack of

transportation infrastructure may have no opti on 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. Cooperativ es believe that the potential

negative impacts on small entities must be co nsidered if the agency sets EGU MACT

limits at levels that may require fuel switc hing. 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 or der to account for their disadvantage in

competing for equipment and skilled la bor resources in a severely tight

compliance timeframe. The el ectric 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 un its and if stringent emission limits are

imposed by an EGU MACT rule, utilities across the country will scramble to

secure the equipment, contractors and sk illed craftsmen needed to install the

needed new control equipment. Large uti lities have leverage to get their plans

retrofitted first. Small c ooperatives will find themselves at the end of a long line,

making it highly unlikely that the new cont rol equipment can be installed within

three years. We strongly believe that the compliance deadline for small entities10 must be extended. Without specific co mpliance requirements to review, however,

we cannot determine with specificity how much of an extensi on will be required.

Similarly, specific units may not have th e physical space to add the required

controls equipment. Consideration mu st 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 rema in 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 incons istent with the stated goals of SBREFA

to encourage the “effective pa rticipation” of small busine ss in the federal regulatory

process 6 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 pa nel 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 signi ficant alternatives to the pr oposed rule, differing compliance

or reporting requirements or timetables that ta ke into account the resources available to

small entities, and the clarif ication, consolidation, or si mplification 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 m eaningfully in the small busin ess 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 th e above, or need additional information,

please do not hesitate to contac t any one of the undersigned c ooperative 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.coopIOU

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% 64% 65% 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 meanswithout explicit permissionAmerica’s Electric Cooperative NetworkAmerica SamoaA-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 potentia lly 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 (“SB A”) standards and did not recognize the

relationship between G&Ts a nd distribution cooperatives.

Eighty percent of the electric power gene rated by cooperatives comes from coalfired units. NRECA’s 66 rural el ectric 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” unde r the SBA size standards. 559 distribution

cooperatives receive their elec tricity 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 di stribution cooperatives

are owned by the consumers to whom they provide electricity. In fact, the Board of

Directors for any given G&T c ooperative is made up of either a member of the board or

chief executive officer from each distribution co operative that has an ownership stake in

the G&T.

1 The vast majority of NRECA’s members m eet the definition of “small” under the Small Business Regulatory Enforcement Fairness Ac t (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” a dopted by the Small Business Administration (SBA). The SBA’s small business size regu lations 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 id entified 14 electric c ooperatives nationwide

that will be affected and that meet the SBA’s small business st andards. Of those

identified, however, NRECA suggests that EPA’ s list includes some c ooperatives that are

larger than the SBA size standards and omits ot hers that do meet the standards. Listed

below are 14 coal burning G&Ts that NR ECA believes should be included in any

analysis of the impacts of the EGU MA CT 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 th e 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 ex tent 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 sharehol ders who could help share these costs. And

because the relationship between the distri bution cooperative and th eir G&T is governed

by an “All Requirements” contract, the di stribution 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 “r esidential, commercial, industrial, and

transportation sector economic demand for ( i.e. , consumption of) electri city is relatively

price inelastic, which suggests that electri c utility plants may succeed in passing through

most or all regulatory costs to their electric ity 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 distri bution cooperatives receive from the G&Ts.

Neither does the concept of “rate hike peti tions to public utility commissions” readily

transfer to the coope rative business model. G&T coopera tives deliver power to their

members at cost-based rates determined by th e Boards of the G&T, and the Boards are

made up by representatives of the distribution cooperative s that own the G&T. AllA-3 additional costs borne by the cooperative (a nd paid for by the di stribution cooperative

member-owners) affect the financial well- being of the G&T coope rative, rendering the

discussion of a cost pass-through a moot issu e for our members. The notion that “passing

through” regulatory compliance costs to cust omers will somehow avoid or mitigate their

impact does not apply to consumer-owned c ooperatives. 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 a nd may have to sacrifice other necessities.

Furthermore, increasing cost of power ha s significant negativ e impacts on economic

development and jobs in de pressed 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 CooperativeNRECA 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 t he states in which they operate

 established to provide at-cost electric service

 governed by a board of directors elected fro m 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., sm all business development, jobs creat ion, 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, churc hes, 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 t he nation’s electric distribution lines, covering three quarters of the nation's landmass

 deliver 10 percent of the total kilowa tt-hours sold in the U.S. each year

 generate nearly 5 percent of the total electricity produc ed 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 cu stomers per mile of line and colle ct $62,665 per mile of line

 Publicly owned utilities, or municipals, average 46.6 consumers and collect $86,302 per mile of lineNRECA 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 Standa rds for Major Sources: Industrial, Commercial, a nd Institutional Boilers and Process Heaters; Proposed Rule

75 Fed. Reg. 3200 6 (June 4, 2010)

Submitted Electronically to:
The Environmental Protec tion 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 A ssociation (“NRECA”) offers the following

comments on the U.S. Environmental Protection Ag ency’s (“EPA” or “Agency”) Proposed Rule:

National Emission Standards for Major Sources; I ndustrial, Commercial, a nd 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 elec tric cooperatives account for approximately 11

percent of all electric energy sold in th e United States. NRECA members generate

approximately 50 percent of the electric energy th ey sell and purchase the remaining 50 percent

from non-NRECA members. The vast major ity of NRECA members are not-for profit,

consumer-owned cooperatives. NRECA’s memb ers also include approximately 66 generation

and transmission (“G&T”) cooperatives, which ge nerate 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 ot her generation sources within

the electric utility sector. Both distribution and G&T c ooperatives were formed to provide

reliable electric service to their owner-mem bers at the lowest reasonable cost.

NRECA’s members and their consumer-owner s 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 informati on 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 co ntrol emissions from these sources using the

approach as proposed will result in increased cost s that cooperatives, being not-for-profit, will be

forced to pass along to their consumer-owners. In creased costs of electric power, particularly in

rural areas served by cooperatives, have negati ve impacts on economic development and jobs.

1 75 Fed. Reg . 32006 (June 4, 2010)- 3 - NRECA urges the agency to include in its consider ation 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 th is 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 stringe nt than needed to assure

protection of public health and the environmen t from industrial boiler hazardous air pollutant

(“HAP”) emissions. As explained below, EPA’s approach to setti ng the standards is flawed and

fundamental data issues exist that compromi se the validity of the proposed standards.

NRECA also believes that EPA has both the n eed and the opportunity to make significant

changes to the proposed standards. The agen cy has the legal discre tion and the technical

justification to substantially reduce the burde n of the standards while still providing ample

protection. NRECA provides reco mmendations in that regard in several key areas below.

Section 112 Standards Must Reflect the Emission s Control Achieved by Actual Units, Not Hypothetical Composite Ones

The proposed Ind. Boiler MACT limits were de rived 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 3 to determine the MACT floor for a given HAP. EPA then

directs its attention to the ne xt HAP, ignoring those units it ju st 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 electri c 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 exis t 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 performa nce 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 sour ces to be determined using a pollutant-by-pollutant approach

on a shifting group of best performing units.

NRECA believes EPA’s standard-setting appr oach 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 MA CT 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 MA CT 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 s ource with the lowest HCl emissions. Likewise,

the source with the lowest mercury (“Hg”) emi ssions had PM emissions 10 times greater than the

best performing PM unit and 146 times highe r than the best performing HCl unit.

EPA’s approach for setting MACT floors in th e 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 th e 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 Re asoned Manner HAP Emissions That Are At or
Below the Method Detection Limit

EPA‘s effort to set emission limits for al l HAPs emitted by industrial boilers is greatly

complicated by the fact than a number of HAPs ar e 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 “quant itation limit.” The detection limit defines the

threshold below which a test method cannot distingui sh whether a substance is present or not. In

EPA’s prior efforts to implement the Clean Wate r 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 an alyte concentration is gr eater than zero.” 40

CFR § 136.2(f). Stated differentl y, a measured value at the detection limit has an error band as

large as the value being reported. One does not have great confiden ce 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 bot h precision and bias, achieves

the objectives of the intended purpose of the me asurement. Target objectives are generally

stated in terms of the precision of the measurem ent expressed as a relative standard deviation

(“RSD”). There is no single agreed approach fo r 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 factor s such as matrix e ffects and purity of

reagents. One does not have confidence in the accu racy 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 un assailable in an enforcement action. Emission

limits must not be set below th e 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 definitio n of detection limit in the IB ICR. As a result, the detection

limits reported in the ICR responses are inc onsistent and are not even based on a common

understanding of the term “d etection 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 “r eported” 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 detec tion 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 labor atory to precisely measure the

amount of a substance in a given sample it rece ives. 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 interlab oratory inaccuracies of

different laboratories testing th e same sample. EPA’s proposed ru le 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 mu ltiplier of three to account for measurement

variability. While EPA’s suggested adjustment is a step in th e right direction, the remaining

uncertainty is too large and ther efore a larger multiplier is need ed. 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 pr ior 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 ag reed to in the IB

MACT rulemaking has resulted in obvious and mu ltiple 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 describe s in its comments, even a cursor y review of the IB MACT data

by its consultant has revealed se veral important problems with EP A’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 need s to conduct a thorough quality assurance review

of the IB ICR data and only after th at review repropose IB MACT limits.

The lesson for the upcoming EGU MACT rule making 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 dete rmined MACT floors based on a variability

adjustment using an upper prediction limit (“UP L”). EPA’s UPL equation attempts to identify

an interval that will, with a specified degree of confidence, c ontain the next randomly selected

observation from the population dist ribution. In theory, EPA’s sta tistical analysis is reasonable

provided the mean and standard devi ations are computed from a dist ribution of values that reflect

all operating conditions. Unfortunately for IB s, 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 shor t-term (snapshot) tests. Thr ee 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. Actu al emissions variability for the best performing

unit(s) results from a variety of factors, incl uding different plant opera ting conditions, different

control equipment settings, and diffe rent 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 99 th percentile

performance of a given unit if the emissions data from three days of test ing of that unit are not

representative of all the unit’s operating condi tions over an extended period of operation. The

three ICR test runs for each boiler were perf ormed 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 we ll as they did durin g the ICR testing.

The lesson for future MACT rulemakings is th at if EPA fails to obt ain 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 circ umstances. 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 Ad ministrator to disti nguish 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. Th e provision merely requires EPA to establish

regulations for each category or subcategory on th e schedules set out in § 112. Indeed, EPA has

not previously subcategorized under § 111 based solely on emissi on effects. For example, under

§ 111 EPA has subcategorized boilers on the basis of size (heat i nput) or the type of fuel burned

(coal, oil or gas). These sub categorization decisions were ba sed on feasibility and/or cost

considerations, not on th e level of emissions.

NRECA commends EPA for creating a large numb er of subcategories in the proposed IB

MACT rule. However, NRECA believes EPA shoul d have created even more subcategories.- 9 - Historical testing has shown th at coal rank has a significant e ffect on Hg and HCl emissions.

Also, as discussed below, a limited use subcateg ory should be created fo r IBs that are operated

infrequently because of their specialized nature and use.

EPA Should Use Section 112(d)(4) Whenever A ppropriate in Settin g Emission Limits

EPA has requested comments on whether it shou ld 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 hea lth-based limits for certain HAPs based on established health

thresholds, rather than having to follow the t echnology forcing provisions of § 112(d)(3). As a

practical matter, § 112(d)(4) applies to non-carci nogenic HAP for which EPA has established a

health threshold such as a reference concen tration (“RfC”) or a reference dose (“RfD”). EPA

defines a reference concentration in its IRIS database as “[a]n es timate (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 apprec iable risk of deleterious effects

during a lifetime.” 4 Thus, human exposures to a HAP at leve ls below its RfC are considered “safe,”

particularly given the uncertainty factors that EPA includes as pa rt 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 endpoi nt of the original § 112 -- protec tion 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 wi th an ample margin of safety, then there is no

practical need for or benefit from further regul ation. 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 Achiev ed by No Fewer Than Five
Units

In the proposed IB MACT rule, EPA has base d the MACT floor for certain subcategories

on emissions data from less than five sources ev en though the subcategory contains more than 30

4 The definition for a reference dose is essent ially 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 performi ng” units in larger subcategories (more than 30

units) when only limited emissions data ar e available. NRECA believes it should.

The CAA requires EPA to set MACT limits fo r existing sources based on “the average

emissions limitation achieved by the best perfor ming 12 percent of the existing sources (for

which the Administrator has emission informati on).” For source categories with less than 30

sources, existing source MACT fl oors are to be set based on “the average emission limitation

achieved by the best performing 5 sources (for wh ich the Administrator has or could reasonably

obtain emissions information).” NRECA believe s these two provisions in dicate 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 contem plated the situation were the am ount of available data from a

large source category or subcategory would re quire 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 duri ng start-up, shutdown a nd 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 lim its during these events. For

example, operations during boiler start-ups are di fferent than normal plan t 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 a ll pieces of control equipment will be operating

at peak efficiency. NRECA believes work prac tices standards are far more appropriate during

these periods. Similarly, for the same reasons, work practice standards ar e also more appropriate

for shutdown and malfunction events.

If EPA insists, however, on setting emission lim its 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 potenti al for enforcement of operating parameter

and opacity limits during peri ods of startup, shutdown, and in the event of equipment

malfunction. When EPA finalized its rule in 2004 with enforceable operating parameters, it did- 11 - so with a rule that also made clear that t hose 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 cont rols would not be expected to be operating

at the same levels as during performance tests, and due solely to equipm ent malfunctions. In its

proposed rule, EPA asserts that it has taken startup and shutdown periods into account by using

continuous emissions monitoring sy stem (“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 asserti ons regarding startup and sh utdown 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 aver age, as proposed for opacity, does not provide

sufficient protection if the unit does not startup or shutdown at exactly midn ight, since there might

not be sufficient data under normal operating conditi ons to compensate for the startup or shutdown

period. In short, NRECA believes EPA has not ma de 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 start up and shutdown. NRECA thinks EPA’s proposal is unreasonable

and the agency must address thes e periods by allowing sources to identify alternative parameters

or by establishing simple work prac tice standards for these periods.

EPA’s promise to address periods of e quipment malfunction by considering other

information before enforcing exceedance of operating limits also provides little comfort,

especially given the risk of c itizen suits. Although NRECA appr eciates EPA’s proposal to make

clear that “deviations” of operating limits are not necessarily violations, nothing in EPA’s

proposal would prevent EPA, a stat e, or a plaintiff in a citizen suit from simply determining in

their “discretion” that any part icular exceedance constitutes a violation. MACT standards are

technology-based standards, and NRECA believes th e agency must recognize that even the best

performing technology occasionally fails.- 12 - 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 opera tional 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 a pply a 10 percent “discount factor” on any source

seeking to average emissions across units at a fac ility. 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 wh ether sources can even comply w ith them using state-of-the-art

control equipment. By effectively lowering t hose standards further by 10 percent for sources

that average emissions, it makes an impossible situ ation 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 sa me 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 faci lity are the same. Th e 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 prepar e and the cap on unit emissions would not allow

any unit participating in the aver aging to have emission any highe r then it had on the effective

date of the proposed rule. If EPA is serious a bout providing operational fl exibility to facilities,

then it must make substantial revision s 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 en courage the combustion of biomass as

substitute fuel for coal or oil. The combusti on of biomass will become increasingly important to

utilities as renewable energy sta ndards are adopted by more states and are possibly applied to all

states as a result of federal mandates. The comb ustion of biomass has the beneficial effect of

conserving natural resources. Unfortunately, the stringent MA CT limits EPA has proposed for

IBs burning biomass will greatly inhibit th e combustion of biomass in the future.- 13 - The proposed biomass emission limits are excee dingly low because of errors in standardsetting discussed above. The PM limit for bi omass units does not account for fuel-related

variability. PM emissions are dire ctly 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 Standa rds for Utility Auxiliary Boilers and Expand the Practice to All Gas-Fired Units

Electric utilities that operate auxiliary boile rs 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 com bust 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 boi lers are subject to work practice standards

requiring an annual tune up. NREC A supports EPA’s decision to se t a work practice standard

for this group of gas-fired IBs. The HAP em issions 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 control ling emissions from these units dwarfs whatever

minute benefits may result.

This work practice standard should be extende d to IB units burning coal-derived gas.

Utilities are increasingly being asked to consid er constructing integrated gas combined cycle

(“IGCC”) units. These units include a coal gasifi er that produces gas for later combustion in a

gas turbine. The gas from an IGCC unit is clea ned 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 requi res oil-fired auxiliar y boilers to comply

with stringent emission limits and demonstr ate compliance with those limits by following

expensive monitoring requirements. The distin ction 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- 14 - gas-fired units. The limited use subcategory shou ld 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 re lief to owners of these sources.

Proposed Compliance Demonstration Provisions

EPA proposes several compliance demonstrat ion 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 re garding 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 UAR G’s comments, is concerned with EPA’s

proposed implementing rules. NRECA has concerns regarding the use of carbon

monoxide (“CO”) CEMS to make complia nce determinations at some of the

proposed emission limits, and has object ions to EPA’s proposed use of PM

CEMS.

 NRECA does not object to EPA’s general a pproach of using operating parameters

to assure compliance in between stack te sts. EPA has previously used this

approach in the Compliance Assuran ce Monitoring (CAM) rule to assure

continuous compliance with standards th at 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. NREC A also objects to several provisions

related to proposed bag leak detection sy stems 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- 15 - 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 pr operly and its performance has not

deteriorated. NRECA also supports EPA’s proposal fo r reduced periodic testing,

but objects to the restrictions EPA woul d impose. In addition, NRECA suggests

that EPA provide options for use of se veral 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 an alysis 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 mont hly fuel analysis for sources that

have not changed fuel type, or the agency ’s proposal regardi ng 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 ar e not sufficiently just ified and will impose

unreasonable costs. Specifically, NRECA objects to EPA’s proposed requirement to report using

the electronic reporting tool (“ER T”) and disagrees with EPA’s a ssertions regard ing the impact

of that requirement on reporting and on emission f actor development. As UARG notes in its

comments, while experience with the ERT has been limited, industr y nonetheless has identified a

number of shortcomings in the programs. Fu rthermore, use of ERT is burdensome (easily

adding 10-20 percent to the cost of compliance testing), requiring manua l inputting of significant

amounts of information much of which is not releva nt to performance test results. It also is

subject to significant performance issues, includi ng software crashes and shutdowns, inoperable

features (like report generation), an d inadequate identification of e rrors preventing data analysis.

In short, even if EPA can justify a requirement to report performance te st data electronically,

EPA cannot justify requiring sources to use this program.- 16 - The Recordkeeping and Reporting Pr ovisions Are Overly Burdensome

EPA’s proposal includes requirements for the tr acking of numerous data points, including

fuel consumption; operating hours, startups, shutdowns including dates and times; equipment

malfunctions including dates and times; numer ous operating parameters including dates and

times of deviations; CEMS, COMS, and CPMS ca libration and quality assu rance/quality control

data; CEMS, COMS and CPMS maintenance in formation; 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 pr oposal, 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 keepi ng as possible. The equipment costs alone for implementing an

automated (to the extent possible) data collect ion 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 th at EPA, in proposing its enforceable

operating limit approach, has adequately estimated or c onsidered the data ma nagement 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. Th e emission limits are far more st ringent 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 addr ess 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 ar e real questions regarding whether sources can- 17 - even comply with these low limits as well as how they will meet the requirements for

compliance demonstrations. Furthermore, NREC A has many concerns regarding the proposed

compliance demonstration provisions and beli eves 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 se t standards for biomassfired electric generating un its that do not impede th e construction of new units.

NRECA appreciates the opportunity to provi de 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.