APPA’s comments on

National Emission Standards for Hazardous Air Pollutants from Coal-and Oil-fired Electric Utility 

Steam Generating Units and Standards of Performance for Fossil-Fuel-Fired Electric Utility, 

Industrial-Commercial-Institutional, and Small Industrial-Commercial-Institutional Steam 

Generating Units

(NESHAP Proposal Also known as EGU MACT or Mercury HAPs Proposed Rule)

Docket Number EPA-HQ-OAR-2009-0234;

Docket Number EPA-HQ-OAR-2011-0044, RFL-9286-1

August 2, 2011
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Contents

About APPA .............................................................................................................................................5

Organization of these comments...............................................................................................................5

Introduction/Executive Summary .............................................................................................................6

Comments related to the requirements of Clean Air Act Section 112......................................................8

Comments related to the requirements of the Unfunded Mandates Reform Act (UMRA), the Small 

Business Regulatory Enforcement and Fairness Act (SBREFA), Executive Order 13563 (Improving 

Regulation and Regulatory Review), and Executive Order 13132 (Federalism)......................................8

EPA Has Failed to Meet the Requirements of the Unfunded Mandates Reform Act of 1995 (UMRA) and 

Executive Order 13563 and Executive Order 13132 of 1995. ....................................................................11

EPA has Underestimated the Impacts of the Proposed Rule on Smaller Utilities Despite SER Panel.......16

APPA urges U. S. EPA‘s final EGU MACT rule to contain <100 MW subcategory to minimize impacts 

to smaller units............................................................................................................................................17

Timing for Compliance Requires 77 Months for Public Power Utilities due to Governance Requirements 

and Financing of Projects............................................................................................................................20

Statutory and regulatory provisions........................................................................................................21

General compliance timing issues...........................................................................................................23

Compliance information related to public power utilities.......................................................................25

General conclusions and recommendations............................................................................................28

Time Constrained Feasibility: Why Categorized Extension for Governmentally Owned Utilities 

Is Justified..............................................................................................................................................29

APPA Believes U. S. EPA Has Provided a Flawed Regulatory Impact Analysis: .................................32

Comments related to general policy considerations................................................................................36

General Clean Air Act Section 111 Comments ......................................................................................40

APPA‘s General Comments on EGU MACT and NSPS Proposed Rule ...............................................40

APPA‘s Technical Comments on the Proposed Rules............................................................................52

I. Rulemaking Background .........................................................................................................................52
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II. The Clean Air Act ..................................................................................................................................52

III. General Policy Considerations..............................................................................................................53

IV. U. S. EPA‘s Proposed Particulate Matter NSPS (APPA defers to UARG on the legal analysis and 

policy comments on the NSPS.) .................................................................................................................53

A. Background ........................................................................................................................................53

1. New and reconstructed boilers. The current NSPS allows three ways to comply: .........................53

2. Modified boilers..............................................................................................................................54

B. U. S. EPA Should Rescind Its Proposal and Repropose its Defective NSPS Rule ............................54

C. U. S. EPA‘s Choice of Best Demonstrated Technology Is Contrary to Law.....................................54

D. U. S. EPA erred in not calculating correctly in settings its preferred Best Demonstrated Technology.

................................................................................................................................................................54

E. APPA agrees with UARG that the U. S. EPA‘s proposed NSPS is not achievable ...........................55

V. Proposed Revisions to SO2 NSPS..........................................................................................................56

A. Background ........................................................................................................................................56

B. APPA believes that the U. S. EPA should rescind its proposal and repropose its defective NSPS rule

................................................................................................................................................................56

C. EPA erred in not calculating a cost for its preferred Best Demonstrated Technology.......................57

D. The Proposed NSPS Are Not Achievable..........................................................................................57

VI. Proposed Revisions to NOx NSPS ........................................................................................................59

A. Background ........................................................................................................................................59

B. The Proposed NSPS Are Barely Achievable (Given Current Technologies) ....................................60

VII. U. S. EPA Should Use Gross Output, Not Net Output, to Set NSPS..................................................60

A. EPA requested comment on this issue with respect to new and reconstructed units. ........................61

B. APPA defers to UARG that separate units should not be penalized for parasitic power from the 

use of control technologies. ....................................................................................................................61

VIII. IGCC Units Should Continue To Be Regulated Under Subpart Da, Not Subpart KKKK.................62

IX. APPA endorses UARG‘s objection to adding petroleum coke to the definition of coal. .....................62
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XII. Monitoring Issues (testing compliance and maintenance)...................................................................63

XV. Oil-fired units in Alaska, Puerto Rico, American Samoa, and Guam require special considerations: 

APPA supports waiver for oil-fired units in Guam, Puerto Rico Hawaii and Alaska Oil Units.................74

XVII. Relationship between EGU MACT and Coal Ash/Coal Combustion Residuals Rulemaking .........74

Conclusions.................................................................................................................................................78

Appendices..................................................................................................................................................82

A. Development of Additional Subcategory for Electric Generating Units Less Than 100 MW........82

B. Payments and Contributions by Public Power Distribution Systems to State and Local 

Governments, 2008 Data ........................................................................................................................82

D. Unfunded Mandates Reform Act of 1995.......................................................................................82

E. APPA‘s Comments to U. S. EPA and SBA regarding EGU MACT (and pointing out the benefits 

of using GACT to reduce regulatory costs and burdens) – December 2, 2010.......................................82

G. The Feasibility of EPA‘s Proposed Utility HAP Compliance Requirements.................................82

H. Technical Report from UARG........................................................................................................82

I. UARG Request for MACT Comments Extension, May 6, 2011....................................................82

J. Neophytes Guide.............................................................................................................................82

K. Why New CO2 Regulations Could Produce Windfall Profits and Unproductive Costs for 

Consumers ..............................................................................................................................................82

L. Retire or Retrofit? A Look at U. S. Regional Scrubbed Coal Capacity, SNL Energy Data Dispatch 

Article, Feb. 24, 2011 .............................................................................................................................82

M. Implications of Greater Reliance on Natural Gas for Electricity Generation - APPA‘s Natural 

Gas Study................................................................................................................................................83

N. Current Capital Cost and Cost-Effectiveness of Power Plant Emissions Control Technologies by 

Ed Cichanowicz www.publicpower.org/files/PDFs/CichanowiczCostEffectiveness.pdf .....................83

O. Guam‘s Oil-Fired Capacity Units & Date of Installation ...............................................................83
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About APPA 

The American Public Power Association (APPA) is the national service organization representing the 

interests of the more than 2,000, not-for-profit municipal and other state and local community-owned 

electric utilities that collectively provide electricity to approximately 45 million Americans. These 

utilities, or ―public power‖ systems, are among the most diverse of the electric utility sectors, 

representing utilities in small, medium and large communities in 49 states (all but Hawaii). Seventy 

percent of public power systems are located in cities with populations of 10,000 or less. APPA was 

created in 1940 as a non-profit, non-partisan organization. Its purpose is to advance the public policy 

interests of its members and their consumers, and to provide member services to ensure adequate, 

reliable electricity at a reasonable price with the proper protection of the environment.

Overall, public power accounts for about 16% of all kilowatt-hour sales to retail electricity 

consumers. Approximately 46% of the megawatt hours of electricity produced by public power 

systems are generated using coal and more than 17% of MWH are generated using natural gas. This 

percentage of gas generation is growing since best practices for system stability dictate that the new 

intermittent resource capacity, such as wind and solar power be backed up at a 1:1 ratio by natural gas 

(mostly new Natural Gas Combined Cycle). In 2008, 27.7% of APPA member electric generating 

capacity (in Megawatts) and 46.4% of generation (in Megawatt-hours) was coal based. Less 

than 90% meet the SBREFA threshold. Figure 1 presents the national generation portfolio from 

public power for 2009. 

Organization of these comments

These comments are structured in the following manner:

 An introduction and executive summary

 Comments related to the requirements of Clean Air 

Act Section 112

 Comments related to the requirements of the 

Unfunded Mandates Reform Act (UMRA), the 

Small Business Regulatory Fairness Act (SBREFA), 

Executive Order 13563, and Executive Order 13132

 Comments related to general policy considerations

 Comments related to Clean Air Act Section 111

 Detailed general comments

 Detailed technical comments

 Appendices

Figure 1
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Introduction/Executive Summary 

Essential Corrections to EGU MACT Rule:

1) U. S. EPA should re-propose the rule and the final EGU MACT should not include acid gases or 

PM regulatory controls.

2) Public power utilities need more time for compliance for planning, public hearings, financing, 

procurement and construction so the U. S. EPA and the President should grant extensions.

3) U. S. EPA should provide more flexibility including subcategories for public power, electric coops, IOUs and merchant power. 

These subcategories include: 

- ≤100 MW for all types of utilities

- ≤30% capacity factor peaking units (limited use – mostly for renewables)

- NERC Reliability Standard CIP 002-4 units

- By fuel type

- Those utilities with physical space constraints

 APPA requested an extension to the comment period deadline and appreciated that the U. S. EPA 

granted that extension of one month to the comment period.

 In the rule preamble and the supporting technical documents, the U. S. EPA fails to provide any 

evidence of any risk to the general population from non-mercury metal HAPs and acid gases. 

APPA believes that it is appropriate to develop regulations under Section 112 for only the two 

hazardous air pollutants (mercury and nickel) for which EPA has provided evidence of a 

significant risk to the public. If EPA believes that non mercury metals and acid gases must be 

regulated, EPA should regulate these HAPs under a less onerous health-based standard. APPA 

believes that this action would be consistent with the call for control of hazardous air pollutants 

only where the U. S. EPA has determined there to be human health concerns. EPA‘s own study 

showed health concerns for only mercury (coal-fired generation) and nickel (oil-fired 

generation).

 APPA does not believe it unreasonable that the U. S. EPA should use its discretion to minimize 

the cost impact of this rule while still providing for the protection of public health. APPA 

believes that EPA should use its discretion in light of Executive Order 13563 (regulatory directive 

to minimize costs) to modify the proposed rule with a number of changes.

 U. S. EPA should eliminate the use of a ―Franken‖ Plant approach to establish a MACT standard 

for coal and oil-fired EGUs. Specifically, APPA believes that EPA should establish a MACT that 

is based on the actual performance of individual EGUs for all HAPs to be regulated. This change 

in the final rule would result in less compliance cost with little to no change in health benefits or 

impacts. 

 The proposed NSPS for SO2, PM, and NOx are, in practice, NOT achievable.

 APPA believes that the U. S. EPA should regulate mercury emissions from power production as 

necessary to reduce methyl mercury bioaccumulation in fish via air deposition. However, the 

U. S. EPA should regulate mercury from EGU‘s considering the comments herein, on matters 

such as subcategories, compliance schedules, and other factors. APPA does not presume that 

these reductions of mercury will affect any mercury transported from international sources of 

mercury including Asia and Mexico.
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 U. S. EPA should not expand the proposed utility toxic rule beyond mercury and nickel since in 

the preamble for the proposed rule EPA provided no data as to any health risks associated with 

non-mercury metal HAPS and acid gases related to fossil fuel-fired EGUs. Regulating these 

emissions would serve no purpose and would add cost without commensurate health benefits. In 

addition, EPA has not shown that the regulation of acid gases (HCl, etc.) and other air toxics is 

necessary and appropriate.

 In assessing costs to consumers, U. S. EPA should analyze the impact of the rule in wholesale 

electricity markets run by regional transmission organizations, particularly in forward capacity

markets.

 U. S. EPA should subcategorize and provide for the use of Generally Available Control 

Technology(s) (GACT) and management practices for area source utilities. U. S. EPA should 

also make GACT along with alternative work practice or operational standards available for 

municipal utilities and utilities that are physically constrained, such as those retrofitting with 

baghouses and scrubbers where the space needed to accommodate the addition of pollution 

controls is not adequate. APPA believes that the subcategory should address fuel types,

combustion processes, such as circulating fluidized boilers or pulverized over air-fired boilers,

physical constraints limiting the footprint of plants, and age of plants. APPA strongly endorses 

the ≤ 100 MW sub-category. This ≤100 MW subcategory should apply to all in the utility 

sector. See Appendix A

 U. S. EPA has grossly overestimated the health benefits of controlling Particulate Matter (PM) 

and should not consider these benefits since PM is to be controlled under the National Ambient 

Air Quality Standards (NAAQS) section of the Clean Air Act.

 U. S. EPA should use its discretion to regulate utility air toxics with a health-based emission 

standard, which would decrease costs without jeopardizing public health and safety.

 U. S. EPA should 1) enable the power sector, particularly public power utilities, to have 

additional compliance time beyond the standard three years in the Clean Air Act. 2) The U. S. 

EPA should provide extensions of one or two years each (as needed) as allowed under 

Presidential extension provisions (the Presidential extension should be delegated to the Governor 

of each state if the U. S. President desires). An extension is necessary to allow installation of 

pollution control equipment given time needed for planning compliance, timing and process for

obtaining financing for either pollution controls (scrubbers, baghouses, etc.) for EGU 

MACT/NSPS final rule or more time is needed for fuel switching to natural gas where the natural 

gas pipeline development and expansion projects must be financed, permitted and built by third 

parties to supply the utility plants that would use the natural gas. 

APPA does not assert that any additional time is needed to purchase or install the combined cycle 

gas turbines themselves as that technology is fully commercially demonstrated, available, and 

even available in international markets. However, even fuel switching or conversion from coalfired to natural gas may require permitting, financing and building of natural gas pipeline 

extensions, as well as natural gas storage permitting and construction. This is particularly true if 

a public power authority does not have power of eminent domain.
8

For some pipelines and local distribution companies (LDCs), FERC and Public Utility 

Commissions (PUCs) may need to change standards that would harmonize the ―electric day‖ and 

―natural gas‖ scheduling day. 

 APPA strongly recommends the U. S. EPA‘s final EGU MACT rules include a Title V method to 

accommodate any utility that cannot meet the EGU MACT compliance deadline. This 

administrative noncompliance procedure is already established under the Clean Air Act. This 

will allow for compliance time and avoid criminal and civil liability while reducing the 

administrative burdens on U. S. EPA and any state agencies with delegated authorities, and 

reduce costs and burdens on small towns with public power electric utilities.

Comments related to the requirements of Clean Air Act Section 112

Section 112 and subsequent court decisions have led to a process for establishing HAP standards that

includes establishing a ―floor‖ requirement reflecting the performance achieved in practice by the best 

controlled similar units, followed by an adjustment for further reductions ―beyond the floor‖ if certain 

statutory criteria are met. A key element in establishing the floor is identification of appropriate 

subcategories within a regulated category, to ensure that the units represented by the ―best 

performing‖ units are indeed ―similar.‖

In general, the nature of many public power facilities differs from the general population of coal-fired 

power plants. As described in our detailed comments, public power units tend to be smaller in size, 

and are often space-constrained by growth in the community surrounding the generating unit since its 

initial construction. These limitations restrict the ability of these units to achieve the same 

performance levels as larger, unconstrained units, and, for those units which can comply with the 

proposed standards, sharply increases the cost of compliance.

We believe that the requirement that the floor represents levels ―achieved in practice‖ is at odds with 

the proposed rule in at least two respects. First, the test operations and statistical treatment of the test 

data do not represent periods of startup, shutdown, or malfunction. Therefore those periods of 

operation should not be subject to the standards. A work practice approach, similar to that 

promulgated for industrial boiler HAPs, would be appropriate for these abnormal operating periods. 

Second, the continuous compliance assurance requirements – which include enforceable limits on 

various fuel and hardware variables like the pressure drop across a control device – are effectively 

more stringent than the emission standards that they support, and therefore were not ―achieved in 

practice‖ by the best controlled units. Such additional levels of stringency are not authorized under 

the provisions of Section 112. In addition, we have a number of technical objections to the validity of 

determining emission compliance using these parameters. A better approach would be to exempt 

emissions during SSM functions or identify a much reduced set of parameters that are indicative of 

increased emissions, and monitor those to determine when an emission test is likely warranted.

Comments related to the requirements of the Unfunded Mandates Reform Act 

(UMRA), the Small Business Regulatory Enforcement and Fairness Act 

(SBREFA), Executive Order 13563 (Improving Regulation and Regulatory 

Review), and Executive Order 13132 (Federalism)

UMRA and SBREFA include provisions that require EPA to evaluate the impact of its regulations on 

state and local governments, and certain small entities. Most public power systems qualify under 

these general categories. EPA should have, but did not, engage in an adequate process of consultation 

with APPA or other small entities regarding these rules. Moreover, the rulemaking record shows no 

evidence that EPA considered substantive alternative regulatory approaches in an effort to reduce the 
9

financial burden of these rules on state and municipal governments that own public power facilities, 

or that purchase power from other utilities subject to the rules. APPA believes that there are 

mechanisms whereby EPA could reduce this burden, while still complying with the statutory 

requirements of the Clean Air Act.

In addition to these statutes, two Executive Orders direct EPA, as a matter of good public policy, to 

minimize the economic burden of meeting environmental requirements, and to minimize the federal 

presence by consulting with state and local governments when developing national standards. APPA 

believes that EPA has failed to comply with these orders.

Additional details on these procedural cost-related requirements are included below, and in the 

detailed comment sections of these comments.

On of APPA‘s most significant concern is that the U. S. EPA has not responded to the concerns of the 

small business community, the U. S. Small Business Administration (SBA), and the Office of 

Management and Budget (OMB). The December 2, 2011 Small Entity Representatives (SER) panel 

discussed their concerns with the amount of time it would take to complete any emissions control 

installation project on a utility. The Regulatory Impact Analysis (RIA, section 10-23) includes 

commentary from OMB and SBA (See Appendix B). The U. S. EPA did not act upon OMB‘s 

suggestions that the EPA meet again before the rule was proposed 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.‖ (RIA, pg. 10-23)

APPA notes that no additional meetings were convened between December 2, 2010 and March 16, 

2011 when the proposed rule was announced or by May 3, 2011 when the proposed rule was 

published in the Federal Register. APPA also observes that the U. S. EPA ignored the strong 

concerns expressed by the SER panelists regarding the three-year compliance deadline.

More than 90% of public power 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).

1

According to EPA‘s Regulatory Impact Analysis (RIA), this rulemaking will affect 1,400 coal and 

oil-fired units with >25MW nameplate capacity units. This means approximately 200 APPA member 

utilities with coal-fired or oil-fired generation will need to undergo retrofit or gas conversion within 

36 months. APPA believes that the U. S. EPA grossly underestimated the costs for compliance 

and overall feasibility of this rulemaking on approximately 200 public power coal-fired utilities,

given the compressed time. See Appendix G or pages 20-32 of comments.

APPA believes that the U. S. EPA did not fulfill its statutorily required actions and failed to 

perform a full analysis under the Regulatory Flexibility Act, or “Reg Flex,” and UMRA as well as 

SBREFA.

Since the proposed EGU Utility MACT regulations that the U. S. EPA intends to propose would 

almost certainly have a significant economic impact on a substantial number of small entities,

2 U. S. 

EPA was required, pursuant to the Regulatory Flexibility Act (RFA),3to convene a Small Business 

Advocacy Review Panel (SBAR) to thoroughly and accurately assess the impact of the proposed 

regulations on utilities that qualify as small businesses. During the convened SBREFA SER panel 

 

1

See ―Regulatory Flexibility and Unfunded Mandates Reduction Act Considerations.‖

2

See section titled ―The Proposed NSPS Are Not Achievable‖

3

5 U.S.C. § 601 et seq.,
10

meeting it was clear that the U. S. EPA had not adequately fulfilled its responsibilities to assess the 

impact of any proposed regulations since the Agency did not lay out clear and significant alternatives 

to the regulation that would be proposed. 

The Small Business Regulatory Enforcement and 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 businesses in the federal regulatory process4and to 

create a more cooperative regulatory environment among agencies and small businesses that is less 

punitive and more solution-oriented.5Section 609 of SBREFA envisions that small business panels 

will review ―any material the agency has prepared in connection with this chapter,‖ including 

information required to be part of the initial regulatory flexibility analysis.6 A regulatory flexibility 

analysis typically includes descriptions of significant alternatives to the proposed rule, differing 

compliance or reporting requirements or timetables that take into account the resources available to 

small entities, and the clarification, consolidation, or simplification of compliance and reporting 

requirements for small entities.7 At the December 2, 2010 SER meeting on Utility MACT the U. S. 

EPA did not prepare and distribute any of these clarifications, consolidations or simplifications 

of the U. S. EPA regulatory options by the U. S. EPA. Subsequently, the U. S. EPA asked the 

SER panel participants to advise the agency and file comments a few days following this 

meeting. This does not follow Congress’ intent for how SBREFA analysis and SBAR panels 

should be conducted. (See Appendix C for letter from the U. S. Small Business Committee, June 

2011, regarding similar concerns with the EPA SER process on NSPS for CO2.)

The highly abbreviated nature of this particular small business review panel that was established for 

the EGU MACT rule prevented small APPA utilities from having the meaningful advisory role 

envisioned and outlined by SBREFA.8 Only one panel meeting was provided and after that meeting, 

panel members were given a mere 14 days to prepare written comments on an incredibly complex 

topic.

9 The materials provided by EPA just prior to the only panel meeting were little more than what 

the EPA 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 and individual utilities 

were invited to participate. Those included the Clean Water Act Section 316(b) cooling water intake 

structures/entrainment and impingement of aquatic organisms, the ICI Boiler MACT rulemaking (<25 

MW coal-fired plants) in 2003 and others held in the last ten years where the APPA has been invited

to attend and participate. The SER panel meeting held on Dec. 2, 2010 was reminiscent of the very 

unorthodox small entity outreach undertaken by the U. S. EPA for the GHG Tailoring Rule in 2009. 

APPA accepted the non-SER panel approach on the GHG Tailoring Rule because of the unusual 

circumstances surrounding how CO2 would be regulated. This was brought about by the cascade 

regulation of stationary sources of CO2 from Section 202 of the Clean Air Act for tailpipe standards. 

Alternatively, the EGU MACT regulation and the timing of that regulation required no 

truncated or shortened process for the SER panel. The U. S. EPA set the deadlines with the 

 

4

5 U.S.C. § 203(3).

5

5 U.S.C. § 203(6).

6

5 U.S.C. § 609(b)(4); see also 5 U.S.C. § 603(b)(3), (4) and (5) and 603(c).

7

See 5 U.S.C. § 603(c).

8 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. 

9 While providing only 14 days for written comments by panel participants, EPA nevertheless propounds six slides of questions for those entities. 

Many of those questions were answered by all EGUs in response to Parts 1 and 2 of the EGU MACT ICR. Others would require far more than 14 

days to provide meaningful responses. If EPA is serious about wanting input on the questions it posed to panel members, then a much longer 

comment period should be provided. 
11

court in response to litigation and should have factored the timing for a full and complete 

SBREFA panel. U. S. EPA acknowledged that it needed this time during the meeting at its 

offices on December 2, 2010. APPA believes that the December 2, 2010 meeting made a 

mockery of the productive goals of SBREFA and the SER panel process. The U. S. EPA 

identified no regulatory alternatives to reduce costs and ignored the recommendations offered

by SER panelists, such as GACT controls for subcategories.

EPA Has Failed to Meet the Requirements of the Unfunded Mandates Reform Act of 1995 

(UMRA10) and Executive Order 13563 and Executive Order 13132 of 1995.

11

As stated in Executive Order 13563, and to the extent permitted by law, each agency must, among 

other things: (1) propose or adopt a regulation only upon a reasoned determination that its benefits 

justify its costs (recognizing that some benefits and costs are difficult to quantify); (2) tailor its 

regulations to impose the least burden on society, consistent with obtaining regulatory objectives, 

taking into account, among other things, and to the extent practicable, the costs of cumulative 

regulations; (3) select, in choosing among alternative regulatory approaches, those approaches that 

maximize net benefits (including potential economic, environmental, public health and safety, and 

other advantages; distributive impacts; and equity); (4) to the extent feasible, specify performance 

objectives, rather than specifying the behavior or manner of compliance that regulated entities must 

adopt; and (5) identify and assess available alternatives to direct regulation, including providing 

economic incentives to encourage the desired behavior, such as user fees or marketable permits, or 

providing information upon which choices can be made by the public.

APPA acknowledges that the U. S. EPA has discretion in developing utility air toxics rules under 

Section 112 and believes that this discretion allows U. S. EPA to consider the economic realities 

facing the country today. It is noted that U. S. EPA has taken relatively little discretion in developing 

MACTs for virtually every industrial source except for electric utilities, which got entirely different 

treatment under (n)(1)(a). In addition, APPA believes that Executive Order 13563 provides important 

guidance as to the use of U. S. EPA's discretion. All the information provided by U. S. EPA in the 

preamble of the proposed air toxics rule indicates that the proposed rule will have a major impact on 

the fuel mix of electric utilities and electric generating capacity. The projected cost for the rule is 

significant while providing only minimal benefits from the direct reduction of hazardous air 

pollutants. By U. S. EPA's own calculations, 99.99% of all benefits from the proposed rule will 

result from co-benefits associated with estimated reductions of SO2 and NOx resulting in lower 

ambient PM2.5 and ozone levels. However, these co-benefits would naturally follow the 

implementation of other CAA requirements currently in progress, including the revised PM2.5

and ozone NAAQS as well as the one hour SO2 and NOx NAAQS, which will lead to lower SO2

and NOx caps under the Clean Air Transport Rule (CATR now called Cross State Air Pollution 

Rule).

12

APPA respectfully submits that the U. S. EPA has failed to meet the requirements of Unfunded 

Mandates Reform Act of 1995 (UMRA) and Executive Order 13132 in this rulemaking. Before 

proposing the MACT rule, UMRA required EPA to undertake an assessment of the impact of the rule 

on local government under sections 202 and 203 of the Act. 2 U.S.C.A.§§, 1532 -1533. (See 

Appendix D) The requirement for this assessment reflects Congress‘ concern regarding the

 

10 2 U.S.C.A. §§1331-1335 (2011).

11 64 Fed. Reg. 43255 (Aug. 10, (1999

12 In the preamble for CATR, EPA discusses this relationship between revisions to lower a NAAQS and future reductions of SO2 and NOx cap 

under CATR.
12

unintentional effects of federal mandates, including federal regulations, on local governments and the 

spill-over effects on local communities, including the tax base of such local economies and their 

ability to provide other governmental services. In the context of this rule, these impacts could be 

especially significant. First, the cost of power in small municipalities will be driven up by the 

compliance costs of the proposed utility MACT, particularly if EPA does not take APPA‘s 

suggestions to reduce the regulatory burdens of complying with the proposed MACT standards. 

Second, because municipal power generation is a pivotal component to many local economies and in 

turn the ability of municipal governments to provide other community services, it is critical that EPA 

carefully assess the social and economic impacts of compliance costs or the consequences of the 

potential shut down of public power plants on municipal governments, in addition to residents and 

local industries served by public power. The agency‘s proposed action does not reflect these 

considerations despite the direction to do so under UMRA, SBREFA and the Executive Orders..

APPA is particularly troubled by being unable to find information in the rulemaking record regarding 

the qualitative and quantitative assessment of the anticipated costs and benefits of the proposed 

regulation on local governments. Nor did EPA‘s analysis extend to which costs to local governments 

may be paid with federal financial assistance or otherwise paid for by the Federal government, 

including any assessment of the disproportionate effect of the MACT rule on regions of the country. 

In some parts of the country there is no infrastructure to deliver sufficient additional supplies of

natural gas to meet the additional demand in many states. APPA respectfully submits that despite 

information in the preamble to the proposed rule, there is little information in the background 

documents in the record of this proposed action that EPA has in fact consulted with state and 

local officials “early in the process of developing the proposed action.” Id. at 25086. 

APPA acknowledges that the preamble to the proposed rule states that EPA has convened a meeting 

of the ―Big 10‖13 national organizations representing state and local elected officials, held on October 

27, 2010 in Washington pursuant to UMRA. Although the EGU MACT proposed rule states that the 

potential impacts of the proposed rule must be disclosed and considered with the affected regulated 

community under UMRA‘s Section 204, Id. At 25085, APPA can find no record in the RIA of any of 

the details of the proposed rule being shared with the October 27, 2010 ―Big 10‖ meeting. We 

respectfully wish to point out that APPA‘s examination of the technical support documents for this 

rulemaking has failed to yield an agenda or minutes of this meeting with the ―Big 10‖ organizations. 

We also respectfully observe that it is unlikely that EPA had reached the point in its Utility MACT 

decision-making in October 2010 when the agency could have shared meaningful information with 

elected officials regarding the costs and other consequences (such as the shutdown of plants for cities 

and their service communities) of regulatory alternatives. Even if these assessments had been made 

in October 2010 (which changed to the Regulatory Impact Assessment in early May 2011 suggest are 

unlikely), APPA also submits that the ―Big 10‖ organizations are unlikely to have had stakeholders 

that were impacted by the MACT rule and therefore EPA‘s statement that it has received no 

additional questions or requests from state or local officials concerning the rulemaking, id at 25086, 

comes of little surprise. While we have been unable to locate the list of 112 state and local 

governments which EPA states it provided addresses for at these meetings, we are not aware that any 

of these cities or their public power providers received any meaningful communications regarding 

potential impacts.

 

13 The Big Ten organizations are defined at 76 FR 25085 (May 3, 2011) as National Governors Association, National Conference of State 

Legislatures, Council of State Governments, National League of Cities, US Conference of Mayors, National Association of Counties, 

International City/County Management Association, National Association of Towns and Townships, County Executives of America, and 

Environmental Council of States. Specific section: RFA/SBREFA analysis under ―Consultation with Government.‖
13

Not until December 2011 did EPA actually invite public power (along with investor–owned utility) 

representatives to a meeting to discuss the potential regulatory impacts of the rule. In fact, APPA 

submits, many more communities will be negatively impacted by the costs of the proposed MACT 

rule, causing many municipalities to cease to provide low-cost electricity and steam to communities 

and industries that they currently service.

Section 202 of UMRA requires statements to accompany proposals of significant regulatory actions, 

defined as ones that in the aggregate may result in the expenditure by state, local, and tribal 

governments, in the aggregate, or by the private sector, of $100,000,000 or more (adjusted annually 

for inflation) in any one year, and before promulgating any final rule for which a general notice of 

proposed rulemaking was published, the agency shall prepare a written statement containing—

(1) an identification of the provision of federal law under which the rule is being promulgated; 

(2) a qualitative and quantitative assessment of the anticipated costs and benefits of the federal 

mandate, including the costs and benefits to state, local, and tribal governments or the 

private sector, as well as the effect of the federal mandate on health, safety, and the natural 

environment and such an assessment shall include—

(A) an analysis of the extent to which such costs to state, local, and tribal governments may 

be paid with federal financial assistance (or otherwise paid for by the federal 

government); and 

(B) the extent to which there are available federal resources to carry out the 

intergovernmental mandate;

(3) estimates by the agency, if and to the extent that the agency determines that accurate 

estimates are reasonably feasible, of—

(A) the future compliance costs of the federal mandate; and 

(B) any disproportionate budgetary effects of the federal mandate upon any particular 

regions of the nation or particular state, local, or tribal governments, urban or rural or 

other types of communities, or particular segments of the private sector; 

(4) estimates by the agency of the effect on the national economy, such as the effect on 

productivity, economic growth, full employment, creation of productive jobs, and 

international competitiveness of United States goods and services, if and to the extent that 

the agency in its sole discretion determines that accurate estimates are reasonably feasible 

and that such effect is relevant and material; 

(5) a description of the extent of the agency‘s prior consultation with elected representatives 

(under section 204) of the affected state, local, and tribal governments; 

(6) a summary of the comments and concerns that were presented by state, local, or tribal 

governments either orally or in writing to the agency; and 

(7) a summary of the agency‘s evaluation of those comments and concerns. 

Section 203 requires that before establishing any regulatory requirements that might significantly or 

uniquely affect small governments, agencies shall have developed a plan under which the agency 

shall—

(1) provide notice of the requirements to potentially affected small governments, if any; 
14

(2) enable officials of affected small governments to provide meaningful and timely input in the 

development of regulatory proposals containing significant federal intergovernmental 

mandates; and 

(3) inform, educate, and advise small governments on compliance with the requirements.

EPA’s Poorly Managed SBREFA SER Panel

At the December 2, 2010 EGU MACT meeting the U. S. EPA materials did not include any possible 

rulemaking alternatives or any information about possible compliance or reporting options. Moreover, 

the material lacked any results of EPA‘s analyses of the data from the extensive information 

collection request (ICR) that EPA identified as being ―critical to the promulgation of an EGU MACT 

rule.‖ APPA urged that additional small business SER panel meetings be held following a better 

staff review of the data, and that small entities be given the opportunity to comment on real 

regulatory alternatives once the U. S. EPA identified options. APPA would have been pleased to 

participate in that more thorough process.

14

 See Appendix E for a copy of the APPA comments in 

response to the EGU MACT SER meeting.

APPA believes EPA should have fully assessed the potential impacts of agency rules on small 

entities, including through solicitation and review of comments from small entities and examination 

of regulatory alternatives that achieve the same purpose(s) of the rule while minimizing impacts to 

small entities.15 In addition, RFA requires federal agencies to prepare and publish an initial 

regulatory flexibility analysis, and to perform a final regulatory flexibility analysis when proposing a 

regulation that would have a significant economic impact on a substantial number of small entities. It 

is clear that the proposed Utility or EGU MACT rule will have a significant impact on a substantial 

number of small entities especially if the EPA considers the number of smaller public power utilities.

Approximately 10% of governmental or public power utilities will be directly impacted by this 

rulemaking (200 out of 2000) and the likely impact is projected at much greater than 5% of utility 

revenues. All public power utilities will be impacted by significantly increased wholesale electricity 

prices.16 

Specifically, APPA is very disturbed that some of the recommendations made by the SER participants 

at the December 2011 SER panel meeting (and later in writing) were ignored and not even offered in 

the rulemaking. For example, the EPA did not discuss subcategorizing by age, type of plant, fuel,

physical space constraints or useful anticipated life of the plant. Nor did the U. S. EPA provide any 

opportunity for smaller emitters to use GACT—often used in other U. S. EPA MACT regulations to 

alleviate the regulatory costs and operational difficulties that would have burdened other small 

businesses including dry cleaners, metal fabricating, metal finishing, and others. It is in that context 

that APPA asks and will continue to ask for both the U. S. EPA and OMB to consider these APPA 

comments under SBREFA during inter-agency review of the final rule. 

Since all APPA member public power utilities are not-for-profit, APPA also requests that APPA 

comments on the EGU MACT be considered in the context of the Unfunded Mandates Reform Act 

(UMRA). In particular, it should be noted that all additional regulatory permitting costs would be 

incurred by public power utilities. Accordingly, APPA asks that comments on the Utility MACT 

submitted by municipal or state governments (including their electric utilities) also be 

considered under SBREFA and UMRA.

 

14 For more specific information please see APPA‘s general comments on the December 2, 2010 SBREFA SER 

15 See 5 U.S.C. § 601 et seq.; see also Pub. L. No. 96-354, § 2(a), 94 Stat. 1164 (1980).

16

 See page 45 under APPA‘s General Comments number 13.
15

APPA‘s members who operate power plants that burn coal, particularly in the Midwestern and 

Southeastern parts of the country will face the biggest impact under the EGU MACT/NSPS rule. In 

addition to the impacts a proposed rule would have on those APPA power producers that generate 

their own electricity using coal, other APPA members who purchase electricity from the open market 

generated from coal – or where coal generation keeps the market clearing price lower - would face 

significantly higher costs for power, which, in turn, would be passed on to the residential consumers

and businesses of the communities they serve. 

EPA must also understand that any adverse cost impacts from the EGU MACT would extend directly 

to municipal and local government operating budgets during a very difficult economic time. APPA 

members are not-for-profit entities, and as such serve no shareholders. Increasing operating costs on 

these power producers would be passed on directly to rate payers. Significantly increased costs may 

also cause reduced Payments in Lieu of Taxes (PILOT) from APPA members to municipal 

government general funds. PILOT payments are an important part of many municipal operating 

budgets. Smaller PILOT payments to general municipal budgets would likely result in cuts to 

essential governmental services, including fire, police, schools and EMT personnel. This could not 

come at a worse time, as municipal governments are seeking even larger contributions from the 

public power electric utilities they govern to help fend off other dramatic short-falls in municipal 

budgets for essential governmental services. In 2009, over 66% of surveyed municipalities were 

engaging in hiring freezes or layoffs due to economic conditions.

17 The proposed MACT 

regulations will create significant economic impacts for many utilities, causing further significant 

municipal budget shortages, and could force further layoffs and furloughs. This downward cycle 

would only deepen the financial stress felt in local economies. Although we do not have 2010 figures 

from our municipal membership, APPA notes that many cities have seen continued loss in tax 

revenue and property taxes in 2011.

APPA is concerned about the ability of small entities or nonprofit utilities such as those owned and/or 

operated by rural electric co-op utilities, and municipal utilities to comply with the proposed 

standards within three years. EPA identified a variety of small entities that will have to comply with 

the new rule, many of which will face substantial compliance costs.

18 In the proposal, EPA states that 

102 of the estimated 1,400 EGUs are owned by 83 small entities. EPA further estimates that 59 of the 

identified entities will have annualized costs greater than one percent of their revenues. APPA 

believes that U. S. EPA has not fully recognized the number of small entities that are impacted by this 

rule. This poor analysis reflects both a poor analytical preparation for the rulemaking and a 

disregard of what the EPA was told during the U. S. EPA SBREFA SER panel meeting on 

December 2, 2010. The SER panelists explained in December 2010 that under these current 

economic conditions they have constraints on their ability to raise capital for the construction of 

control projects and to acquire the necessary resources in order to meet a three-year compliance 

deadline.

In the proposed rule, EPA identified a number of mechanisms - such as work practice standards, subcategorization, health based compliance options, and emissions averaging - that it explains will lessen 

the burden on small businesses. While these actions may reduce the burden to a limited degree, they 

will be far from enough to make the final rule cost effective for many small and medium sized public 

power utilities. APPA believes that the ultimate impact on many of these entities will be enormous.

They are certainly ―significant‖ within the meaning of the Regulatory Flexibility Act (RFA). The 

monetary impact on small businesses will be substantial enough to strain their financial well being.

The present sluggish economy simply does not provide the financial resources for many of these 

small utilities to take on the additional costs of retrofits to meet the proposed MACT standards in 

 

17 Hoene, Christopher W., ―City Budget Shortfalls and Responses: Projections for 2012,‖ National League of Cities, 2009

18 See 76 FR 25083
16

three years. More time and more flexibility are needed for public power utilities. (See section on 

timing, page 22)

The EPA should acknowledge that the price of compliance increases as size of generating unit 

decreases.

19 This means that smaller generating units will be impacted more in their decision to 

comply with EPA‘s toxics rule. This disproportionately large impact poses a much more serious 

compliance hurdle for small communities that depend on coal fired generation to meet their base load 

demand. Coal plant emissions control retrofits to reduce SO2 emissions cost on average three times 

as much when installed on smaller generating units. In addition, by using EPRI data it can be seen 

that the price of compliance doubles for NOx control equipment as the size of the unit is 

decreased from 100 MW to 50 MW. APPA believes that the U. S. EPA did not adequately 

consider the disproportionately large cost of compliance on small communities.

20

Though the utility industry may be able to produce and install the technology necessary to upgrade 

coal plants, smaller plants that represent smaller electricity sales and those that exist on the margin 

will be incrementally charged more by vendors and contractors. Just as home buyers looking for 

home repair or modification during the housing bubble paid a large time-dependent scarcity price on 

labor, public power utilities will face similar costs. Less desirable compliance projects at smaller 

generating units will likely be bid in at prices that reflect the lower desire to capture those projects or 

the opportunity cost of lower performance on a larger job. Smaller plants that already have to pay 

three times more for controls equipment will also have to pay more for labor.

The cost to comply with this proposed rule for a small power plant (approximately 50 MW in size) is 

equivalent to purchasing a new gas-fired power plant. In effect, by not subcategorizing to consider the 

disproportionately high cost on small communities the EPA is dictating a fuel switch. See the section 

on page 17 regarding the details of subcategorizing units ≤ 100 MW. This subcategory will greatly 

help the public power and broader utility industry.

EPA has Underestimated the Impacts of the Proposed Rule on Smaller Utilities Despite SER Panel

U. S. EPA identified a variety of small entities that will have to comply with the new rule, many of 

which will face substantial compliance costs. See 76 FR 25083. One way U. S. EPA defined a small 

entity was an electric utility that generated four million megawatt-hours of electricity per year or less. 

In the proposal, U. S. EPA states that 102 of the estimated 1,400 EGUs are owned by one of 83 small 

entities. U. S. EPA further estimates that 59 of the identified entities will have annualized costs 

greater than one percent of their revenues. APPA believes that the U. S. EPA has not fully 

recognized the number of small entities that are impacted by this rule. This is a critical failing 

because many of these entities have severe constraints on their ability to raise capital for the 

construction of control projects, and to acquire the necessary resources in order to meet a three-year 

compliance deadline. This financial strain is mostly caused by the inclusion of acid gas controls and 

PM controls that greatly increase the cost of this regulation and require more retrofit time. The U. S. 

EPA should re-propose the rule to address only mercury (coal-fired) and nickel (oil-fired) limits with 

subcategories – especially the ≤ 100 MW subcategory discussed in detail Appendix A.

APPA notes that the U. S. EPA‘s Regulatory Impact Analysis (RIA) states that the U. S. Small 

Business Administration (and presumably OMB) expressed concerns that the U. S. EPA failed to 

identify and offer as regulatory alternatives a number of options on the proposed EGU MACT rule 

before it was proposed. A Small Entity Representative (SER) panel was convened on Dec, 2, 2010 

and no regulatory options or regulatory alternatives were provided as required under the Small 

 

19 Bernstein analysis report

20 U.S. Utilities: Coal-Fired Generation Is Squeezed in the Vice of EPA Regulation; Who Wins and Who Loses?, BernsteinResearch, 2010
17

Business Regulatory Enforcement and Fairness Act (SBREFA). Instead the SER panelists gave both 

verbal recommendations and followed up with written recommendations ten days later that identified 

regulatory options to reduce costs while meeting the requirements of the law to reduce mercury. None 

of those recommendations for subcategories (by size, by fuel type, by generation technology type or 

by geographic isolation (rural)) were even proposed by the EPA in the proposed rule. The EPA‘s 

proposed rule did not explain why none of these recommendations were considered and not used. 

That explanation is required under SBREFA and Unfunded Mandates Reform Act (UMRA) and both 

of these statutes deal with regulatory decisions for local government-owned utilities. APPA has 

discussed a small unit subcategory related to space constraints since 2004 so this should not be a new 

idea to the U.S. EPA staff. APPA has provided many aerial photos showing space constraints. (See 

Appendix F for APPA‘s comments.)

The OMB and SBA also commented (captured in the RIA, Section 10, pp. 10-27) that the U. S. EPA 

should have convened a panel with regulatory alternatives offered to the SER panelists and that, at a 

minimum before the proposed rule was published, a second meeting should have been held where 

these regulatory options should have been discussed. Additionally, SBA asked for the EPA to 

consider granting an additional year to the smaller utilities that would need to procure, contract, 

construct, install, and calibrate control technologies to meet the EGU MACT requirements since these 

units are often baseload units with inadequate backup generation to support the municipal utility 

during the scheduled outages. The proposed rule did not mention any plans to offer an additional year 

to these smaller entities and was dismissive of the serious reliability issues for smaller communities 

(especially in the Midwest) where many of the retrofits or conversions to natural gas will take place 

within three years of the final rule. 

APPA urges U. S. EPA’s final EGU MACT rule to contain <100 MW subcategory to 

minimize impacts to smaller units

APPA points out that this recommended subcategory, primarily designed for public power utilities <100 

MW would help minimize uneconomical plants from facing retirements. Further this subcategory, while 

still reducing mercury through GACT controls, would provide ―wiggle room‖ during the time of 

transition to ensure system or regional reliability—particularly in the Midwest where these <100 MW 

units are more common. APPA believes that this <100 MW subcategory should also be provided for 

investor utilities, merchant power or electric-co-operative utilities although APPA notes that 106 of these 

units are in public power communities. While the subcategory would help a handful of investor or 

electric co-operative utilities, it would most benefit local governmental utilities. Of the <100 MW utilities 

across the U. S. the total generating capacity affected, if a subcategory is created, is only 5%. Thus this 

subcategory is not a ―loophole‖ and should not concern the U. S. EPA or public health officials. See 

Table1 for details.
18

Note: Rounding up of emission limits was practiced by EPA for the proposed EGU MACT Rule. 

Table 1

EGU MACT Range of 99% CI Upper Predicted Limit (UPL) Values from RMB Small 

Unit Subcategorization Analysis Applying Student T Test Methodology.

EPA Proposed Emission 

Standards

RMB Estimates of Emissions Standards 

"Full 12%" of Coal Units > 8300 Btu/Lb With Small Unit 

Subcategory

Pounds per Million Btus lbs./mmBtu lbs./mmBtu lbs./mmBtu

HAP < 8300 Btu/lb 

(lignite)

> 8300 

Btu/lb < 100 MWs > 100 MWs All Units

Mercury 4.0 E-6 1.2 E-6

2.3E-06 2.1E-06 2.1E-06

EPA's approach for using the lowest reported ICR value 

for a unit was applied in these calculations. RMB 

sensitivity analysis also considered use of average 

reported unit emissions and the statistical methods EPA 

applied for industrial boiler MACT estimates. Doing so 

increases emission standards relative to this table. 

Total PM (as 

surrogate for metals)

Same as > 

8,300 Btu/lb 0.030 0.060 0.020 0.030

Filterable PM NA NA 0.020 0.010 0.010

Total Metal HAPS Same as > 

8,300 Btu/lb 0.000040 0.000110 0.000040 0.000040

HCl Same as > 

8,300 Btu/lb 0.0020 0.0230 0.0020 0.0020

SO2 (FGD/DSI 

Only)

Same as > 

8,300 Btu/lb 0.2 0.2 0.2 0.2

Organics (Work 

Practice Standard)

Same as > 

8,300 Btu/lb

Boiler 

Tune-Up 

Every 18 

Months

Boiler TuneUp Every 18 

Months

Boiler TuneUp Every 18 

Months

Boiler Tune-Up Every 18 

Months

# of Coal Units 30 1061 294 767 1061

# in EPA ICR 

Reporting Mercury 

Emissions

11 328 91 237 328

Number in Mercury 

HAP Best 

Performing 12% 

Calculation

2 

(Hg Limit 

based on 

"Beyond the 

Floor" 

analysis)

40 35 92 127

Number in NonMercury HAP Best 

Performing 12% 

Calculation

2 

(Hg Limit is 

based on 

"Beyond the 

Floor" 

analysis)"

127 35 92 127

Color Code: No color No change in Estimated Emissions Standard

Yellow Increased value

Orange Decreased Value
19

EPA’s own Regulatory Impact Analysis and economic analysis says that 97 municipal or state 

utilities will have a compliance cost of $666.3 million in annual direct compliance costs (RIA, 10-

30). This EPA cost analysis does not factor other costs such as:

(a) Cost of purchasing power off the market or from other municipal utilities during scheduled 

outages for retrofit.

(b) Costs for fuel switching to natural gas.

(c) Inability to sell coal ash or coal combustion residuals (CCR) to the cement industry due to the 

sodium levels from Dry Sorbent Injection (DSI) exceeding the cement industry‘s ASTM (formally 

known as American Society for Testing and Materials)21 standards for sodium content. These coal ash 

residual costs resulting from the DSI technology were not mentioned or considered in the proposed 

rule‘s economic analysis.22

As with all EPA regulations, the costs to the ultimate consumer of the U. S. EPA regulation of CCR 

as hazardous were not considered. This is most unfortunate since small businesses are often price 

sensitive to fluctuations in energy pricing. While the CCR rulemaking has not been finalized, APPA 

points out that, if coal ash is designated as hazardous waste under RCRA (Subtitle C), state and 

municipal governments might feel compelled to remove and remediate the coal ash fill from under 

buildings, at landfills, and under existing highways and roads. These coal ash/CCR costs were not 

considered in this rulemaking, but there is certainly a link between these two proposed rules. There is 

no mention of this very significant impact of this proposed rule in the RIA, given the lost revenue and 

increased utility costs associated with coal ash being not useful for the commercial market due to its 

very high sodium content. The EPA‘s press announcements and all subsequent presentations given to 

the utility sector mention that they have considered the allegations of the ―train wreck‖ and that they 

have considered the convergence of many EPA regulations on the utility sector in a short timeframe. 

Clearly the EPA did not do a thorough job looking at the costs of these regulations but chose to point 

out only the costs of the EGU MACT without any consideration of the effect of DSI controls on the 

ability to sell or trade coal ash.

For municipal electric utilities, a RCRA hazardous waste Subtitle C designation - or simply making 

the ash undesirable to the cement industry (due to sodium content from DSI technology) - would 

often mean a dramatic increase in the cost of disposal. These increased coal ash disposal costs can 

range between 5% and 24% of a municipal government‘s utility budget (when considering larger 

public power utilities that exceed the SBREFA threshold). The typical cost range is between 2% and 

14% depending upon proximity to a hazardous waste landfill (Source: APPA‘s comments to the U. S. 

EPA on coal ash, Nov. 2010). Impacts referenced in Table 3 on page 75.

APPA notes that there may be unintended cost consequences to eastern coal varieties because utilities 

using eastern coal variety‘s coal may not be able to meet the EGU MACT/NSPS proposed rule. 

APPA notes that use of western coals by the remaining coal fired power plants may well cause 

utilities of all sizes to be more reliant upon rail transportation due to moving more western coal to 

more power plants. As captive customers of rail companies, power plants would pay significantly 

more for delivery of western coals. The displacement of the eastern coal, cost and the related 

transportation impacts were not considered by the U. S. EPA. The costs of transportation of coal are 

 

21 http://www.astm.org/ABOUT/overview.html

22 An APPA member noted that if they were to start using DSI at their generating station they estimate that it would cost an additional $100 

million over 20 years to dispose of the fly ash (This includes the revenue loss from selling it, increased material handling costs, the need to build 

additional landfill cells and all the operating and closure costs associated with the landfill). These numbers assume that fly ash will not be 

declared a hazardous waste.
20

almost always more expensive than the cost of the coal itself. If the U. S. EPA‘s final EGU 

MACT/NSPS rulemaking causes more fuel switching from eastern to western coals, the additional 

transportation costs (and captive rail cost concerns) may well be another major factor not considered 

in the U. S. EPA Regulatory Impact Analysis (RIA). This is yet another reason why the U. S. EPA‘s 

failure to subcategorize between eastern and western coal represents a serious technical flaw which is 

unlikely to survive judicial challenge.

While some larger public power utilities may not have as many logistical challenges as the smaller 

municipal systems, APPA notes that it is unwise to have so many utilities (regardless of size) 

attempting to retrofit and convert over the same three-year period. Additionally, the U. S. EPA failed 

to avail itself of its ability to use GACT controls and subcategorize adequately (especially for ≤ 100 

MW units) to help either the smaller utilities or the larger utilities. GACT controls have been used 

successfully in many other EPA MACT rules, including the following industries:

 Iron & Steel Foundries 

 Electric Arc Steelmaking

 Coatings Operations Area Source Controls Rule

 Clay Ceramics Manufacturing

 Glass Manufacturing

 Secondary Nonferrous Metals Manufacturing

 Paint Stripping & Miscellaneous

Timing for Compliance Requires 77 Months for Public Power Utilities due to Governance 

Requirements and Financing of Projects 

The U. S. EPA has on several occasions made compliance extensions applicable to an entire industry 

or subcategory.23 The analysis presented below focuses on these provisions and why in particular 

public power facilities face unique additional municipal and state laws that make it urgent for EPA to 

utilize its authority to provide compliance extensions for the industry. First we provide a general 

discussion of the Agency‘s authority to provide compliance extensions. Then we describe 

assumptions that the Agency states in the preamble about the industry‘s ability to comply with the 

proposed standards and why we believe that they are in error. Third, we describes the results of an 

independent APPA-commissioned survey24 of the public power industry and the types of problems 

that members will have in complying with the standards if EPA fails to take the recommended actions 

to reduce the regulatory burdens of complying with the proposed MACT standards. We urge EPA to 

pay particular attention to municipal and state law affecting bidding procedures for equipment design, 

fabrication and labor and the state and municipal laws that affect the timing and procedures for public 

referendums for issuance of public bonds, eminent domain concerns and other unique issues such as 

easements, high density zoning and union labor that municipalities have reported will necessarily 

delay compliance with final emission standards for up to six years after they are promulgated. On 

this basis APPA urges U. S. EPA to grant a one-year state compliance extension in the final rule. We 

also suggest that it is critical for U. S. EPA to consider the provision in the Clean Air Act that enables 

the President to grant extensions for up to two additional two-year periods and the source-by-source 

showings that governors and mayors should provide to be eligible for such extensions from 

compliance.

 

23 National Emission Standards for Hazardous Air Pollutants From Coal- and Oil-Fred Electric Utility Steam Generating Units, proposed rule, 

76FR24976, May 3, 2011.

24 See survey summary in Appendix G
21

Statutory and regulatory provisions

The Clean Air Act addresses compliance schedule requirements in Section 112(i)(3) and (4), as set 

forth below:

§112(i)(3) Compliance schedule for existing sources 

(A) After the effective date of any emissions standard, limitation or regulation promulgated under this 

section and applicable to a source, no person may operate such source in violation of such standard, 

limitation or regulation except, in the case of an existing source, the Administrator shall establish a 

compliance date or dates for each category or subcategory of existing sources, which shall provide 

for compliance as expeditiously as practicable, but in no event later than 3 years after the effective 

date of such standard, except as provided in subparagraph (B) and paragraphs (4) through (8).

(B) The Administrator (or a State with a program approved under subchapter V of this chapter) may 

issue a permit that grants an extension permitting an existing source up to 1 additional year to 

comply with standards under subsection (d) of this section if such additional period is necessary for 

the installation of controls. An additional extension of up to 3 years may be added for mining waste 

operations, if the 4-year compliance time is insufficient to dry and cover mining waste in order to 

reduce emissions of any pollutant listed under subsection (b) of this section.

(4) Presidential exemption 25- The President may exempt any stationary source from compliance with 

any standard or limitation under this section for a period of not more than 2 years if the President 

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

national security interests of the United States to do so. An exemption under this paragraph may be 

extended for 1 or more additional periods, each period not to exceed 2 years. The President shall 

report to Congress with respect to each exemption (or extension thereof) made under this paragraph.

Proposed section 63.9984 of the HAP rule states that ―if you have an existing EGU [electric 

generating unit], you must comply with this subpart no later than [3 years after date the final rule is 

published in the federal register].‖26 Pursuant to a Consent Decree, the U. S. EPA Administrator 

must sign a final rule by November 16, 2011.27 The recently promulgated HAP rule for industrial 

boilers was signed by the U. S. EPA Administrator on February 21, 2011,

28 but was not published in 

the Federal Register (making it effective) until March 21, 2011. It specified a compliance date for 

existing units of March 21, 2014 (three years after publication).

29

 Assuming a similar one-month lag 

for publication of the Utility HAP rule would suggest a three-year compliance interval would result in 

a compliance deadline of December 16, 2014. For any unit granted a one-year extension under 

§112(i)(3)(B), the compliance date would be December 16, 2015. Hence, a source can be assured 

that it has 37 months following issuance of the final rule to comply, and that it may be able to obtain 

an additional 12 months (49 month total), but approval of the 49 month alternative is at the discretion 

of the permitting authority. 

 

25 APPA points out that the CAA‘s statutory term ―exemption‖ in this context does not mean a complete exemption from the rule meaning no 

installation of pollution controls. A ―Presidential exemption‖ in the context of these comments functions as a regulatory compliance time 

extension. See CAA 112(i)(4). APPA‘s recommendation for the use of the Presidential exemption is really a request for additional time.

26 Ibid., p.25102.

27 Consent Decree, American Nurses Association, et. al., v. USEPA, Civ. No. 1:08-cv-02198 (RMC), US District Court for the District of 

Columbia, http://www.epa.gov/ttn/atw/utility/consentfnl.pdf .

28 National Emission Standards for Hazardous Air Pollutants for Major Sources: Industrial, Commercial, and Institutional Boilers and Process 

Heaters, USEPA, 76FR15662.

29 Ibid., 76FR15665.
22

U. S. EPA provided limited discussion of the compliance schedule requirements in the preamble of 

the proposed rule. 30 U. S. EPA stated, ―We believe that 3 years for compliance is necessary to allow 

adequate time to design, install and test control systems that will be retrofitted onto existing EGUs, as 

well as obtain permits for the use of add-on controls. We believe that the requirements of the 

proposed rule can be met without adversely impacting electric reliability. Our analysis shows that the 

expected number of retirements is less than many have predicted and that these can be managed 

effectively with existing tools and processes for ensuring continued grid reliability. Further, the 

industry has adequate resources to install the necessary controls and develop the modest new 

capacity required within the compliance schedule provided for in the CAA. ... EPA believes that the 

ability of permitting authorities to provide an additional 1 year beyond the 3-year compliance timeframe as specified in CAA section 112, along with other compliance tools, ensures that the emission 

reductions and health benefits required by the CAA can be achieved while safeguarding completely 

against any risk of adverse impacts on electricity system reliability. ” The ensuing discussion 

explained that U. S. EPA believes that many of the units requiring retrofit technology for acid gases 

can use dry sorbent injection (DSI) technology, which requires less time to install than the dominant 

approach currently used by electric utilities (flue gas desulfurization, or FGD), but that even if FGD 

systems were chosen by utilities, they could be ―installed within the 3-year window.‖ For nonmercury metal HAPs, ―EPA has assumed that companies with ESPs will likely upgrade them to FFs.‖ 

And for mercury, EPA assumed that compliance would come through the combined contribution of 

non-mercury specific controls like FGD and FFs, and activated carbon injection systems (ACI). EPA 

noted that some facilities would have multiple retrofits, requiring a staggered installation sequence, 

but even these could be accommodated within the four year schedule.

U. S. EPA considered the possibility that widespread retirement of existing coal units and 

replacement with new capacity could strain industry construction capabilities, but concluded that 

―very little new capacity‖ would be needed to maintain adequate electricity reserve margins, and 

―EPA projects that approximately 9.9 GW of coal-fired generation (roughly 3 percent of all coal-fired 

capacity and 1% of total generation capacity in 2015) may be removed from operation by 2015.‖

U. S. EPA‘s assessment of timing appears to reflect immediate action based on the proposed rule 

(versus waiting until a final rule is promulgated). ―EPA expects that sources will begin promptly, 

based upon this proposed rule, to evaluate, select, and plan to implement, source-specific compliance 

options.” U. S. EPA also believes that Regional Transmission Organizations (RTOs) should get 

started on the new regulations and states, ―The RTOs/ISOs also have a very important role to play 

and it appears that a number of them are already engaged in preparing for these rules.‖ The Agency 

cites two presentations as evidence of this early action: a presentation by the PJM Interconnection,

31

and a second by MISO.32

U. S. EPA notes that it is developing a number of regulations impacting the power sector in addition 

to the proposed HAP rule. These regulations include the interstate transport rule (and its multiple 

iterations as U. S. EPA modifies ambient air quality standards), the coal combustion waste rule, the 

cooling water intake structure rule, and limits on greenhouse gases from both new and existing power 

plants. Although U. S. EPA does not address the planning difficulty this poses for the regulated 

utilities, it does observe that U. S. EPA‘s job will become easier over time as ―the Agency will have 

an opportunity to take into account the effects of the earlier rulemakings in making decisions 

regarding potential GHG standards for EGUs.‖

 

30 Op. Cit., National Emission Standards, 76FR25054 - 25058.

31 Consideration of Forthcoming Environmental Rules for Resource Adequacy in PJM, presentation to Harvard Electricity Policy Group, 

December 9, 2010, Tucson, AZ, Paul Sotkiewicz, Chief Economist, PJM Interconnection.

32 Proposed EPA Regulation Impact Analysis, MISO Planning Advisory Committee, November 23, 2010, 

https://www.midwestiso.org/Library/Repository/Meeting%20Material/Stakeholder/PAC/2010/20101123/20101123%20PAC%20Item%2002%20

Proposed%20EPA%20Regulation%20Impact%20Analysis.pdf .
23

In addition to the foregoing discussion in the preamble to the proposed regulation, U. S. EPA 

conducted an analysis of the feasibility of the retrofit program required by the proposal.33 The 

conclusion of this analysis was: ―... a reasonable, moderately paced effort of the power sector and 

supporting industry, including some early starts, would result in many of the needed retrofits being 

installed by January 2015 with some needing up to an additional year. In order for all retrofits to be 

completed by January 2015, most projects would have to start early and the sector would have to 

engage in a more aggressive deployment program.” The analysis drew from U. S. EPA‘s modeling 

of compliance measures. A key conclusion from that modeling was the projected widespread use of 

DSI technology instead of FGD, with a resource savings of 80-90% based on the simpler DSI 

systems. Additionally, the feasibility analysis implies that the capital cost assumed for fabric filter 

(FF) systems, the most broadly deployed compliance system in U. S. EPA‘s analysis, was about 30% 

the amount of a similarly sized wet-FGD. EPA also assumed that the most resource-intensive 

compliance option was retirement of an existing coal unit with replacement by a new coal unit, which 

U. S. EPA assumed would cost about 5 times the amount of a wet-FGD retrofit. These cost 

assumptions were critical to U. S. EPA‘s resource and timing analysis because the U. S. EPA 

assessment of industry‘s capacity to design, manufacture, and install compliance hardware was based 

on the capital cost of compliance measures. U. S. EPA also based its expectations for feasibility in 

part on improving past schedules for installing air pollution control (APC) systems, and stated, ―EPA 

believes that almost all future APC retrofits can be completed far more quickly than were historical 

APC projects.‖ The U. S. EPA feasibility analysis for the HAP rule did not consider any of the 

resource requirements for compliance with the other regulations U. S. EPA cited in its 

preamble.

In summary, U. S. EPA predicts very little problem in meeting the three-year compliance schedule 

proposed in the regulation, if the additional year of compliance time is provided to ―some‖ units. The 

key assumptions supporting this conclusion are:

 The use of low-cost, simple, DSI systems to control acid gases, instead of more complex FGD 

systems

 Faster retrofits than similar projects in the past 

 Compliance requirements of other regulations have no impact on HAP compliance

 The small number of projected retirements, about 10 GW of coal capacity

 Early planning action by regulated utilities

 Early planning action by RTOs

General compliance timing issues

Each of the key assumptions in EPA‘s analysis of compliance timing merits consideration.

DSI systems

DSI systems have been used by some utilities to address ―blue plume‖ issues associated with the 

retrofit installation of SCR systems on power plants burning medium to high sulfur coal. SCR 

retrofits tend to oxidize more of the SO2 in the flue gas to SO3, which can pass through FGD systems 

and condense outside the power plant stack as an acid mist. DSI has been effective in preventing 

such a mist plume. However, DSI is not in widespread use as a basic SO2 control system. If these 

systems are as effective as U. S. EPA assumes, it raises the question of why they have not been 

placed in service to mitigate basic SO2 emissions.

 

33 An Assessment of the Feasibility of Retrofits for the Toxics Rule, US EPA, Office of Air and Radiation, March 9, 2011.
24

Faster retrofits

One might expect that as utilities gain experience with air pollution controls, this learning would 

allow future retrofit projects to be more streamlined, and faster. However, at some point, such 

learning reaches a point of diminishing returns, as the application of air pollution controls becomes a 

mature industry. For the types of hardware that U. S. EPA expects to be retrofitted to enable 

compliance with the proposed HAP rules, that point in time occurred perhaps in the mid-1980‘s, as 

utilities complied with 1971 vintage State Implementation Plans and New Source Performance 

Standards. Since that point in time, further experience was gained with eastern U. S. ozone control 

programs, and the acid rain program prescribed by the 1990 Clean Air Act Amendments, but by then 

the air pollution control industry was well established.

Countering this learning curve process is the exploitation of the best opportunities for retrofits. Air 

pollution regulations incorporating trading, like the acid rain program, allowed utilities to control 

emissions from those sites easiest to retrofit. By exploiting these sites first, utilities were able to 

minimize the cost of retrofits, and resulting electricity price increases. A consequence of this process 

was that those sites which have not yet retrofitted advanced SO2 or NOx control hardware will face 

more difficult retrofits. And at sites which have already added large control systems like FGD and 

SCR, finding available space to retrofit a FF often will be difficult. While the ―learning curve‖ 

advantages diminish over time, the site congestion problem becomes worse. Site congestion can 

extend the planning and installation time for a project. The net effect is that EPA’s assumption of 

faster future retrofits is probably incorrect.

Requirements of other regulations and the 10 GW of retirements

If the purpose of a feasibility analysis is to determine feasibility, then ignoring major compliance 

activities imposed on the same work force at the same time can only be viewed as disingenuous. 

When EPA considered resource constraints on the implementation of the 2005 Clean Air Interstate 

Rule (CAIR), the Agency considered not only the CAIR requirements but also other ongoing 

regulatory requirements.34 An analysis of resource adequacy conducted on one of several regulations 

has limited value.

Early planning

U. S. EPA is correct in stating that these regulations, and the other regulations under development and 

cited by U. S. EPA, are known to be coming. However, the implicit assumption that utilities can 

begin designing and ordering compliance hardware before they know what the basic requirements are 

is unsupported. It will be difficult for utilities to make decisions even when a final HAP rule is 

promulgated, given the approach of additional regulations with additional requirements for capital 

investment. Consider the industrial boiler HAP rule promulgated by U. S. EPA in the spring, 2011. 

Between its proposal in June 2010, and promulgation in March 2011,

35,36 the rule changed 

dramatically. As a result, U. S. EPA‘s estimate for the total compliance costs for all affected existing 

units burning solid fuels decreased from $2.2 billion per year (proposed rule), to $0.85 billion per 

year (final rule). An electric utility with <25 MW unit or an industrial party with an industrial boiler 

owner who made financial commitments based on the proposed rule would have likely have made a 

poor decision.

 

34 Rule To Reduce Interstate Transport of Fine Particulate Matter and Ozone (Clean Air Interstate Rule), 70FR25216, May 12, 2005.

35 National Emission Standards for Hazardous Air Pollutants for Major Sources: Industrial, Commercial, and Institutional Boilers and Process 

Heaters, Proposed Rule, 75FR32006, June 4, 2010.

36 National Emission Standards for Hazardous Air Pollutants for Major Sources: Industrial, Commercial, and Institutional Boilers and Process 

Heaters, Final Rule, 76FR15608, March 21, 2011.
25

U. S. EPA‘s confidence that RTO‘s are currently making plans for this wave of regulations, including 

the HAP rule, may similarly be misplaced. The PJM37 presentation cited by U. S. EPA in the 

preamble summed up the industry‘s dilemma in one slide:

38

The fact that PJM knows that additional regulations are being developed does not enable the RTO to 

take specific measures to ensure grid reliability. That ability will come when it is clearer which 

power plants will retrofit specific types of hardware, and which will retire – facts that cannot emerge 

until the final rules, i.e. all rules affecting air emissions, water intake and discharge and waste 

management, are promulgated. PJM‘s population served of >51 million means that one of every six 

consumers of electricity is in the PJM RTO.

Compliance information related to public power utilities

An APPA survey of public power utilities was conducted (July 2011) in order to obtain a better 

understanding of the procedures and time necessary for that segment of the generation fleet to comply 

with the proposed HAP rule. Specific questions related to:

 The characteristics of existing coal-fired generation, including existing air pollution control 

equipment, and potential compliance needs

 The timing and process of planning compliance, and how that might differ from that of an 

investor owned utility (IOU)

 The timing and process of obtaining financing for pollution control projects

 Permitting, detailed design, and construction processes at public utilities

 An overall assessment of the time required for the full compliance process, from initial planning 

through startup of new pollution control hardware.

Utilities owning approximately 14 GW of coal based generation capacity responded to the 

APPA survey. These represent over 50% of the coal based capacity wholly owned by public 

power utilities. Respondents ranged in cumulative capacity between 55 MW and 2200 MW, 

and averaged 610 MW of coal based capacity. Not all respondents addressed every question in the 

survey, but most provided a general description of their compliance process, and areas where they 

might differ from IOUs. The results of the survey are summarized by the following:

 

37 PJM is a regional transmission organization (RTO) that coordinates the movement of wholesale electricity in all or parts of 13 states and the 

District of Columbia. PJM has 163,500 MW generating capacity and >51 million customers.

38 Op. Cit., Consideration of Forthcoming Environmental Rules, slide #20.
26

 About 20% of respondents planned to retrofit FGD,

39 and about 20% SCR40 (typically the same 

utilities were retrofitting both). About one-half planned to replace or supplement existing ESPs 

with new FFs.

41

 About one-fourth were moving forward with plans based on the notice of proposed rule (NOPR). 

Half were waiting until the final rule is promulgated, and the rest intended to wait until other 

pending environmental rules were finalized before deciding on a compliance approach.

 About three-fourths of respondents stated that they needed the assistance of engineering 

consultants for planning their compliance strategy. Such reliance is not unusual, even for IOUs, 

but several respondents cited their small size and/or remote locations as barriers to obtaining 

assistance from the larger, more qualified consulting firms. Additionally, several respondents 

cited a mandatory ―public bid‖ process for selecting contractors (and purchasing equipment) 

which deterred some contractors and created additional delays in reaching compliance.

 Public power utilities generally must receive approval from political bodies, such as an 

elected Board of Directors and a City Council. Procedures vary by utility, but separate 

government approvals may be required for the compliance plan and the issuance of bonds to pay 

for the compliance projects. Several respondents noted that a public referendum is required in 

order for bonds to be sold.

 Planning periods averaged 17 months, and financing 8 months. However several respondents 

noted that budgets were addressed only once per year, and that public reviews of plans and 

funding could result in extended delays, including what one respondent called ―hostile 

interventions.‖ 

 Respondents cited a range of criteria for deciding whether to retrofit an existing unit or retire the 

unit and replace the lost capacity with a new unit. In determining the most important criterion 

affecting that decision, 38% of respondents cited the age of a unit or the capital cost of the 

retrofit project, 41% cited the average cost of electricity increase resulting from the retrofit 

project, and 21% cited the general uncertainty regarding the cost of future environmental 

regulations. Stated differently, the basic logic used to model the HAP rule – minimizing future 

cost of electricity considering only the HAP rule – was not the critical criterion for compliance 

planning for most public power utilities. This is important to the issue of compliance timing 

because it suggests that modelers, including EPA‘s, may be using the wrong model logic to 

simulate responses to the proposed rule, and thereby projecting the wrong compliance strategies. 

Different strategies (specifically, retirement versus retrofit) could have fundamentally 

different resource and timing requirements.

 Over three-fourths of respondents expecting to add a FF for compliance stated that space 

limitations at their sites would significantly increase capital costs, compared to a site with 

adequate space.

 Responding utilities with multiple units to retrofit at the same facility expected to need an 

additional 12 months in order to address a second unit.

 For past retrofits of environmental control systems (FGD, SCR, FF, ESP), respondents reported 

an average of 49 months to address all activities from planning to startup. This average did not 

include the additional time needed to retrofit multiple units at one facility. It is important to note 

that this figure represents an average. As reflected in EPA‘s approach to establishing upper 

performance limits (UPLs) for HAP emission rates, average values should not be the basis for 

 

39 Those planning to retrofit FGD were all single-facility utilities, and they planned to retrofit the entire facility.

40 One of these SCR respondents planned to retrofit 50% of his capacity; the remainder would retrofit 100%.

41 The portion of the FF respondents‘ facilities retrofitting FFs generally ranged between 60-100% of total capacity.
27

setting compliance requirements. If one used EPA‘s approach of ―percentiles‖ (i.e., select a value 

for which 99% of facilities would comply with the rule), then the number of months needed for 

a single unit retrofit at a facility would range from 73 to 78 months, for “percentiles” of 

90% to 99%. 

Adding 12 months for a facility requiring two retrofits would result in 85-90 months. 

However, four of the past retrofits described by respondents were either unusually faster or 

slower than the rest of the reported retrofits. Excluding these units as ―outliers,‖ which seems 

reasonable if one takes the ―percentile‖ approach, would yield the same average (49 months), but 

a range of 54-65 months for the 90% to 99% UPL, or 66-77 months if a year is added for 

facilities retrofitting two units. Please see Figure 2 below for a visualization of the time needed to 

complete retrofits for compliance as compared to the time allowed by U. S. EPA.

 Unusual situations are not reflected by the above average, but probably fall within the range 

represented by a ―90 percentile‖ approach. One respondent speculating on a future retrofit cited 

the need to replace a hot-side ESP with a FF. This change would mean that the air heater would 

no longer receive ―clean‖ flue gas, since the fabric filter system could not tolerate the high 

temperature of gases entering the air heater, leading to reconfiguring the air heater to a ―dirty‖ 

system, and relocating a major electrical subsystem within the existing unit. The respondent 

judged that this work could not be completed in 4 years.

Figure 2: Visualization of timeline needed by utilities to install pollution controls for compliance as opposed to 

timeline allowed by U. S. EPA.
28

General conclusions and recommendations

It is clear that public power (not for profit) utilities face some procedural requirements not generally 

shared by investor owned utilities and independent power producers. These procedural requirements 

can extend the period of time needed by public utilities to comply with the HAP rule. For example, 

most public utilities must answer to a ―Board of Directors,‖ or equivalent body, as well as a City 

Council, or equivalent political body. Generally, both of these groups must approve major capital 

projects, such as retrofitting a FF on a power plant. In some cases, the process includes public 

participation. Public power (not for profit) utilities do not issue stock, so capital projects are 

generally financed entirely via debt. Subsequent to approving a project, a second review and 

approval process is usually required for public utilities to issue bonds, which are the primary debt 

vehicle for public utilities. In some, but not all, jurisdictions, bonds must also be approved by voter 

referendum. These review and approval processes can be time consuming, particularly if the 

government body only considers budget items once per year, or if a bond vote must await a general 

election.

The average public power utility is also smaller than the average electric utility. Cumulative coal 

capacity averages about 417 MW for public power utilities, versus an average of over 1,000 

MW for all utilities. Several respondents to the public power survey expressed difficulty in 

attracting quality contractors due to the utility‘s small size relative to large IOUs competing for the 

same pool of contractors. Requirements for a public bidding process were cited by several public 

utilities as creating an additional barrier to securing top quality contractors. Smaller, less experienced 

contractors can require longer to complete a project than larger firms.

In general, respondents to the public power survey supported few of the key assumptions used by 

U.S. EPA in the agency‘s compliance time analysis. For example, U. S. EPA‘s expectation of 

significant planning activity prior to issuance of the final HAP rule was not supported by respondents. 

Over 70% of respondents felt the need to see the final HAP rule before charting a compliance 

path, and some of those wanted to see the outcome of other pending U. S. EPA rules before 

making decisions. This is a significant issue for public power utilities, as noted above, because 

of their formal, multilevel oversight and approval process. Municipal entities cannot afford the 

economic or political consequences of planning missteps.

Respondents also challenged U. S. EPA‘s reliance upon DSI, instead of more traditional FGD 

systems for acid gases. As noted previously, 20% of respondents planned on retrofitting FGD 

systems. On the other hand, respondents supported EPA‘s expectation for a large number of FF 

retrofits. About one-half of respondents planned to retrofit a FF system.

Based on the preamble42 and EPA‘s supporting feasibility study,43 it appears that EPA believes that 

the regulated utilities can achieve compliance within 50 months of the signing of the final rule (48 

months after publication in the Federal Register). As noted above, the preamble states that three

years is ―necessary,‖ but does not say that it will be sufficient. The U. S. EPA feasibility paper says 

that, if some utilities get started before the rule is finalized, then ―many of the needed retrofits‖ could 

be ―installed by January 2015 with some needing up to an additional year.‖ These dates are 

coincidentally identical to the compliance limits specified in Section 112 of the Clean Air Act. EPA 

appears comfortable with the fact that it is proposing a rule with compliance dates which are 

unachievable, absent favorable execution of discretionary extensions by permitting authorities, but 

which are achievable even in that case only if regulated facilities embark on compliance strategies 

before they know what the regulation will require. This exceedingly thin endorsement of a 3-4 year 

compliance period is not well supported by the past experiences of public utilities. As described 

 

42 Op. Cit., National Emission Standards, May 3, 2011.

43 Op. Cit., An Assessment of the Feasibility.
29

above, a survey of past retrofits by public power utilities suggests that the regulations would 

need to provide 66-77 months to accommodate facilities with multiple retrofits and to ensure 

that 90% to 99% of retrofit projects could be completed within the compliance date deadline.

U. S. EPA‘s lack of consideration of resource requirements by other rules under development by the 

agency, and the assumption ―that almost all future APC retrofits can be completed far more quickly 

than were historical APC projects‖ are both causes for concern. U. S. EPA acknowledges that there 

are at least four other major power plant rules which will be adopted over the next year, but offers no 

insight into how resource demands for those rules will impact the timing of compliance with the HAP 

rule. Those additional engineering and construction resource demands could be large, particularly if 

the cumulative effect of the rules leads to early retirement of existing coal units and construction of 

replacement power. U. S. EPA‘s vacant assertion regarding future versus past retrofit schedules 

ignores the fact that recent rules involving emissions trading (the acid rain program, the NOx SIP-call) 

created a strong incentive to control the most easily retrofit units first. Remaining sites will face 

inherently more difficult and time consuming challenges. The most common retrofit technology 

projected by the U. S. EPA‘s analysis is FF technology. Many existing public power utilities will be 

challenged to find space to retrofit those large units, and disruptive installations tend to take longer to 

install.

Finally, it should be recognized that public power utilities are extensions of state and local 

governments. U. S. EPA‘s analysis of the timing of compliance includes no consideration for the 

special compliance schedule challenges that public power utilities face. Both the Unfunded Mandates 

Reform Act of 1995 and Executive Order 13132 create imperatives that U. S. EPA minimize 

regulatory impacts on local governments. U. S. EPA acknowledges its obligations to public utilities 

in the preamble,44 but appears to believe that convening meetings with national associations 

representing state and local governments relieves the agency of the need to propose and evaluate 

substantive alternative regulatory options that address the needs of those government entities.

Time Constrained Feasibility: Why Categorized Extension for Governmentally Owned Utilities Is 

Justified

APPA urges that U. S. EPA grant publicly owned utilities an extra year for compliance beyond 

the three years provided by the Clean Air Act. 42 U.S.C. §112(i)(3)(A). As outlined above, 

publicly-owned electric generating facilities must comply with administrative and regulatory 

procedures for bidding and financing pollution control and repowering projects. Notice 

requirements and public contracting procedures for bidding the purchase, design and 

installation of such equipment are also mandated under city or state laws so that the public has 

the opportunity to monitor, contribute to, and comment on how public funds are used for large 

expenditures that will be necessitated to meet the pollution control requirements of the 

proposed MACT standard. Such local governance duties for these expenditures and actions

will add up to three years to compliance periods required to retrofit or repower units to meet 

the proposed standards, according to APPA‘s survey. 

In addition to the inability of most publicly owned utilities to compete economically with 

privately owned utilities for the already limited supply of skilled design and construction 

engineers and available technology to meet the industry-specific MACT requirements, 

government-owned utilities will need to meet unique local, state and federal requirements 

regarding bond issuance for the purchase of equipment and other competitive bidding 

processes for implementation of the requirements. Based on prior U. S. EPA precedent and 

these unique circumstances, more time is required for publicly-owned generating facilities to 

purchase controls and approve contractors. Additionally, more time is needed for installation 

 

44 Op. Cit., National Emission Standards, 76FR25084 – 25087.
30

of compliance equipment. The U. S. EPA should provide in the final EGU MACT rule for a 

categorical extension for compliance for publicly-owned or governmental facilities to meet 

the new MACT standard based upon time-constrained feasibility. This categorical public 

power extension is based upon the feasibility for local government and must be considered 

under UMRA and the Clean Air Act. Under Clean Air Act the U. S. EPA has the authority to 

set the deadline based upon feasibility. APPA is aware that ―feasibility‖ has been addressed 

for other Clean Air Act deadlines (NAAQS) in the case of the steel industry when the 

―feasibility‖ in installing new controls was either economic or technical. (See U. S. EPA‘s 

RACT/ BACT Guidance.) APPA believes this is a different type of ―feasibility,‖ but one 

consistent with the common parlance or meaning of ―feasibility.‖

A clear reading of Executive Orders 13563 (Improving Regulation and Regulatory Review) 

and Executive Order 13132 (Federalism) shows that the U. S. EPA failed to follow their 

obligations under either Executive Order.

Executive Order 13563‘s Section 4 makes it clear that all agencies (including Independent 

agencies such as the U. S. EPA) shall identify and consider flexible approaches for compliance 

to their proposed rule. In this instance the U. S. EPA has not proposed any of the regulatory 

options to reduce burdens and maintain flexibility. 

Sec. 4. Flexible Approaches:

Where relevant, feasible, and consistent with regulatory 

objectives, and to the extent permitted by law, each 

agency shall identify and consider regulatory 

approaches that reduce burdens and maintain flexibility 

and freedom of choice for the public. These approaches 

include warnings, appropriate default rules, and 

disclosure requirements as well as provision of 

information to the public in a form that is clear and 

intelligible.”45

Further, the Executive Order on Federalism (EO 13132 )‘s principal tenants were ignored in 

Sections 1, 2 and 3 by the U. S. EPA. Please see pp 9-14 of APPA‘s comments. In specific, 

Executive Order on Federalism says:

Section 3(b) of Executive Order 13132:

 “Where there are significant uncertainties

 as to whether national action is authorized or

 appropriate, agencies shall consult with appropriate

 State and local officials to determine whether Federal

 objectives can be attained by other means”

APPA notes that the U. S. EPA has failed to carry out its regulatory obligations of the

Unfunded Mandates Reform Act of 1995 (in addition to those critiques offered on pp 8-16) in 

its nominal meeting with the ―Big Ten‖ on October 27, 2010. Section 203 of UMRA (2 USC 

1533) says:

SEC. 203. SMALL GOVERNMENT AGENCY PLAN. 

 

45 Executive Order 13563 of January 18, 2011, Improving Regulation and Regulatory Review, Federal Register /Vol. 76, No. 14 / Friday, January 

21, 2011
31

(a) EFFECTS ON SMALL GOVERNMENTS.—Before establishing 

any regulatory requirements that might significantly or uniquely 

affect small governments, agencies shall have developed a plan 

under which the agency shall—

(1) provide notice of the requirements to potentially affected small 

governments, if any; 

(2) enable officials of affected small governments to provide 

meaningful and timely input in the development of regulatory 

proposals containing significant Federal intergovernmental 

mandates; and 

(3) inform, educate, and advise small governments on compliance 

with the requirements. 

APPA’s recommends a time-constrained feasibility categorical time extension under E. O 

13132, 13563 and UMRA of 1995.

1. U. S. EPA Has Granted Categorical MACT Compliance Extensions Before in 

Unique Circumstances.

While the Act contemplates that the administrator (or a state with delegated Title V 

Permitting authority) would generally grant such extensions on a case-by-case basis 

for an existing source up to one additional year. 42 U.S.C. §112(i)(3)(B), the agency 

also has used this authority to grant category-wide industry MACT compliance 

extensions upon a specific showing of need. See e.g. Subpart G Hazardous Organic 

NESHAPS, 60 Fed. Reg. 5320 (Jan.27, 1995) (discussion of several categorical 

compliance extensions from MACT compliance); National Emission Standards for 

Chromium Emissions From Hard and Decorative Chromium Electroplating and 

Chromium Anodizing Tanks, 62 Fed, Reg. 4463(Jan. 30, 1997) (partial extension for 

all sources in California); NESAHPS for Group I Polymers and Resins 62Fed. Reg. 

1835 (Jan 14, 1997); National Emission Standards for Hazardous Air Pollutants for 

Shipbuilding and Ship Repair (Surface Coating) Operations, 61 Fed. Reg. 30815 

(June 18, 1996) (U. S. EPA has learned that sufficient time was not provided to 

prepare the implementation plans and establish the necessary inventory management 

systems to ensure compliance with the standard.) 

U. S. EPA also has denied requests to grant a category wide extension if sufficient 

basis was not demonstrated. For instance, with respect to implementation of subpart 

H‘s SOCMI leak prevention equipment, commenters argued that the 6-to-18-month 

compliance period in proposed subpart H did not take into consideration the 

implementation problems that could arise during installation of required equipment. 

U. S. EPA did not revise the compliance schedule as requested ―because the 

commenters did not provide any information that would justify establishing a sourcecategory-wide compliance schedule similar to that provided in subpart G. Due to the 

lack of detailed information on equipment changes and installation schedules, the 

U. S. EPA thought that case-by-case compliance extensions would be sufficient to 

address any implementation problems that might arise. In issuing the final rule, the

U. S. EPA added a provision, Sec. 63.182(a)(6), to clarify that individual extensions 

of compliance may be requested for installation of equipment required by subpart H. 

60 Fed. Reg. 5320 (Jan. 27, 1995).
32

2. Publicly-Owned Electric Generators Meet the Statute‘s Standard for Granting Compliance 

Extensions.

The preamble to the proposed amendments to the General MACT Provisions describes some 

of the situations in which a compliance extension for MACT compliance is authorized under 

the Clean Air Act. 

The compliance extension under section 112(i)(3) is available for adding controls and other 

compliance measures requiring time beyond that which is anticipated in establishing the 

compliance date for NESHAP. For example, other compliance measures may include 

obtaining or implementing technology hardware or software systems and process changes to 

accommodate pollution prevention or other emission reduction measures. Such a compliance 

extension is not appropriate for the failure of an owner or operator to properly plan and carry 

out the installation by the compliance date. However, there may be situations where sources 

acting in good faith to anticipate and fulfill their compliance obligations can still not achieve 

compliance in a timely manner because of circumstances or events not entirely of their own 

making. Work stoppages at a control equipment supplier‘s factory are cited as one example 

of a reason that sources, acting in good faith, might not be able to achieve compliance on 

time. Shortages of skilled design and construction engineers who are needed to build new 

facilities to meet relevant standards, as well as shortages of available technology to meet the 

demand from sources who must comply with industry-specific MACT requirements, may 

also contribute to delays in achieving compliance.

APPA‘s members and other publicly-owned utilities meet these additional situations, 

when a compliance extension is appropriate. For administrative ease and resource 

savings on the part of governmental entities and U. S. EPA officials, it would be 

prudent to approve a categorical extension for compliance with the final utility 

MACT to avoid additional justification and review by cities and other 

governmental entities as well as the federal government. While notice, contracts 

and other bidding processes and bond approval requirements may vary somewhat 

among cities, they are very much the same.

APPA Believes U. S. EPA Has Provided a Flawed Regulatory Impact Analysis:

U. S. EPA‘s RIA projects that only three percent of the electric utility industry‘s coal-fired capacity 

will become uneconomical due to the proposed rule because of age, size, or lessened hours of 

operation. U. S. EPA has failed to recognize that many older coal-fired power plants have 

considerable space constraints and may only be able to ―build up‖ if they are installing a baghouse. 

The U. S. EPA RIA failed to identify how many of the public power units will be implementing 

control technologies under separate regulations, including:

 CSPAR or Regional Transport (RT) in 31 states.

 316(b) cooling water, entrainment and impingement studies and the subsequent control 

technologies.

Further, the U.S. EPA has a series of anticipated revisions to the existing National Ambient Air 

Quality Standards (NAAQS) for tropospheric ozone, PM2.5, SO2 and NOx standards. These,

combined with state implementation plan (SIP) changes and revisions to effluent guidelines 

(chlorine, boron, mercury, etc.), may well make power plants subject to being offline for many

weeks and perhaps months over the next five-plus years.
33

Perhaps most importantly the U. S. EPA NESHAP proposal calls for 165 GW of fabric filters for 

the existing coal-fired power plants and perhaps half of the U. S. coal fleet. In total, U. S. EPA‘s 

analysis shows 354 gigawatts of control technology being installed. APPA believes this is a 

significant underestimate of the needed controls and additional costs. Further, APPA believes that 

the U. S. EPA underestimated the impacts on some regions that will have more power plants under 

construction and retrofit at the same time. These plants tend to be in the upper and lower Midwest, 

Southeast and Southwest. Other reliable estimates performed by industry experts show 531 

gigawatts of control technology being installed.46

DSI, the sorbent technology selected by U. S. EPA for its relative low cost, can cause significant 

technical problems, APPA would be very surprised to see half of the industry install dry sorbent 

injection (DSI) by 2015 (RIA, Section 8-13). APPA finds it rather remarkable that the U. S. EPA 

assumes that the DSI technology will work so effectively for all coal types without any technical or 

historical basis. APPA believes that the U. S. EPA has presumed effectiveness based only upon 

limited use of DSI at a few plants. This type of technology choice does not consider all of the 

factors facing utilities and further contributes to the inaccuracies of the U. S. EPA‘s Regulatory 

Impact Analysis. 

APPA believes that the U. S. EPA has grossly underestimated the number of coal-fired 

generation retirements at only 9.9 GW, which is only three percent of all coal-fired capacity 

by the year 2015. APPA believes that the U. S. EPA chose to view the proposed EGU NESHAP 

in isolation and not in the CSPAR (the replacement of the Regional Transport Rule). Many 

published studies project retirements above 40 GW, when viewed in combination and under certain 

circumstances. 

U. S. EPA‘s RIA offers peculiar reference (RIA p. 10-18) to the APPA and NRECA request (verbal 

and written) for subcategorization. Neither the proposed rule nor the RIA adequately explained 

why more subcategorizations were not made. The RIA (RIA section 10-18 under 

―Subcategorization‖) specifically refers to the SER panelists who recommended units that generate 

for wind generation or other purposes such as combined heat and power (CHP). Perhaps most 

significantly the EPA declined to propose a subcategory for small or rural (geographically isolated) 

units. This decision not to propose a small unit subcategory is bad enough but is made all the worse 

since the U. S. EPA offered no use of GACT controls. OMB’s own comments in the RIA agree 

that GACT and management practices would be effective (pp. 10-21 of RIA).

As noted before on page 19, APPA points out that the U. S. EPA‘s Regulatory Impact Analysis 

(RIA) states that the U. S. Small Business Administration (and presumably OMB) expressed 

concerns that the U. S. EPA failed to identify and offer as regulatory alternatives a number of 

options on the proposed EGU MACT rule before it was proposed. None of those recommendations 

for subcategories (by size, by fuel type, by generation technology type or by geographic isolation 

(rural)) were even proposed by the U. S. EPA in the proposed rule. The U. S. EPA‘s proposed rule 

did not explain why none of these recommendations were considered. That explanation in the 

proposed rule is required under SBREFA and Unfunded Mandates Reform Act (UMRA) and both 

of these statutes deal with regulatory decisions for local government-owned utilities. The proposed 

rule did not mention any plans to offer an additional year to these smaller entities and was 

dismissive of the serious reliability issues for smaller communities (especially in the Midwest) 

where many of the retrofit or conversions to natural gas will take place.

 

46 American Coalition for Clean Coal Electricity
34

EPA’s own Regulatory Impact Analysis and economic analysis says that 97 municipal or state 

utilities will have a compliance cost of $666.3 million in annual direct compliance costs 

As previously mentioned, the U. S. EPA‘s cost analysis does not factor in other costs such as the 

cost of purchasing wholesale power off the market, the costs for fuel switching to natural gas or the 

inability to sell coal ash or coal combustion residuals (CCR) to the cement industry.

In addition to poor analysis in the three-year compliance date feasibility presumption about DSI 

technology for all coal types, and ―check the box‖ exercises with the December 2010 SBREFA 

SER, APPA also notes that the U. S. EPA did a very poor job in its Unfunded Mandates Reform 

Act (UMRA) analysis.

“Section 202 of UMRA requires the EPA to consider a reasonable number of 

regulatory alternatives and adopt the least costly, most cost-effective, or least 

burdensome alternative that achieves the objectives of the rule. Moreover, section 

205 allows EPA to adopt an alternative other than the least costly, most costeffective, of least burdensome alternative if the administrator publishes an 

explanation why that alternative was not adopted.”

APPA refers the U. S. EPA to the full critique of UMRA and SBREFA on page 8.

In section 8.10 (Projected Fuel Price Impacts) of U. S. EPA’s Regulatory Impact Analysis for 

the Toxics Rule, the U. S. EPA states that consumer natural gas price impacts from the rule 

are expected to range from a 0.6% to 1.3% increase. APPA believes this is a significant 

underestimation and encourages U. S. EPA to revaluate impacts of the Toxics Rules projected 

price impacts using a range of natural gas prices (and other key variables). In its alternative 

case analysis, U. S. EPA should at a minimum use a set of natural gas prices that include a hedge on 

the bet that natural gas prices will stay low for the foreseeable future. 

Long-term natural gas prices are notoriously difficult to predict and monthly spot prices have varied 

in the last five years from as high as $13 per MMBtu to below $3 per MMBtu; as far as we know 

no government agency or consultant has a consistent track record getting them right. Despite the 

popular view that shale gas makes natural gas available at low prices as far as the eye can see, 

policy analysis should take a more neutral view and consider a plausible range that natural gas 

prices take, recognizing forecasting difficulties and uncertainty. The U. S. EPA should be 

particularly careful with the natural gas price assumption given its recognition that higher natural 

gas prices force more coal-fired generation to retire. A graph of average national monthly gas prices 

can be seen in Figure 3 on the next page. Significant variability in prices can be seen. 
35

Figure 3: Average natural gas prices at the wellhead, citygate, and for commercial consumers from EIA data

Projecting natural gas prices is further complicated because (a) industrial load and demand for gas 

has not rebounded to 2008 levels of consumption, and (b) liquefied natural gas exports may 

influence domestic natural gas prices considerably. It has been noted in the energy trade press that 

exports from built or pending liquefied natural gas terminals may affect as much as 23% of existing 

U.S. natural gas production. 

The natural gas prices produced by U. S. EPA‘s modeling are driven by the assumption on the size 

and economics of gas resource base. ICF, the company that produces the IPM model used by U. S. 

EPA to assess the impact of air regulations, prepared an alternate case in which it reduced the shale 

resource assumption by 31%. Unfortunately, there are no additional alternates testing other key 

assumptions. This should be remedied. The increase in natural gas prices produced by assuming a 

lower resource base amply illustrate how important the resource base is to the natural gas prices 

projected by ICF‘s IPM model. This increase in prices can be seen in Table 2.
36

Table 2

Natural Gas Prices for IPM Policy Case Vs. Lower Gas 

Resources Case

(2007 $/MMBtu)

2012 2015 2020 2030

Policy Case

Henry Hub 5.49 4.77 5.90

Delivered 5.73 4.99 6.22

Lower Gas Resource Case

Henry Hub 4.98 5.51 7.64 8.50

Delivered 5.19 5.71 7.88 8.91

There are a number of other factors that could lead to higher natural gas prices that are not 

reflected in the IPM assumptions or the model structure. U. S. EPA should address these 

factors in order to more accurately model gas prices:

 Higher natural gas demand for use in vehicles (a la The Pickens Plan) or some amount of

transportation electrification

 Constraints either on shale resources allowed to be extracted due to regional opposition or reflect 

drilling restrictions or a cost adder for environmental remediation 

 Starting oil prices ―adapted from AEO 2009,‖ of about $62/bbl for 2011 are well below current oil 

prices

 No documentation of any indication that the gas market module of IPM reflects the drilling lease 

inventory buildup that may be causing some producers to drill at less economic prices in exchange 

for cash flow and retention of their lease options

 Unclear what the production per well or depletion assumptions are or whether they have been 

updated (i.e., lowered) for the shift to more shale production

 Figure 10-7 from U. S. EPA‘s proposed rule provides the resource cost curves but no 

documentation of how they were derived or how the quantity able to be produced economically at 

prices below $14 per MMBtu was determined. Page 10-13 of U. S. EPA‘s proposed rule indicates 

that the undiscovered gas resource is ―assumed‖ to grow at 0.2% per year for conventional gas and 

0.75% for undiscovered gas. Nothing provides the basis for testing that assumption‘s validity. The 

discussion admits that technology drives the ability to produce undiscovered resources but does not 

test the technology assumption and no curves are provided at all for the existing discovered 

resource base.

 The model covers North America only, so it must be fed an exogenous assumption on LNG imports 

(or exports) and cannot predict or capture changes in world-wide development and trading of 

natural gas. 

Comments related to general policy considerations

The Final MACT Should Provide For An Administrative Compliance Procedure for Utilities When 

They are Unable to Comply with the MACT Compliance Date.

If U. S. EPA fails to take the actions recommended by these comments (77 month categorical extension)

to reduce the regulatory burdens of complying with the proposed MACT standards, the agency must 
37

provide a streamlined administrative procedure for utilities that operate power plants that will not be able,

through no fault of their own, to comply with the standard on the compliance date. (Other types of 

facilities also should be able to demonstrate that they meet the qualifications for such compliance

extensions as well.) APPA recommends using existing procedures that already exist within the Clean Air 

Act‘s existing Title V operating permit program for modification of permits with compliance plans to 

streamline the procedure for compliance extensions, which we favor over use of other discretionary 

enforcement procedures that U. S. EPA currently uses for noncompliance. As we explain below, we 

believe that the transactional costs and the uncertainty of the outcome of the use of the current U. S. EPA 

enforcement authorities make them unattractive and inappropriate, particularly for public power plants. 

One of the benefits of this program would be to reduce the administrative burden on the U. S. EPA and 

state agencies. Since 1997, EPA has brought enforcement actions for Section 112 air toxics violations in 

over 500 administrative penalty cases and nearly 100 judicial enforcement cases, some involving 

penalties and environmental projects over $1 million each. Many of these cases involve reporting 

violations but involve significant personnel demands on EPA regions and the Department of Justice.

Without this administrative mechanism for streamlining noncompliance schedules into Title V permits, 

the U. S. EPA, Department of Justice, and their state counterparts could be overwhelmed with the 

additional enforcement burden presented by government-operated utilities that cannot comply timely with 

the MACT standards. By ―pre-programing‖ the minimum components that a compliance schedule would 

have and establishing a time frame for coming into compliance with MACT, these additional burdens on 

the federal and state government enforcement programs can be avoided but state and federal enforceable 

compliance milestones would be in place. Also, state and local governments that operate regulated 

utilities would have certainty and enforceable milestones to meet and would avoid the potentially 

overwhelming transactional legal costs associated with traditional EPA enforcement. As a result mercury 

reductions would be achieved without additional costs and in a manner that provides the public with the 

assurance that these reductions are being made without additional costs to communities.

EPA‘s criminal enforcement program opened 346 new environmental crime cases in FY 2010.47 Many 

states have experienced losses in employees at state regulatory agencies as a result of cut backs and lost 

revenue from permitting fees. This proposal is designed to place the least possible burden on state and 

Federal EPA, consistent with Unfunded Mandates Reform Act (UMRA).

APPA discusses these procedures below and recommends how U. S. EPA should ―streamline‖ the 

adoption of compliance plans even further.

1. Streamlined extended compliance schedules should be provided to public power (and 

other entities) that can demonstrate need for additional time.

APPA has enumerated in good faith the reasons that many municipally operated power plants are likely to 

be unable to comply within the three-year MACT compliance period, even if U. S EPA provides the 

additional year for all public power plants in the final MACT standard, as APPA requests. These reasons 

include, but are not limited to:

 U. S. EPA‘s mistaken assumption that cities can legally begin designing and ordering 

compliance hardware before issuance of the final MACT; 

 

47 US.EPA Office of Enforcement 

http://yosemite.epa.gov/opa/admpress.nsf/ab2d81eb088f4a7e85257359003f5339/78264683b1a9874e852577f10059b840!OpenDocument)
38

 Public power‘s heavy reliance on outside engineering and union labor and difficulty 

competing with other utilities because of most cities‘ bidding procedures;

 The iterative state and locally mandated administrative procedures for the receipt of bids 

and award of contracts;

 Federal, state and municipal requirements of public referendums and the issuance of 

public debentures/bonds for the purchase and installation of pollution control equipment.

In view of these unique public power issues that will likely result in the many public power utilities being 

unable to meet the MACT compliance date, APPA submits that the final MACT should establish an 

―Extended Non-Compliance Schedule‖ procedure for public power generators (and other sources that can 

demonstrate need for additional time).

2. Discretionary U. S. EPA enforcement procedures are too uncertain, and the transactional 

costs that they entail are inappropriate when cities know they will be unable to meet the 

MACT rule because of necessary procedures applicable to local governmental bodies.

The Clean Air Act provides for a battery of civil and criminal remedies, including noncompliance 

penalties, civil penalties, injunctive relief and jail time, for failure to comply with Clean Air Act standards 

and emission limitations. These remedies are administered at the discretion of the agency‘s enforcement 

officials in conjunction with officials in the Department of Justice‘s Environment and Natural Resources 

Division (DOJ ENRD). In most situations, the Agency favors use of consent decrees for entering into 

agreements with noncompliance sources because such legal instruments are judicially enforceable and can 

be judicially modified. Typically, the U. S. EPA and DOJ will issue a Notice of Violation, negotiate with 

officers and other legal representatives of the non-complying source and enter into an agreement which is 

filed the same day as a judicial complaint in the federal court with jurisdiction over a particular entity. 

Such process involves countless hours, attorney fees, the resources of individual federal district courts, 

lengthy periods of time and UNCERTAINTY. U. S. EPA enforcement policy also dictates the need for 

monetary penalties and supplemental environmental policies when noncompliance involves federal 

emission limitations. If a penalty will exceed certain amounts, U. S. EPA enforcement policy also 

dictates several levels of agency review before the consent order can be finalized, and such agreements 

must be published for public notice and comment under section 113(g) of the Clean Air Act before they 

are final. While U. S. EPA enforcement officials also have the sole discretion to utilize Administrative 

Orders on Consent (AOCs) without DOJ oversight, the procedures for their issuance also involve case-bycase review and determinations, though AOCs typically involve far less transactional delays and resource 

costs. 

Since many of APPA’s public power utilities are likely to be unable to comply with the MACT 

compliance date, even with a one year extension, APPA submits that the typical enforcement 

procedures are inappropriate. Moreover, because municipal entities are often cash-strapped because of 

economic conditions and are confronting disproportionate compliance costs (in comparison with other 

entities) and because they are not-for profit, U.S. EPA should provide for another streamlined procedure 

for sources to outline compliance milestones which can be incorporated through streamlined procedures 

in their Clean Air Act federal operating permits. We submit that through these processes, there is more 

likelihood of equal treatment between entities in various parts of the country (a level playing field, if you 

will) and greatly minimized transactional costs and legal resources exacted from municipalities that 

require additional time to come into compliance. 

3. Public power utilities will not reap benefits from being out of compliance with the 

MACT.

Moreover, because public entities are not reaping monetary benefits from failure to comply on time with 

the MACT, these procedures are equitable. Further since such entities are acknowledging they are 
39

violating the Clean Air Act MACT requirements, they bear the onus of noncompliance. Also, Section 

112(d)(4) of the Clean Air Act does not preclude the Agency from identifying other means in a Section 

112(d) MACT standard for a non-complying source to bring itself into compliance. Finally, if a public 

power plant violates the milestones in its compliance plan, recordkeeping and reporting procedures for a 

responsible officer will require expeditious notification of the State and EPA of noncompliance, and 

opportunity for further enforcement actions with penalties, etc.

4. Part 70 Operating Permit Procedures Provide Procedures for Compliance Plans, Which 

EPA Can Streamline Further in The MACT by Allowing Such Plans to Be Incorporated 

Through Minor Modification Permit Procedures.

Title V Compliance Schedules and Reopener Process: APPA urges U. S. EPA to provide in the final 

MACT rule an adoption of MACT compliance schedules through minor permit modifications of a 

source‘s Title V federal operating permits. We explain below why this streamlined procedure should be 

relied on in lieu of judicial or administrative consent decrees where cities and EPA and DOJ would have 

to incur unnecessary transactional costs. We also explain why the Title V rules allow EPA to provide in a 

standard for the use of minor permit modifications which already require notice and public comment to 

streamline further the incorporation of compliance schedules for entities that cannot comply on the 

compliance date even if EPA provides, as APPA hopes, for automatic compliance extensions.

Title V of the Clean Air Act is applicable to operating permits for all major Clean Air Act sources 

required the States to adopt procedures for states and EPA to adopt in operating permits Schedules of 

Compliance. A Schedule of Compliance is defined by Section 501(3) of the Act as:

“a schedule of remedial measures, including an enforceable sequence of actions or operations, 

leading to compliance with an applicable implementation plan, emission standard, emission 

limitation, or emission prohibition.”

See both sections 42 U.S.C. §7661 (a) and 42 U. S. C. § 7661 (3). 

APPA also believes that such compliance schedules could be processed with public comment under 40 

CFR §70.(e)(2)(i) (B) as ―minor permit modifications‖ if, as required by this provision, the procedure for 

inclusion of the compliance schedule is provided by the MACT standard. In other words, to avoid the 

lengthy administrative procedures required by the major modification procedures of 40 CFR Section 

70.7(e)(4) for processing significant permit modifications, EPA can ―pre-program‖ these changes as 

minor permit modifications requiring the public power authority to use the procedures for submitting 

complete applications for approval of a compliance schedule for review by State permitting authorities 

and continue to operate in compliance with those new requirements unless denied by state authorities. 

Such procedures also require notice and public comment with proposed permit modifications. By 

adopting a procedure (and we suggest a general permit modification form for MACT compliance 

extensions in the final MACT), U. S. EPA can avoid unnecessary, lengthy and costly transactional costs 

for municipalities and the federal government (and the judiciary) that would be avoided in prosecuting 

notices of violations and judicial consent decrees. Most important to the cities, it also would allow 

orderly and expeditious negotiation of extended compliance schedules in full view of the public through 

the procedures already established for reopening operating permits. (APPA also suggests that these 

procedures are fully consistent with EPA voluntary audit policies, except of course they would be 

anticipation of noncompliance rather than in discovery of past noncompliance.)

Demonstration of Qualification for Compliance Plans – A public power plant (or other entity) would 

submit an application for a minor permit modification for a compliance plan. Such application would be 

accompanied by a sworn statement by the responsible officer for the utility and city‘s mayor or city 

attorney that despite its best efforts, the public power plant in the jurisdiction cannot timely meet the final 

MACT standard. Such sworn statement shall be accompanied by affidavits of the efforts that the city had 
40

taken to come into compliance and the reasons that it will be unable to comply on the MACT compliance 

date. 

Contents of Compliance Plans: Requirements for MACT compliance plans would include enforceable 

compliance milestones such as dates for purchase of equipment, dates for contractual agreements for 

installation, dates for construction and installation of equipment, or shutdown of equipment, with dates if 

necessary for completion of repowering. Compliance plans also could provide for other contingencies 

and penalties for failure to meet milestones. 

5. Alternatively the final MACT rule should provide for the use of Administrative Orders 

on Consent to Streamline the Adoption of Noncompliance Extensions.

If EPA determines that the potential burden on states permitting authorities in administering operating 

permit modifications for incorporation of compliance plans is too great, it should provide in the final 

MACT rule for administrative consent orders to provide for adoption of MACT compliance plans with 

milestones for purchase and installation of MACT-required equipment for retrofits or shutdowns of 

facilities with or without repowering. APPA believes that it is critical that these Administrative Orders 

are entered into without penalty, since noncompliance will not be to avoid compliance costs that other 

utilities are facing, but merely to move as quickly as is allowed by law to come into compliance with 

Clean Air Act emission limitations. In that regard, it would not be appropriate for cities to pay the U.S. or 

state treasuries penalties for noncompliance with the MACT.

6. It is likely that adoption of a compliance plan procedure requires additional public 

comment.

Even though the Title V and EPA‘s discretionary enforcement authority under the Clean Air Act exist for 

adoption of these mechanisms in the final MACT rule, we think that it would be appropriate for EPA to 

reopen the final MACT to take further comment on these issues, including the milestones for such 

compliance plans and the eligibility requirements for such compliance plans.

General Clean Air Act Section 111 Comments

APPA does not believe that the U. S. EPA has represented ―best demonstrated technology‖ for the gas 

and oil units, and it is inconsistent with the Statute. There is no need for any revision of the standard for 

gas and oil units. 

APPA’s General Comments on EGU MACT and NSPS Proposed Rule

1. APPA believes that the U. S. EPA has made a significant error in its proposed rule on mercury 

under the NESHAP program by adding extraneous regulatory controls for acid gases and PM2.5. 

APPA believes that the U. S. EPA study authorized only mercury reductions in order to protect at 

risk populations of young children, child-bearing women, and those persons who consume large 

quantities of fish and may therefore be exposed to the human health concerns associated with 

bioaccumulation of methyl-mercury. APPA does not believe that the U. S. EPA needed to add 

these additional regulatory requirements since PM2.5 is controlled under ozone and regional haze 

regulatory programs and State Implementation Plans (SIP). Further, particulate matter is 

scheduled to be reviewed for residual risk, which may lead to tightening of ozone, PM2.5, SO2, 

and NOx under the National Ambient Air Quality Standards (NAAQS).

APPA believes that the U. S. EPA should repropose the rule to require reasonable mercury 

reductions consistent with the intent of Section 112 of the Clean Air Act without the 
41

extraneous control requirements on non-methyl mercury. APPA believes that this reproposal should include subcategories for smaller systems (≤100 MW) that have limited physical 

space. Those units should only have to meet GACT controls or area source controls for mercury. 

2. APPA believes that three years from the date of publication of the final rule is an unrealistic 

timeline for compliance, given the need for municipal government to conduct resource planning 

for fuels, issue and review Requests for Proposal (RFP), obtain financing or issue debt/bonds to 

pay for projects, and coordinate with contractors, labor unions, and crane operators, along with 

any permits needed for construction and transportation affected by major construction. Some 

smaller utilities may need to arrange to purchase power from other utilities or the market during 

planned outages to retrofit for EGU MACT controls. This timeline suggests six years to 

accommodate these complex steps. In some states, permitting agencies might require up to six 

months for permit approval processes. Since the Clean Air Act‘s ―pollution exclusion‖ has been 

removed, utilities may well trigger New Source Review (NSR) and this permitting process can 

easily add an additional year to the original permitting time. This point is made especially 

pertinent considering the specific steps that must be completed for each additional control group 

that is added to a generating unit. The specific steps include, but are not limited to:

a. Identifying the type of equipment needed

b. Quantifying the basic design parameters for each control type

c. Evaluating the balance of plant/ancillary changes that will be needed

d. Determination of possibility of compliance, including further economic analysis

These steps outline what is typically referred to as phase 1 engineering work. A municipality 

cannot reasonably expect to complete these steps and the additional phase 2 work, which 

includes final engineering, construction, tie in, and start up with testing, in less than 36 months. 

To that point, a detailed engineering study involving just the decision to add fabric filter 

technology to a utility showed that 34 percent of the fabric filter upgrades would take longer 

than 36 months. 48 See Appendix G

Considering these facts, APPA strongly urges the U. S. EPA to provide an industry wide 

extension, as outlined on pages 62, to reduce the burden on electric utilities, state 

permitting agencies and the consumers of electricity who will pay for the compliance costs. 

APPA urges the U. S. EPA and OMB to consider this under the Unfunded Mandates Reduction 

Act (UMRA) and Executive Order 12866 on energy impacts as well as the Executive Order on 

Federalism. (EO 13132)

3. APPA is a member of UARG and endorses UARG‘s technical paper (found in Appendix H) on 

this proposed EGU or Mercury MACT and the proposed NSPS rulemaking pertaining to data 

availability, data analysis and the identification of conversion errors. APPA also endorses 

UARG‘s comments offered separately on EGU MACT monitoring.

4. EPA did not adequately subcategorize to accommodate many of APPA‘s small and medium sized 

public power utilities. In particular, EPA did not avail itself of the opportunity to use public 

power electric utility subcategory, rural subcategory, and many other fuel type subcategories. 

APPA endorses the establishment of a ≤ 100 MW sub-category that will reduce the costs of the 

proposed rule significantly but only affect 5% of the total electric utility sector.

 

48 Feasibility of retrofitting fabric filter particulate matter control technology to the electric generating unit inventory, UARG paper, Edward 

Cichanowicz, 2011
42

5. APPA does not believe that the EPA sufficiently considered its ability within the Clean Air Act to 

use Generally Available Control Technology (GACT) for smaller emitters of air toxics. Section 

112(d)(5) of the Clean Air Act authorizes the EPA to use less stringent emissions standards or 

work practices for area sources of hazardous air pollutants (HAPs). EPA has broad authority to 

set GACT standards that are less stringent than MACT standards. Alternatively, the U. S. EPA 

should make GACT available for smaller plants. The proposed Utility MACT blurs the 

distinction between pollutants and the sections where they should be regulated in the Clean Air 

Act. This is problematic because there are many APPA member plants that would qualify as area 

sources had the U. S. EPA not combined two sections of the Clean Air Act. GACT has been used 

in the electroplating, dry cleaning and halogenated solvents industries MACT rulemakings in 

order to reduce costs and regulatory burdens. APPA had, along with NRECA, requested the use 

of GACT during the Dec. 2, 2010 SBREFA SER panel and this reasonable request was ignored. 

It seems inexplicable to APPA that the U.S. EPA would not use GACT in this rulemaking after 

being advised by both electric cooperatives and APPA member utilities that this would be an 

optimal way to reduce regulatory costs and achieve a reduction in toxic air pollutants. 

Additionally, APPA thinks it is strange that the U. S. EPA did not include GACT in the EGU 

MACT proposed rule after having allowed GACT and using GACT in the ICI Boiler MACT.49

APPA and NRECA filed comments and discussed GACT during the December 2, 2010 SBREFA

SER meeting so the EPA had plenty of notice to accommodate this option, which is provided for 

small emitters in the Clean Air Act.

6. EPA‘s feasibility and cost analysis did not adequately address physical space and age of plant 

issues when setting Best Demonstrated Technology (BDT), MACT and NSPS. In not addressing 

the age and space issues associated with including so many control technologies, the EPA has 

wrongly produced a rule that will make older plants and smaller plants unable to meet the new 

standards. 

7. The various reports of projected plant closures under various EPA regulations—including EGU 

MACT - suggest the closures will far exceed EPA‘s projected possible closure of 9 GW.

 SNL Financial (Feb 2011) report identifying 14,000 MW to retire between 2011 and 2020.

 Brattle Group‘s forecast that 67,000 MW of existing coal-fired power plants to retire in 

same timeframe.

 Black & Veatch‘s December 2010 analysis stating that 52,000 MW of coal capacity would 

retire. 

 FBR, Capital Markets‘ expectation that 45,000 MW of coal capacity to retire by 2017.

 BPC, March 2011 29-35 GW total retirements,

 EEI, January 2011 46-56 GW total (24-34 GW incremental retirements)

 CRA, December 2010, 39 GW total retirements

 DOE, James Wood, deputy assistant secretary for the U.S. Department of Energy, comments 

at the Eastern Coal Council‘s Annual Conference May 2011, 30-75 GW

These publications are significant because they show that in setting the Utility MACT standard 

the EPA has not adequately addressed the impact of the rule on the electric utility industry, given 

that costs are considerably more expensive for smaller units. This suggests that U. S. EPA 

modeling is subject to strong confirmation bias in favor of U. S. EPA‘s ideal outcome.

 

49 http://www.epa.gov/ttn/atw/129/ciwi/fr21mr11.pdf
43

APPA believes that the U. S. EPA should acknowledge that the price per MW of compliance 

increases as the size of generating unit decreases.

50 This means that smaller generating units 

will be impacted more highly in their decision to comply with EPA‘s toxics rule. This 

disproportionately large impact poses a much more serious compliance hurdle for small 

communities that depend on coal fired generation to meet their base load demand. As can be seen 

in the excerpt from the Bernstein and EPRI data analysis in Exhibit 2 below, coal plant retrofits

for SOx control technology cost, on average, three times more per MW when performed on 

smaller generating units. In addition, the price of compliance doubles for NOx control equipment 

as the size of the unit approaches 50 MW. APPA believes that the EPA did not adequately 

consider the disproportionately large cost of compliance on small communities.

Source: Bernstein Research coal plant SO2 control retrofit analysis of capital cost by generating unit size

These disproportionately higher costs for smaller and medium-sized municipal utilities were 

missed by the U. S. EPA in its own technical and economic analysis. In addition, the U. S. EPA 

has missed the critical factor that cities are in a time of great financial stress due to falling tax 

revenue from fewer sales and declining property taxes. According to Meredith Whitney,

51

―While over the past 10 years state and local government spending has grown by 65%, tax 

receipts have grown by only 32%.‖ Ms. Whitney‘s statement certainly confirms the hundred of 

press stories about municipal governments reporting lower tax receipts and layoffs. Some of the 

public power communities with electric utilities have also faced significant declines in property 

taxes and sales tax receipts.

8. APPA believes that the U. S. EPA‘s estimate of benefits and costs resulting from this proposed 

rule exaggerate the human health benefits dramatically because of its inclusion of PM2.5. 

Additionally, APPA believes that the costs were underestimated by not including many 

smaller utilities in the sampling or ICR run.

9. APPA believes that the MACT new source limits were unrealistic and miscalculated based upon 

contractor errors (See UARG letter to U. S. EPA, dated May 6, 2011 in Appendix I.) While 

APPA is pleased that the EPA has corrected, by letter, the new unit emissions, APPA notes 

that the EPA has not corrected all errors found in the proposed rule. Such errors make it all 

the more risky for a utility to make business decisions now based upon a proposed rule.

10. APPA believes the U. S. EPA should be commended for using work practices in lieu of CO 

limits but we do ask EPA to consider UARG‘s technical comments. APPA recommends that 

 

50 U.S. Utilities: Coal-Fired Generation Is Squeezed in the Vice of EPA Regulation; Who Wins and Who Loses?, BernsteinResearch, 2010

51 ―The Hidden State Financial Crisis,‖ Wall Street Journal online publication, May 18, 2011
44

the rule includes an alternate surrogate CO limit for additional compliance demonstration 

flexibility. A surrogate CO limit [if set at a reasonable level (i.e., 0.25 lbs/MBtu)] to demonstrate 

dioxin/furan best combustion control practices might be easier for EGUs with pre-existing CO 

limits.

11. The U. S. EPA did not adequately set subcategories for HCl, coal rank, and for rural and 

isolated power plants that may not have equal options for fuel. APPA also believes that

≤100 MW and peaking or limited use of (<30% annual capacity factor) units should have a 

separate subcategory.

12. The U. S. EPA did not adequately study the costs to the electric utility sector resulting from 

inability to sell or trade coal ash/coal combustions residuals due to sodium content in ash from 

DSI control technology. (See narrative and table 3 on pages 74-77 for details)

13. Though the U. S. EPA states that Regional Transmission Organizations (or RTOs) should 

―consider the full range of options to provide any necessary power replacement,‖ it is not 

reasonable to expect that the RTOs can produce the necessary engineering studies to determine 

the impact of U. S. EPA‘s rulemaking in the time allotted for comment. Nor is it reasonable to 

suspect that any remediation that might be required can be completed in time to allow units to 

retire.

For example, NERC standard FAC-013-2 states that a Planning Coordinator shall have a 

documented methodology it uses to perform an annual assessment of Transfer Capability in the 

Near-Term Transmission Planning Horizon (Transfer Capability methodology). That includes a 

description of how each of the following assumptions and criteria used in performing the 

assessment are addressed, generation dispatch, including but not limited to long-term planned 

outages, additions and retirements. This assessment, along with all of the many other 

assessments and studies, take time to perform. A study on a single retirement or a few 

retirements might be possible, but many retirements grouped into a few month span would 

certainly be difficult. A review of the generator retirement section of the PJM website shows that 

there are a number of problems that must be addressed before a generator can be successfully 

retired.

―Generator retirements alter power flows that often yield transmission line 

overloads. From a Regional Transmission Expansion Plan (RTEP) 

perspective, generation retirements announced coupled with steady load 

growth and sluggish generation additions can lead to the emergence of 

reliability criteria violations in many areas of PJM. Generating unit 

deactivations can contribute to the need for future, long-term baseline 

reliability transmission upgrades to mitigate reliability criteria violations.‖52

An analysis of the time it takes the PJM to respond to a generator request to shut down shows 

that without reliability issues they are able to remove a facility from the system within months.53

However, if multiple units are forced to shut down due to this rule it could cause problems with 

multiple impacts. Where a system is in need of generation at a location multiple retirements will 

cause significant delays and  ̳reliability must run‘ agreements might be needed. Some problems 

that might occur from multiple forced retirements or from significant downtime as a majority of 

the existing fleet upgrades to environmental control technology, include, but are not limited to:

 

52 http://pjm.com/planning/generation-retirements.aspx

53 http://pjm.com/planning/generation-retirements/~/media/planning/gen-retire/generator-deactivations.ashx
45

 N-1-1 Thermal Violations, 

 Generation Deliverability Violations, 

 Common Mode N-1 Contingency Thermal Study Violations, 

 Common Mode N-1 Contingency Voltage Study Violations, 

 CETO Voltage Study Violations, 

 N-1-1 Voltage Study Violations, 

 Short Circuit violations

APPA would like to note that the Texas Reliability Entity filed a report with the Texas PUC, 

documenting a major outage during the February 2-3, 2011 timeframe.54 This outage was 

extended by a lack of generator response during a cold weather event. This event is a chilling 

reminder that having generation offline for upgrades even during a low load season has its risks. 

APPA is concerned that EPA has not factored in these types of contingencies when it 

developed this final rule.

FERC and NERC are working together on an event analysis report detailing their conclusions and 

recommendations on the Texas generation failures. Their report is due out shortly. APPA will 

put a place holder in the appendices of these comments so that the FERC/NERC report may be 

given as additional materials. APPA will forward a copy of this report to the EPA docket when it 

is released. Since the report will be important in understanding the implications of reduced 

electric supply diversity, APPA feels the U. S. EPA needs to consider this report in this 

rulemaking.

NERC has filed with FERC a revision to its Critical Infrastructure Protection (CIP) Standards that 

may have bearing on the implementation of the U. S. EPA final rule. On February 10, 2011 

NERC submitted to FERC a revision to NERC Reliability Standard CIP-002-4.

55 This revision 

will designate approximately 400 additional generating units under the CIP standards for 

compliance with cyber security requirements.

 Generation greater than 1,500 MW (59 using CIP-002-3, 229 using this criterion) - 170 

additional units

 Blackstart resource identified in a transmission operator‘s restoration plan: (337 using 

CIP-002-3, 540 using this criterion) - 203 additional units

 Each generation facility necessary to avoid BES Adverse Reliability Impacts in the longterm planning horizon. (14 using CIP-002-3, 44 using this criterion) - 30 additional units

 Pending FERC approval, the anticipated affective date for compliance with this revised 

standard is 2013.

APPA is concerned that these 400 newly designated critical generation facilities will be evaluated 

for protection and compliance with NERC Reliability Standards at approximately the same time 

as the EPA final rule.56 APPA believes U. S. EPA should provide additional compliance 

options or a subcategory for units newly designated as critical under the NERC Reliability 

 

54 http://www.puc.state.tx.us/agency/topic_files/TX_RE_EEA_Protocol_Comp_Report.pdf

55 http://www.nerc.com/files/Final_Final_CIP_V4_Petition_20110210.pdf

56 Critical Asset: Facilities, systems, and equipment which, if destroyed, degraded, or otherwise rendered unavailable, would affect the reliability 

or operability of the Bulk Electric System. http://www.nerc.com/files/Reliability_Standards_Complete_Set.pdf
46

Standard CIP-002-4. Some of these newly designated units also may decide to shut down due 

to the crush of all these competing regulations, and APPA believes that U. S. EPA should provide 

additional time for studies to determine the reliability impacts of these retirements.

The list of newly identified critical assets will not be available as a public document due to the 

assets being classified as critical and protected under FERC‘s CEII requirement and the DHS 

PCII requirement.

1. Department of Homeland Security Procedures for handling Protected Critical 

Infrastructure Information (PCII); Final Rule September 1, 2006: 

http://www.dhs.gov/xlibrary/assets/pcii_final_rule_federal_register9-1-06-2.pdf

2. FERC Critical Energy Infrastructure Information (CEII)

 http://www.ferc.gov/help/filing-guide/file-ceii/ceii-guidelines.asp#skipnav

APPA would also like to note that current proposed NERC Critical Infrastructure Protection 

standards will create an additional cost that was not considered in the EPA‘s economic analysis. 

This cost may be significant and should have been considered as a part of EPA‘s RIA.

An additional consideration is the availability of reciprocating internal combustion engines 

(RICE) units to soften the blow that the large scale scheduling of outages and retirement of plants 

will likely cause. APPA has already commented on and requested reconsideration for the U. S. 

EPA‘s RICE rule. We hope that the considerations will be resolved in time to allow RICE use and 

that U. S. EPA will allow emergency operation of these engines to help ease the transition pains 

that will be experienced by utilities as a result of this rule. 

14. The EPA did not properly and thoroughly investigate and address the significant cost 

imposed on all businesses that consume electricity by this proposed rule, therefore it 

should attempt to address the unproductive costs of compliance that will occur due to RTO 

market structures. Since this rule will, by EPA’s own estimates, force the closure of many 

power plants that are often dispatched to meet demand (ie. the plants are determined to be 

efficient by the market mechanism), there will exist a higher probability for the dispatch of 

less efficient plants.

Any generator facing an increase in the cost to produce a megawatt-hour of electricity will 

increase their offer to sell electricity by at least a corresponding amount.57 This will include not 

only coal plants but also natural gas plants whose operating costs reflect increases in natural gas 

prices. Because the highest offer accepted in an hour sets the price for all megawatt-hours 

consumed, a single coal or natural gas plant can affect the prices paid for by all the 

electricity generated by nuclear, hydropower, wind, and all other plants within that hour. 

Power generated by plants that do not face any greater compliance costs will therefore still be 

sold at a price reflecting at least the compliance costs paid by other plants. RTO markets 

therefore create an entirely separate category of ―unproductive costs‖ on top of the actual 

compliance costs (also referred to by economists as ―economic rent‖ or the amount paid above

what is needed to keep a good or service in supply.) (See Section 15 for further explanations 

about electricity markets and the relationship of those markets to the costs that would be 

incurred by electricity consumers resulting from this rule.) APPA believes that the U. S. EPA 

 

57 Because there is no cost-based regulation of wholesale power prices, generators can offer to sell a megawatt-hour at a price that is greater or 

less than the actual costs of producing that power.
47

made no attempt to consider these market issues when assessing the costs of this rulemaking 

despite the fact that APPA met with U. S. EPA‘s chief EGU MACT and policy experts. 

15. The RTO market structures are less likely to lead to the construction of new units that U. S. EPA 

states will be needed to meet demand, and will also contribute to a greater level of plant closures 

than in other regions. Moreover, the capital costs of retrofits to existing plants will cause 

significant extra costs for consumers within RTO regions because the market structure will 

multiply these costs beyond just the actual compliance costs. For example, in the most recent 

Reliability Pricing Model (or RPM ) auction, held in May 2011 to procure capacity for the June 

2014 through May 2015 time period, a number of plants added to their supply offers the costs 

associated with installation of emission control technologies to meet environmental regulations. 

PJM estimated that these higher costs were responsible for at least half of the 350 percent 

price increase between the past two auctions in the western region of PJM, from $27.73 per 

MW/day to $125.99 per MW/day. Although the number of units or MWs that included these 

compliance costs is not yet available, PJM‘s graphical representation shows that of the roughly 

150,000 MW that cleared the auction and will receive this capacity price, about 120,000 MW 

offered to sell capacity at a zero or close to zero price. (Zero price offers are typically submitted 

by existing baseload plants who are price takers in the auction.) Therefore the half of the $98 

price increase attributable to environmental upgrades will be paid to all 120,000 MWs of 

capacity that did not include environmental compliance costs in their offers, equal to an 

unproductive cost of at least $2.1 billion for just one year. The U. S. EPA did not seem to 

capture the impact of these auctions in its cost analysis.

APPA points out that the U. S. EPA‘s own economic modeling relies on per unit compliance 

costs only and does not appear to have taken the multiplier effect of the RTO market structure 

into account, even though these markets will greatly expand the actual cost to consumers. These 

factual PJM auction results from May 2011 demonstrate that the U.S. EPA’s assertion that 

the electricity consumer will see no more than a 3.6% increase in the cost of electricity does 

not match recent actual market performance. The U. S. Census reports that currently there 

are 307,006,550 people in the United States and approximately 51 million of them live in the 

PJM Market. This means that approximately 15% of the United States population is affected 

by PJM Market and any U. S. EPA regulatory factors that cause an increase in capital 

expenditures. APPA believes it is significant that the U. S. EPA does not seem to account for the 

impacts of this market its projected cost analysis. For more detailed information on electricity 

markets, reference Appendix J (APPA‘s Neophytes Guide to Electricity Markets) and Appendix

K (Why New CO2 Regulations Could Produce Windfall Profits and Unproductive Costs for 

Consumers).

16. The EPA did not adequately consider the distinctly large regional cost impacts of their proposed 

rule. Figure 4 exemplifies how coal plant closures will have a much more severe impact in 

different locations. Figure 5 presents a clear picture of how prices will increase due to the 

combination of the U. S. EPA‘s Transport Rule and MACT Rule. These projected price 

increases disproportionately impact coal-dependant regions of the U. S.
48

Figure 4: Source - Data Dispatch, Feb. 22, 2011 (Used with permission from SNL Energy) See Appendix L for

more details.
49

Figure 5: Source – American Coalition for Clean Coal Electricity. Note: Price increase does not include RTO 

electricity market price increase.

17. U. S. EPA did not properly assess the reliability issues related to the transformation of the 

industry through both fuel switching to natural gas or retrofitting a significant number of 

power plants within three years. APPA has pointed out our concerns with getting pollution 

control equipment designed, procured, financed, installed and calibrated and in place in the 

three year compliance deadline. 

18. The U. S. EPA has some limitations placed upon it under the Clean Air Act that require a 

presidential extension of an additional year to be based upon national security concerns. In 

this instance, APPA assumes that national security would mean a significant concern about 

the reliability of the electric grid nationwide. APPA does not believe that there is a risk to the 

reliability of the entire national electricity infrastructure. APPA believes that the municipal 

utility sector (and perhaps some co-ops and IOUs) needs at least 5.5 years and perhaps as 

long as 77 months for planning, procuring, construction, installation, and calibration. APPA 

believes the presidential extension should be allowed on a utility-by-utility or case-by-case 

basis. This extension could be part of the time-constrained categorical extension talked about 

on page 62.
50

If the U. S. EPA fails to take the recommended actions to reduce the regulatory burdens of 

complying with the proposed MACT standards, APPA thinks it is critical for EPA to provide 

in the final rule for automatic compliance extensions to enable utilities, and particularly 

public power utilities to comply with the standard because of unique governmental 

administrative procedures that they must adhere to whether they retrofit or repower boilers. 

In this same vein, APPA observes that the Clean Air Act provides that the President has the 

authority under Section 112(i) of the Act to exempt any stationary source from compliance 

with any standard or limitation for a period of not more than two years if the President 

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

national security interests of the United States to do so. The law also provides that such 

exemptions may be extended for one or more additional periods, each period not to exceed 

two years. 42 U.S.C. §7412(i)(4).

19. U. S. EPA failed to adequately and properly assess the feasibility and cost impacts of fuel 

switching from coal to natural gas. APPA urges the U. S. EPA to seriously consider the 

infrastructure (pipeline and natural gas storage) issues and other concerns found in the APPA 

study Implications of Greater Reliance on Natural Gas for Electricity Generation, which can 

be found in Appendix M. APPA also suggests that the U. S. EPA staff evaluate the most 

recent articles regarding natural gas supply resulting from the June 2011 New York Times

stories.

58

20. U. S. EPA has failed to anticipate additional costs from closure of coal-fired power plants in 

the PJM and other RTO markets where fuel switching to natural gas and early retirement 

without replacement of other units would result in substantially and disproportionately higher 

costs for millions of consumers.59 

21. The U. S. EPA proposes in its rule that this rule will have a positive effect upon 

unemployment. 

While APPA is not an expert on macro economic analysis on jobs, we are aware of the 

assertions of jobs to be lost on a state-by-state basis. The American Coalition for Clean Coal 

Electricity (ACCCE) took the EGU MACT proposed rule and the soon to be final Regional 

Transport Rule and determined that unemployment impacts far exceed the temporary jobs 

created under the U. S. EPA analysis. The ACCCE analysis will be submitted by the 

American Coalition for Clean Coal Electricity (Source: www.cleancoalusa.org). This

organization projects net nationwide employment losses (employment losses minus 

employment gains) totaling 1.44 million job years by 2020. Employment sector losses 

outnumber gains by more than four to one through 2020 due to the two rules. By contrast, 

U. S.EPA‘s analysis of employment for the MACT proposal says that, ―We expect that the 

rule ̳s impact on employment will be small, but will (on net) result in an increase in 

employment.‖ The U. S. EPA estimates a one-time increase of almost 31,000 construction 

jobs and an annual increase of 9,000 jobs in the electric sector.

22. U. S. EPA should not include start up, shut down and malfunction in its proposed 

standards. This would render the proposed standards inherently tighter than they 

appear on paper considering the time per year of start ups, shut downs and 

malfunctions. This is especially a concern because of the increasing number of ―loadfollowing‖ coal-fired power plants backing up wind and solar power plants. The ramping up 

 

58 http://www.publicpower.org/files/PDFs/ImplicationsOfGreaterRelianceOnNGforElectricityGeneration.pdf

59 http://www.publicpower.org/files/PDFs/IssueBriefWindfallProfitsandEPARegsMarch2011.pdf
51

and down as well as the start up or shut down activities will increase emissions of many 

pollutants. 

23. U. S. EPA Should Provide for Streamlined NSR Procedures in the Final MACT Rule.

It is quite likely that modification of facilities to meet MACT standards, if they remain at or 

near to the levels proposed (in addition to modification of facilities to meet the Cross State 

Air Pollution Rule and New Source Performance Standards), could result in emission 

increases in one or more pollutants subject to the regulation under the federal New Source 

Review/Prevention of Significant Deterioration Clean Air Act preconstruction program or 

state ―minor NSR programs‖ administered through federally enforceable state 

implementation plans (SIPs). We anticipate increases are most likely to result from pollution 

control changes that will produce increases in carbon monoxide, greenhouse gases, and/or 

nitrogen oxide from power to operate pollution control equipment or new natural gas-related 

equipment. As the U. S. EPA is aware, a Federal Court of Appeals held in New York v. EPA, 

New York v. EPA, 413 F.3d. 3 (D.C. Cir. 2005) stated that pollution control projects are 

subject to New Source Review like any other plant modification. Because preconstruction 

permitting under the PSD/NSR takes between 14 months-to-5 years to complete, and 

generally with respect to electric generating units of any kind, engenders permit objections, it 

would be beneficial for U. S. EPA to streamline NSR procedures to the greatest extent 

provided by law. This could be accomplished by general permits that states could adopt now, 

a FIP for NSR permits for MACT, and/or schedules for expediting the receipt, determination 

of permit completeness (with a checklist) and release for public comment of PSD/NSR 

applications. Failure to address the possible delays from PSD/NSR permitting in this 

rulemaking could add additional time for sources to operate in compliance with the final 

regulation.

24. APPA Members Experience Unique Issues with Respect to Complying with the 

Proposed MACT Standard for Existing Units, Particularly If U. S. EPA Fails To Take 

the Recommended Actions To Reduce the Regulatory Burdens of Complying with the 

Proposed MACT.

Section 112(d)(4) of the Act provides that the Administrator may distinguish among classes, 

types, and sizes of sources within a category or subcategory (of an industrial sector) in 

establishing MACT standards. We acknowledge that this ability to subcategorize, which 

U. S. EPA has already used to subdivide the industry sector by type of fuel and size, shall not 

be used under Section 112 (d)(1) for purposes of authorizing extensions. However, we 

believe that U. S. EPA has authority to use its discretion to establish emission limits for types 

of sources, based on ownership and location, that it has not recognized and can address some 

of the unique issues that not-for-profit utilities face, including but not limited to the 

ownership, size of communities served, and most importantly, location. We suggest that U. 

S. EPA must examine these issues carefully and determine standards based on the criteria 

enumerated in Sections 112(d)(2) and (d)(3) for these sources. 

As APPA‘s comments have already described, the majority of public power generators are 

small entities as defined by federal law. They are all not-for-profit. Seventy percent of 

public power systems are located in cities with populations of 10,000 or less, and a significant 

percentage of these systems are located in rural locations, including Alaska, Guam, Puerto 

Rico and American Samoa. In cities and townships, electric generation is generally located 

in the center of town, bounded by railroad easements and private property. These 

characteristics of our members‘ operations have several significant consequences for public 
52

power and rural electric cooperatives that will make compliance with the proposed standards 

uniquely difficult: 

(1) Many municipal utilities are space-constrained and cannot build laterally. They must 

build vertically, but this makes construction of dry scrubbers, ESPs and fabric filters 

technically infeasible. If the U. S. EPA were to examine the group of facilities as a 

subcategory, it is likely that the agency would set a different floor for this subcategory of 

utility.

(2) Most of these facilities have only two boilers and possibly off-site gas turbines for 

peaking. Quite a few also own wind and/or solar generation that provides an interruptible 

power supply. As a consequence of state and federal requirements these operators can 

take only one unit off-line at a time for refurbishment and retrofit or repowering.

(3) These communities are generally not located near natural gas pipelines, except in the 

southwest and isolated areas in the northeast. As a consequence of their size, 

infrastructure is not likely to come to them so that they can avail themselves by

repowering units. 

APPA submits that U. S. EPA has ignored these significant distinctions and the level of 

controls that are and can be achieved by these distinct parts of the utility industry. In part, 

this is a result of inadequate scoping and review under the Unfunded Mandates Reform Act 

(UMRA) and SBREFA, discussed earlier in these comments. On this basis, we urge the U. S. 

EPA to re-propose the MACT rule to reexamine not only the regulation of pollutants other 

than mercury, but to reexamine the subcategorization of the industry by ownership and 

location. If this examination is done properly, the MACT floor for units based on their 

footprint and location will be vastly different than the level of emissions control achieved for 

larger non-rural power plants.

APPA’s Technical Comments on the Proposed Rules

I. Rulemaking Background

A. U. S. EPA has rushed its own regulatory schedule and is under no court order. APPA believes 

it is simply not true that the U. S. EPA must propose/finalize the MACT rule as quickly as 

suggested in the proposal. APPA believes the judge who presided over the consent decree for 

proposal and timing made it clear that the U. S. EPA would be given more time if technical or 

scientific issues necessitated it.

II. The Clean Air Act

A. APPA defers to the UARG letter on the legal and policy issues related to the various Clean Air 

Act programs, including the interplay of NSPS, NAAQS, PSD (BACT) and nonattainment 

programs, such as Lowest Available Emissions Rate (LAER), and how the EPA has confused 

these discreet regulatory programs and tried to insert into the proposed EGU MACT rule ways 

to reduce PM2.5 etc. APPA believes that the U. S. EPA has exaggerated the health and 

economic benefits of the proposed rulemaking by asserting benefits from PM2.5 controls and 

from control of other pollutants, such as acid gases.

APPA believes that the U. S. EPA should address PM only under ambient standards that are 

set to protect human health under an adequate margin of safety. That is to say, since PM2.5 is 

a criteria pollutant, it has no place in a regulatory schema for HAPs, even as a co-beneficiary. 
53

Any PM emission limitations should be justified within the context of PM regulatory 

programs. Similarly, reductions of HAP compounds – those specifically listed by Congress in 

the Act – should stand on their own merits as well.

B. The Clean Air Act‘s utility study [and U. S. EPA‘s related Great Waters Study along with 

assessment of the Section 303(d) waterbody segments listing of noncompliant waterbodies in 

the Clean Water Act,] justified only mercury reduction through the MACT program. U. S. 

EPA‘s own utility study said ―The report indicates that, although uncertainties in the analysis 

exist, on balance, mercury from coal-fired utilities is the hazardous air pollutant of greatest 

potential public health concern.” The U. S. EPA‘s utility study did not justify additional acid 

gas controls, PM 2.5 controls or other controls through new NSPS regulations.

See U. S. EPA‘s Source: http://www.epa.gov/ttncaaa1/t3/reports/utilfs.pdf APPA strongly 

believes that the U. S. EPA far exceeded its statutory authority to propose MACT for 

non-mercury metals and acid gases. (See Section IV below) 

C. As a member of UARG, APPA defers to the legal analysis and critique of Section 111, 

including discussion of subcategorization, factors that must be analyzed (degree of emissions 

reduction achievable, cost, non-air quality health and environmental impact, energy 

requirements, adequate demonstration of technology). 

III. General Policy Considerations

A. Effects on economy of making it difficult or impossible to permit or build a new coal-fired 

power plant. 

B. Problems associated with essentially mandating certain technologies or making certain 

technologies are obsolete.

C. The U. S. EPA has utilized its statutory authority to propose area source controls (GACT) for 

the power sector. These GACT controls would be less expensive than the control technologies 

in the proposed rule for many pollutants. The U. S. EPA failed to avail itself of its ability to 

use GACT controls and subcategorize adequately to help either the smaller utilities or the 

larger utilities.

GACT controls have been used successfully in many other U. S. EPA MACT rules including the 

following industries:

 Iron & Steel Foundries

 Electric Arc Steelmaking

 Coatings Operations Area Source Controls Rule

 Clay Ceramics Manufacturing

 Glass Manufacturing

 Secondary Nonferrous Metals Manufacturing

 Paint Stripping & Miscellaneous

IV. U. S. EPA’s Proposed Particulate Matter NSPS (APPA defers to UARG on the legal analysis and 

policy comments on the NSPS.)

A. Background

1. New and reconstructed boilers. The current NSPS allows three ways to comply:

(1) 0.015 lb/MBtu; (2) 0.14 lb/MWh (24-hr average); or (3) 0.03 lb/MBtu and a 99.9% 

reduction.
54

a. The U. S. EPA proposed a total PM NSPS of 7.0 ng/J or 0.055 lb/MW-hr 

(0.006 lb/MBtu). PDF, p. 655. The limit is proposed to be a summation of 

Method 5 (filterable PM) plus Method 202 (condensable PM) and includes 

periods of startup/shutdown/malfunction. PDF, see pg. 487-88 of the prepublication version of the proposed EGU rule.

b. The U. S. EPA is considering a range between 15 ng/J to 5.0 ng/J (0.004 -

0.034 lb/MBtu) for the final rule.

2. Modified boilers. 

The current NSPS requires achieving 0.03 lb/MBtu and a 99.8% reduction.

a. The U. S. EPA proposed a limit of 15 ng/J (0.034 lb/MMBtu). 

b. This is more stringent than the proposed limit for new units, and is likely an 

error. The U. S. EPA erred in the proposed regulatory language (§ 60.42Da 

(f)(2)) for modified units. The proposed limit of 0.034 lb/MMBtu could 

possibly be 0.13 lb/MBtu and was converted incorrectly from 15 ng/J. 

Alternatively; the limit of 15 ng/J was converted incorrectly from 0.034 

lb/MMBtu. 

B. U. S. EPA Should Rescind Its Proposal and Repropose its Defective NSPS Rule

1. U. S. EPA misstated the limit for modified boilers. The regulated community cannot 

provide intelligent comment on the agency‘s proposal and therefore the U. S. EPA 

should rescind its proposal and repropose the rule after correcting these defects.

C. U. S. EPA’s Choice of Best Demonstrated Technology Is Contrary to Law

APPA defers to UARG in the more thorough analysis and critique of the EPA‘s choice in 

combining technologies to define Best Demonstrated Technology (BDT). 

1. U. S. EPA may not require a combination of technologies to be BDT.

a. U. S. EPA based its NSPS for new and reconstructed units on a combination of 

four technologies -- fabric filters, FGD, dry sorbent injection and wet ESPs. 

The Agency based its NSPS for modified units on a combination of FGD and 

fabric filters.

b. The ―best system of emission reduction‖ under §111(a)(1) does not allow U. S. 

EPA to base the NSPS on a combination of technologies and EPA has not 

attempted to do so in the past. 

D. U. S. EPA erred in not calculating correctly in settings its preferred Best Demonstrated 

Technology.

APPA defers to UARG‘s more thorough comments addressing the failure to calculate properly 

in setting the Preferred Best Demonstrated Technology.

1. U. S. EPA claims the NSPS are ―cost free‖ because the proposed PM NESHAP limits 

for new units are as stringent or more stringent. Yet §111(a)(1) requires EPA to 

―tak[e] into consideration the cost of achieving such reduction . . . .‖

2. The cost of adding, e.g., a wet ESP or dry sorbent injection after a new unit has 

installed fabric filters and FGD is likely so expensive that the gency‘s BDT is arbitrary 

and capricious. APPA defers to the analysis provided by UARG on costs of this 

selection of technologies making up BDT. That analysis is provided in UARG‘s 

comments or appendices.
55

3. The cost of adding a fabric filter or FDG to a modified unit that has ESPs but does not 

already have an installed fabric filter or FDG is likely so expensive that the Agency‘s 

BDT is arbitrary and capricious. APPA defers to the technical analysis and cost 

materials provided by UARG in their separate comments.

4.(a)EPA has not identified what the condensable is and how to control it, so the agency 

cannot identify BDT or set an NSPS. (b) EPA‘s proposed rule eliminates ESPs as a 

control option.

1. APPA defers to UARG‘s more detailed comments regarding technical work to 

be completed both for new (proposed as 0.006 lb/MBtu) and for modified 

units.

2. APPA defers to UARG regarding U. S. EPA‘s option that ESPs should be 

retained as a control option.

E. APPA agrees with UARG that the U. S. EPA’s proposed NSPS is not achievable

1. Analysis is provided in the detailed comments to explain that the U. S. EPA used the 

top 20th percentile of performance test data because no one is ―specifically attempting 

to control condensable PM beyond eliminating the visible blue plume.‖ In addition,

EPA seems to have changed its method to calculate achievability.

2. APPA defers to the UARG analysis and agrees that this shows that limits lower than 

the proposed NSPS are not achievable.

3. U.S. EPA used the entire population of ICR PM data as its basis to propose NSPS.

The data for these units differ from those employed for SO2 and NOx in that most data 

sets are limited to three independent, discrete measurements. A significant challenge in 

using data from these reference units is properly accounting for variability due to both 

unit operation and measurement capability.

60

 

U. S. EPA‘s methodology for proposing its Total PM NSPS of 0.055 lb/MWh for new 

and reconstructed units is unclear. The ―BDT‖ selected by U.S. EPA for Total PM -- a 

combination of a fabric filter with coated or membrane filter media bags, FGD, dry 

sorbent injection (DSI) and a wet ESP -- has been installed at a single coal-fired unit 

(Dallman Unit 4).61 It appears that U. S. EPA has arbitrarily selected the top 20th 

percentile of performance test data on the basis that no one is ―specifically attempting 

to control condensable PM beyond eliminating the visible blue plume.‖ 76 Fed. Reg. at 

25,064, col. 3. In addition, the variability ―analysis‖ for the agency‘s proposed Total 

PM standard appears to be based on an assessment of data obtained from a single 

facility ( J. K. Spruce ) without any attempt to evaluate the national boiler population 

with respect to variability in fuel, plant operation, age and other key variables.

62

UARG provided U. S. EPA in January 2011 with an analysis based on the ICR data 

concerning a filterable PM rate that can be achieved by both a fabric filter and a wellperforming ESP at new units.

63 APPA agrees with this analysis. Starting with an 

average emission rate of 0.011 lb/MMBtu and factoring in the variability for this type 

 

60 Id. at Section 4.

61 Id. In addition, wet ESPs are operating on only two units in addition to Dallman, one of which has a design that is very different from 

conventional designs for utility boilers. Id.

62 Id.

63 Id. at Figure 4-1, reproduces data submitted in the January 2011 paper.
56

of measurement, a filterable value of 0.015 lb/MMBtu should be used – the same as 

the 2006 NSPS.

64

With respect to modified units, U. S. EPA states the Total PM value of 0.034 

lb/MMBtu represents no real adjustment or change to control technology deployment 

compared to the 2006 NSPS. However, U. S. EPA‘s proposed Total PM limit is not 

limited to filterable PM and includes condensable PM. U. S. EPA has provided no data 

to suggest that the 2006 NSPS, which allows compliance by achieving both 0.03 

lb/MMBtu and a 99.8% reduction, can be improved. 

V. Proposed Revisions to SO2 NSPS

A. Background

1. New and reconstructed boilers. For most units, the current NSPS is 1.4 lb/MWh (0.16 

lb/MBtu) or a 95% reduction.

a. U. S. EPA proposed 1.0 lb/MWh (0.11 lb/MBtu) (30-day roll) or a 97% 

reduction. PDF, p. 504. The NSPS includes periods of startup, shutdown and 

malfunction. PDF, pp. 487-88 of pre-publication copy.

b. U. S. EPA is considering a range between 0.80 – 1.2 lb/MWh and a percentage 

reduction between 96–98% for the final rule.

2. Modified and new coal refuse units. U. S. EPA proposes retaining the current NSPS.

a. APPA believes that UARG has better expertise on U. S EPA‘s assertion that 

they should preserve the ability to use spray dryer FGDs for modified units. 

APPA defers to UARG‘s comments. 

B. APPA believes that the U. S. EPA should rescind its proposal and repropose its defective 

NSPS rule

1. It is unclear to APPA in the proposal what technology U. S. EPA considers to be best 

demonstrated technology. For the fixed emission rate it may be dry FGD. The U. S. 

EPA does not clearly state the technology on which it bases its percentage reduction 

standard. The U. S. EPA rushed the proposed rule process without sufficient time to 

propose a coherent rule and intends to finalize it in November 2011 without sufficient 

time to correct the defects in the proposal. APPA points to this as one of many data 

errors that resulted from too short of a preparation time and an improperly 

designed schedule for proposal and final rule.

2. Without knowing BDT, the regulated community cannot provide intelligent comment 

on whether the emission limits are achievable or whether the costs of the technology 

are reasonable under § 111(a)(1). APPA believes that the U. S. EPA should rescind 

its proposal and re-propose the rule after correcting these defects in its proposed 

rule. APPA does not believe it is realistic for local governments to commit to 

purchasing control technology equipment, finance, permit, install and calibrate within 

three years given local governance rules on procedure and current economic problems.

 

64 Id.
57

C. EPA erred in not calculating a cost for its preferred Best Demonstrated Technology 

1. The U. S. EPA claims the NSPS are ―cost free‖ because the proposed SO2 NESHAP 

limits for new units are as stringent or more stringent. (PDF, pp. 538-39 of preproposed rule.) Yet § 111(a)(1) requires EPA to ―tak[e] into consideration the cost of 

achieving such reduction . . . .‖

2. The U. S. EPA failed to do any cost analysis, so the proposed rule is arbitrary and 

capricious.

D. The Proposed NSPS Are Not Achievable

1. APPA reminds the U. S. EPA that UARG provided comments in January, 2011 on 

what could constitute NSPS. A link to those UARG comments is 

http://www.publicpower.org/files/PDFs/UARGSCR_FGDFinal.pdf and a copy of this 

set of comments (in a study) is attached in Appendix F.

APPA reminds the U. S. EPA that in UARG‘s analysis they analyzed similar units and 

found that achievable NSPS are 1.3 lb/MW-hr (0.14 lb/MBtu) with a 96% removal 

efficiency.

2. APPA agrees with UARG that the U. S. EPA‘s variability analysis of fixed rate data is 

not consistent with past rulemakings.

3. It is fundamental to the implementation of CAA § 111 that any NSPS must be 

achievable. Portland Cement Ass’n v. Ruckelshaus, 486 F.2d 375, 402 (D.C. Cir. 

1973). An NSPS represents the best technology available nationwide, regardless of 

specific fuel, climate, water availability, and many other highly case-specific factors.

As discussed below, U. S. EPA‘s proposed NSPS for SO2 are not achievable on a 

nationwide basis, and the final rule needs to be revised upwards because the proposed 

rule is much too low.

The UARG white paper submitted to U. S. EPA in January 2011 analyzed SO2 

emissions from representative units and concluded that combustion controls and FGD 

at 24 new units and 32 retrofitted units could achieve 1.3 lb/MW-h (0.14 lb/MMBtu) 

and a 96% removal efficiency.

65 To justify its proposed revisions to the NSPS for 

SO2, U. S. EPA selected existing units that retrofit FGD technology and new units that 

integrate the FGD process design into the plant. Tables 17 and 18, 76 Fed. Reg, at 

25,065. A disadvantage of utilizing only new units to evaluate SO2 emissions is that 

both the control technologies and fuel represented are not representative of the fuels 

and conditions on a nationwide basis. The trend for newer units has been to locate 

them in western states, with improved access to PRB coal and perhaps less access to 

water. This trend biases the selection of SO2 controls at the newest units to limebased dry FGD.66 Analyzing both new and recent retrofits to existing units 

provides a broader spectrum of controls and fuels, and reflects the use of eastern 

bituminous coals and wet FGD.

As explained in detail in the report by Cichanowicz to the Utility Air Regulatory 

Group, of which APPA is a member, neither the eight new units that U. S. EPA 

 

65 Cichanowicz, Discussion of Factors Affecting New Source Performance Standards for SO2, Particulate Matter, And NOx At Utility Steam 

Generating Units (January 2011).

66 Id. at ___.
58

examines (Table 18) nor the 15 existing units that the Agency considers (Table 

17) reflect the full suite of designs, fuels and conditions for the coal-fired boiler 

population in this nation.

67 The report can be found in Appendix N. One new unit

(Spurlock Unit 3) has a fluidized bed design that is atypical of pulverized coal boilers 

and which inherently provides SO2 removal through the limestone-containing 

bubbling bed. Both the magnitude and variability of the SO2 emissions from 

fluidized bed designs are unrepresentative of pulverized coal boilers and such 

units should either be eliminated from consideration or used in a separate 

subcategory for this boiler design.

Five of the remaining new units are virtually identical in firing PRB coal and using 

lime-based dry FGD with a fabric filter. This combination of coal and equipment 

provides stable and well-controlled SO2 emissions.68 However, it is inappropriate to 

set a standard for all new coal-fired boilers that is based on this single full/control 

technology combination. Additionally, the final two new units (Cross Units 3 and 4) 

in U. S. EPA‘s database are virtually identical in design and both fire eastern 

bituminous coal with moderate sulfur content. Thus they provided only limited 

information about non-PRB units. There are similar problems with the existing 

units.69 APPA urges U. S. EPA to base its decision on the final NSPS using the 

larger and more comprehensive data set that it has available, and that was 

provided by UARG, including three new units not considered by U. S. EPA (Elm 

Road, Oak Grove and Dallman).70

U. S. EPA’s methodology in determining its proposed NSPS for SO2 improperly 

accounts for variability. Table 17 reports for 15 units the highest 30-day SO2

removal efficiency average based on daily averages of SO2 emissions and monthly 

averages of coal sulfur content. As explained in detail in the Cichanowicz Report,71

U. S. EPA’s SO2 removal efficiency cannot be considered a 30-day rolling average 

but an amalgam of daily and monthly “block” averages. Of the 15 units in Table 

17, 10 report only 12 months of operation and thus provide only 12 truly discrete data 

points. Under this approach, a standard is proposed that new units would only be 

able to meet 92.7% of the time for any one unit – a threshold well below the usual 

99% compliance rate historically used when setting NSPS. U. S. EPA has historically 

understood that achievability of any emission standard requires that there be an 

appropriate increment or ―margin‖ above the mean emission level that takes into 

account the statistical properties of the emissions data and the time dependence (auto 

correlation) of the data. Among other things, the achievable emission limit is a 

function of the assumed accepted number of violations of the regulatory limit, which 

is a measure of the risk of noncompliance. This means U. S. EPA’s 97% SO2 

removal rate is at odds with U. S. EPA’s historical methodology in NSPS 

rulemakings, and results in a proposed NSPS that is not achievable because there 

is a certainty that many units will regularly exceed the proposed NSPS.

U. S. EPA’s selection of a 1.0 lb/MWh emission rate is without any statistical 

basis and seems to have been selected as the mid-point between new facilities 

 

67 Id. at ___.

68 Weilert, C., et al., Emissions Control Performance Achieved in Electric Utility FGD Systems in the United States, Proceedings of the 2010 

Power Plant Air Pollution Control "Mega" Symposium, August 30-September 2, 2010, Baltimore, MD.

69 Cichanowicz Report, p. 58

70 Cichanowicz Report, Table 2-1.

71 Id. at __.
59

burning medium sulfur coals and several dry FGD, PRB-fired units.

72

Accordingly, two new generating units with advanced FGD that fire medium-sulfur 

coals (Cross Units 3 and 4) could not meet either the fixed SO2 outlet rate or the 

percent SO2 removal, a clear indication that U. S. EPA‘s proposed NSPS for SO2 is 

not achievable. U. S. EPA should apply UARG‘s and EPA‘s historical approach to 

variability.

UARG has provided the 30–day SO2 average for the new unit pool, based on 

calculations defining the 95% and 99% confidence limits for each of the subject 

units.73 The resulting standards range in value from 0.029 lb/MMBtu to 0.223 

lb/MMBtu, and average 0.119 lb/MMBtu. Given a typical new unit heat rate of 9,500 

Btu/kWh, this translates into an output-based SO2 emission rate – not accounting for 

emissions during startup - of 1.13 lb/MWh. Similarly, 32 units that were used as the 

basis for a recent BACT analysis indicate that EPA‘s proposed NSPS, when subjected 

to a statistical procedure to derive a UCL for 99% confidence limit, should be 0.130 

lb/MMBtu (equivalent to 1.2 lb/MWh), not 1.0 lb/MWh.

This discussion does not consider the fact that the U. S. EPA includes periods of 

startup in the proposed NSPS. UARG has evaluated the effect of including 

startups for 14 units equipped with state-of-art wet limestone FGD process 

equipment. UARG learned that SO2 emissions can increase the value of the first 

30-day calculated rolling average, from 1% up to 16%, and by an average of 

8%. In one-third of the cases analyzed, the first calculated 30-day SO2 emissions 

average was increased by 10% or more above the value that would be calculated in the 

absence of including startup data.

74 SSM should be excluded or the values of SO2

emission rates should be increased to at least 1.30 lb/MWh to account for SO2

startup. Otherwise, the U. S. EPA‘s proposed NSPS for SO2 are not achievable as a 

national standard. 

VI. Proposed Revisions to NOx NSPS

A. Background

1. New units. The current NSPS is 1.0 lb/MWh. Reconstructed units. The current NSPS 

is either 1.0 lb/MWh or 0.11 lb/MMBtu. Modified units. The current NSPS is either 

1.4 lb/MWh or 0.15 lb/MMBtu.

2. The U. S. EPA proposed a NOx NSPS of 0.70 lb/MWh (based upn 30-day roll) for 

new, reconstructed and modified units. This includes periods of startup, shutdown and 

malfunction. 

a. The U. S. EPA is considering a range between 0.60 – 0.90 lb/MWh for the 

final rule. Best demonstrated technology is combustion controls plus SCR.

3. The U. S. EPA is also proposing its alternative and preferred approach for new and 

reconstructed boilers of 1.2 lb/MWh (0.13 lb/MBtu) for NOx + CO

a. This standard is derived from 0.08 lb/MBtu NOx; 0.05 lb/MBtu CO (70

ppm @3% O2)

4. The U. S. EPA is also proposing its alternative and preferred approach for modified 

boilers of 1.8 lb/MWh (0.20 lb/MBtu) for NOx + CO

 

72 Id. at __.

73 Id. at Table 2-1.

74 Id. at Table 2-2.
60

a. This is derived from 0.08 lb/MBtu NOx; 0.12 lb/MBtu CO (160 ppm @3% O2)

B. The Proposed NSPS Are Barely Achievable (Given Current Technologies)

APPA defers to UARG‘s analysis, provided to the U. S. EPA in a white paper in January 

2011. UARG analyzed similar units and found the NSPS should be 0.7 lb/MWh. APPA 

believes that the final NSPS should be no lower than the U. S. EPA‘s proposal and that 

the final NSPS should be higher for modified units.

VII. U. S. EPA Should Use Gross Output, Not Net Output, to Set NSPS

U. S. EPA has proposed output-based NSPS for PM, SO2 and NOx based on gross energy output.

76 Fed. Reg. at 25,070, col. 3. Much of the parasitic power demands at coal-fired power plants is

needed to operate control equipment such as SCR reactors, scrubbers and baghouses that are 

required as a practical matter at all new coal-fired units. EPA states that it prefers using a netenergy output basis for new and reconstructed units because such an approach purportedly would 

―provide a greater incentive for achieving overall energy efficiency and minimizing parasitic 

loads.‖

In its 2005 NSPS proposal, the U. S. EPA recognized ―the monitoring difficulties in measuring 

net output.‖ 70 Fed. Reg. 9706, 9713, col. 1 (February 28, 2005). This remains an issue today. 

Many utility plants are comprised of multiple units and typically individual units are dedicated to 

the operation of specific equipment throughout the plant.75 These units may provide power for 

the air compressors for soot blowing in the plant, for the coal handling system, for induced and 

forced draft fans, or for plant service such as offices, station water, etc.76 The distribution of 

electricity throughout a plant is fed from auxiliary station transformers and then is distributed to 

the various load centers for power-consuming auxiliaries.77 Under a net output-based NSPS, it 

would be difficult, if not impossible, to account for the power distribution for a new unit at a site 

with existing units. The older units would not necessarily be equipped to monitor the power 

going to and coming from the new unit, as the new unit would require the power distribution 

systems to be monitored for the first time.78

U. S. EPA suggests that ―about 5 percent of station power is used internally by parasitic energy 

demands, but these parasitic loads vary on a source-by-source basis.‖ 76 Fed. Reg. at 25,070, col. 

3. Parasitic energy demands not only vary by source but also by duty cycle. As load decreases 

on a typical unit, the percent of parasitic power increases.79 Base-loaded units could take full 

advantage of the relatively low parasitic power losses at high loads but cycling or peaking units 

could not due to rapidly changing operating conditions and the fact that much of the time is spent 

at low loads.80 Any net output-based NSPS would have to be set at levels that are achievable 

under all potential operating duty cycles.

However, U. S. EPA should reject the use of a net energy output approach. Coal-fired power 

plants that are required by U. S. EPA‘s rules to use equipment to control PM, SO2 and NOx

should not be further penalized by subtracting the parasitic power to run them. There are also 

significant issues with a net output approach due to water issues. As Clean Water Act § 316(b) 

 

75 Memorandum from Lowell L. Smith to Craig S. Harrison, ―Impact of Net Output-Based NSPS‖ (June 2011), Attachment 1 (hereinafter 

―Lowell Smith Memo‖).

76 Id.

77 Id.

78 Id. If a new unit were to be constructed at a greenfield site, this would not be an issue.

79 Id. at Figure 1

80 Id.
61

regulations are implemented, power stations may be building more cooling towers, which would 

add significant parasitic load. Water processing and pumping activities can have a large parasitic 

load that varies widely among plants. Some plants would be unfairly penalized if they had to 

comply with a net-output based NSPS. 

At plants with older, less efficient units that supply power to various auxiliaries throughout the 

plant, imposing a net output-based NSPS on the new unit could actually decrease overall plant 

efficiency. The new unit would likely be much more efficient than the older units. Under a net 

output approach, the newer unit might not be used to supply power to the plant‘s auxiliaries 

because it would affect its net output emission level and jeopardize meeting the NSPS.81 This 

would rob the entire plant of an efficient source of power that could be used to replace 

power from less efficient units. U. S. EPA suggests that a net output NSPS would improve 

overall plant efficiency, but instead that approach could require a new unit to be operated as an 

island with virtually none of its power providing auxiliary support for other units. By instituting 

a net energy output based NSPS, U.S. EPA would be encouraging new units that may prove 

to be efficient, but overall the plant efficiency would not be optimized.

The U. S. EPA notes that a net output approach will be problematic with emerging technologies 

such as IGCC, but nonetheless makes a rough estimate that ―the efficiencies are comparable.‖ 76 

Fed. Reg. at 25,071, col. 1. Yet a net output-based NSPS would eliminate use of any 

technology that would cause the parasitic power on an EGU to marginally increase above 

its current levels. For example, carbon capture and sequestration (“CCS”) may have a 25-

30% parasitic power demand.82 U. S. EPA has been attempting to foster IGCC and CCS, and a 

net output energy approach would not encourage the deployment of these technologies. The 

notion that a net output energy approach would ―provide a greater incentive for achieving overall 

energy efficiency and minimizing parasitic loads,‖ id. at 25.070, col. 1, is misplaced. APPA 

strongly disagrees that utilities need a CAA regulation or any additional motivation to 

generate electricity as efficiently as possible. Public power utilities, due to their ownership 

structure, are already trying to maximize plant efficiency for the benefit of their customers. 

Finally, the U. S. EPA has announced plans to propose NSPS for greenhouse gases 

(“GHG”), including existing and new units, by September 30, 2011. U. S. EPA’s regulatory 

approach will likely focus on running coal-fired power plants as efficiently as possible. A 

GHG NSPS rulemaking would invalidate any rationale for requiring a net efficiency 

approach in Subpart Da.

For these reasons, APPA strongly objects to requiring a net output approach.

A. EPA requested comment on this issue with respect to new and reconstructed units.

APPA defers to UARG‘s more detailed comments on errors in methods to set NSPS based 

upon Gross Output. EPA has previously used gross output and APPA (and UARG) believe 

that it should have been used here again.

B. APPA defers to UARG that separate units should not be penalized for parasitic power from 

the use of control technologies. 

Such an approach would make NSPS especially stringent for coal (or natural gas fired) units 

that deploy geologic sequestration of CO2 (or CCS). While APPA remains skeptical that CCS 

will be commercially demonstrated for widespread application in the utility sector within the 

 

81 Id.

82 Id. at Figure 2
62

next decade, we certainly do not want to see the parasitic power issue make CCS less 

economical or attractive as a solution for CO2 due to the unintended consequences that might 

result in the EGU MACT rulemaking.

VIII. IGCC Units Should Continue To Be Regulated Under Subpart Da, Not Subpart KKKK

A. The U. S. EPA proposes that IGCC units that coproduce hydrocarbons or hydrogen be subject 

to the combustion turbine NSPS because using new output-based standards would be 

difficult. APPA is unaware of any APPA member with current IGCC projects. We defer to 

UARG and EPRI in any submittals on data for proposed IGCC facilities.

IX. APPA endorses UARG’s objection to adding petroleum coke to the definition of coal.

X. If U. S. EPA fails to take the recommended action to reduce the regulatory burdens of 

complying with the standards, the agency must provide compliance extensions to ensure that 

public power utilities can comply due to unique local governmental obligations to provide 

electricity to customers under law

XI. APPA Urges the U. S. EPA to Adopt Procedures for the Presidential Extension To Provide an 

Additional Two Years for Compliance.

If the U. S. EPA fails to take the recommended actions to reduce the regulatory burdens of 

complying with the proposed MACT standards, APPA thinks it is critical that the final rule 

provide automatic compliance extensions to enable utilities, and particularly public utilities, to 

comply with the standard. Public power utilities face unique governmental administrative 

procedures that they must adhere to whether they retrofit or repower boilers. In this same vein, 

APPA observes that the Clean Air Act gives the President authority under Section 112(i) of the 

Act to exempt any stationary source from compliance with any standard or limitation for a period 

of not more than two years if the President determines that the technology to implement such 

standard is not available and that it is in the national security interests of the United States to do so. 

The law also provides that such an extension may be extended for one or more additional periods, 

each period not to exceed two years. The Clean Air Act provides Section 112(i) that the President 

may exempt any stationary source from compliance with any standard or limitation for a period of 

not more than two years if the President determines that the technology to implement such 

standard is not available and that it is in the national security interests of the United States to do so. 

Such extension may be extended for more one or more additional periods, each period not to 

exceed two years. 42 U.S.C. §7412(i)(4).

APPA urges U. S. EPA to consider providing procedures for exercise of this Presidential 

option given the issues for public power operators we have described elsewhere in these 

comments, including but not limited to the administrative procedures for bidding contracts under 

municipal and state law, the eminent domain that some communities must exercise to access land 

for gas pipelines and/or transmission lines for new energy sources, issues with such public 

easements given the high density zoning in small municipalities, and general lack of electricity 

alternatives. These technical impediments to repowering and/or retrofitting publicly operated 

power plants and/or providing communities with electricity transcend technological and economic 

feasibility issues that APPA discusses elsewhere in these comments.

Procedures - We suggest that these procedures should involve requests from the mayor and the 

governor of each state for the proposed extension, with a demonstration of cause certified by the 

City Council or the State Attorney General and the entity requesting such extension. In other 
63

words, APPA submits that these procedures should be based on need and the demonstration of 

good faith progress toward compliance, not Clean Air Act technology-based showings. 

XII. Monitoring Issues (testing compliance and maintenance)

APPA fully supports UARG’s comments on the emissions testing, compliance and 

reporting provisions in the proposed rule. 

The proposed regulation would require installing up to three new monitoring devices in 

existing smokestacks. This would be in addition to at least three systems currently installed 

on these Title IV affected units83. EPA gives no impact evaluation on the safety issues 

surrounding drilling additional holes in existing stack and chimney liners. In the experience 

of one APPA member in the Midwest, following promulgation of the CAMR regulation, that 

utility had considerable difficulty finding a structural consultant who would stamp their 

imprimatur on drilling even one new penetration to install a mercury monitor alone. As it 

stands (for now, at least), one of those stacks is riddled with monitoring penetrations that 

comprise 33% of the stack circumference. 

Clearly, drilling three new penetrations would carry the risk of weakening chimney structure 

at EGUs across the nation. This poses not only a worker and community safety ramification, 

but also impacts grid reliability, considering the year or more required to erect a replacement 

stack and return the unit to operation. In consideration of these factors, APPA strongly 

suggests that units employing PM CEMS should be exempted from Federal and state opacity 

monitoring requirements. As recognized by recent New Source Performance Standard 

(NSPS_ revisions, APPA believes that there is no need for a particulate monitor in addition to

a surrogate particulate monitor. Since the vast majority of opacity monitors employ both a 

transmitter and a retroflector to double the monitoring pathlength, retirement would result in 

two opposing holes in which to deploy the new equipment envisioned by this rule.

Bottom line, APPA supports UARG objections to PM CEMS as untested and inappropriate 

technology, and UARGs assertion that if a unit chooses PM CEMS, they should not have to 

also monitor opacity. At a 0.01 PM limit, opacity is meaningless.

U.S. EPA’s Proposed Compliance Demonstration, Recordkeeping, and Reporting 

Provisions Require Clarification and Revision

Although U. S. EPA provides a number of compliance options, each option presents a 

number of issues. Moreover, the applicability of many requirements to those options is not 

clear. The numerous inconsistent provisions and the absence of articulated rationale deprive 

APPA and its members of a reasonable opportunity to comment. 

APPA agrees with UARG‘s comments that U. S. EPA must specify that the operating limits 

(including the operating load limit) apply only to EGUs using stack tests to comply or explain 

why those requirements are necessary for other units. APPA agrees with UARG‘s 

assumptions that the purpose of the operating limits is to demonstrate compliance between 

performance tests at EGUs that are not otherwise monitoring compliance with the relevant 

standard continuously (e.g., at EGUs not using CEMS or sorbent trap monitoring system). 

Proposed § 63.10011(b) states that ―if you demonstrate compliance through performance 

testing,‖ you must ―establish each site-specific operating limit in Table 4 . . . that applies to 

 

83 New monitors are specified for mercury, particulate matter, and hydrogen chloride gas. Existing monitors include opacity, flow, and 

SO2/NOx/diluent, which may or may not be combined in one probe. Some stacks also monitor moisture.
64

you‖ according to the requirements in § 63.10007, Table 7 to this subpart, and paragraph 

(c)(6) of this section, as applicable. 

Table 4 includes operating limits for various control devices. It also requires EGUs that 

―demonstrate compliance using . . . performance testing‖ to maintain their operating load 

such that it does not exceed ―110 percent of the average operating load recorded during the 

most recent performance test.‖ Proposed Table 4 (7), § 63.10007(c). 

However, since all EGUs are required to demonstrate initial compliance with each emission 

limit ―through performance testing,‖ and the proposed rule defines ―performance testing‖ to 

include the first 30 operating days of CEMS data, the proposal appears to require that EGUs 

meet operating limits for all relevant control devices and load regardless of the ―performance 

testing‖ option they choose. See, e.g., proposed § 63.10005(a) and Table 5 (including stack 

tests, CEMS, and LEES in the list of ―performance testing‖ options).

The other provisions cited in § 63.10011(b) provide little clarification. Proposed § 63.10007 

does not discuss applicability. With the exception of the filterable PM limit applicable to 

units using PM CEMS, Table 7 does not distinguish between compliance options. Instead, 

Table 7 refers to various parameters depending on which control device ―your operating 

limits are based on.‖ Section 63.10011(c)(6) addresses fuel sampling, not operating limits. 

Section 63.10011(b)(6), the provision U. S. EPA likely meant to cite, refers only to control 

devices and not compliance options. 

U. S. EPA‘s preamble discussion contains numerous inconsistent statements and no rationale 

by which one could determine U. S. EPA‘s intent with respect to these operating limits for 

units using CEMS and sorbent trap monitoring systems. 

APPA agrees with UARG that there is no known rationale for requiring sources that 

establish compliance with the non-Hg metal limit (using PM as a surrogate and PM 

CEMS, with the HCl limit using HCl CEMS or an SO2 CEMS, or with the Hg limit 

using Hg CEMS or a sorbent trap system) to also comply with an operating load limit, 

or with control device parameter operating limits for PM, HCl, or Hg controls. 

U. S. EPA Has No Basis To Require HAP Stack Testing for EGUs Using Surrogates Or 

To Require Surrogate Testing For EGUs Not Relying on Surrogates

Where a surrogate is used to demonstrate compliance (e.g., PM for non-Hg HAP metals, or 

SO2 for acid gases), U. S. EPA proposes to require rate testing for the applicable HAP 

―during the same compliance test period and under the same process (e.g., fuel) and control 

device operating conditions of the pollutant and surrogate.‖ Proposed § 63.10005(a). For 

example, sources using PM as a surrogate for non-Hg HAP metals must perform metals 

testing in addition to stack testing for total PM and establishing a filterable PM limit and 

demonstrating compliance with PM CEMS. Similarly, sources using SO2 as a surrogate for 

HCl must test for HCl in addition to the SO2 CEMS performance test. The testing must be 

repeated every 5 years. Proposed § 63.10006(a), (b); Preamble, 76 Fed. Reg. at 25,029. 

For EGUs that do not choose to use a surrogate, U. S. EPA proposes to require testing for 

surrogates anyway. For example, proposed § 63.10006(d) requires EGUs without PM 

CEMS, but with a PM control device, to perform annual tests for both PM and non-Hg HAP 

metals. Similarly, proposed § 63.10006(h) requires EGUs without SO2 CEMS to conduct ―all 

applicable performance tests‖ for SO2 and HCl annually and, for units with SO2 controls, to 
65

conduct SO2 emissions testing ―at least every other month.‖ See also Preamble, 76 Fed. Reg. 

at 25,051. 

These requirements are duplicative and must be removed. Where U. S. EPA has 

demonstrated the appropriateness of use of a surrogate, and selected an emission limit for that 

surrogate that is consistent with what the best sources achieve, there is no basis for also 

requiring the source to test for the applicable HAP. Preamble, 76 Fed. Reg. at 25,021. 

Where a source chooses to comply with the HAP limit, testing for surrogates is unnecessary 

and unreasonable. Both requirements also are inconsistent with Tables 1 and 2, which clearly 

establish surrogate emission limits as ―alternatives‖ to HAP emission limits and vice versa. 

Although U. S. EPA describes these duplicative testing requirements in the preamble, U. S. 

EPA again provides no rationale to support them. They must be removed. 

A. Summary of Compliance Options and Issues

1. For coal-fired units and solid oil-derived EGUs.

a. Options for Non-Hg HAP metals 

i. PM CEMS: 

(1) U. S. EPA’s proposed operating limit is not clear 

(2) EGUs are unlikely to pass PS 11 performance criteria at the levels 

expected 

(3) U. S. EPA should not require use of PM CEMS data to show 

compliance during startup and shutdown

(4) U. S. EPA must take measurement error into account when 

establishing a PM CEMS limit

(5) In light of the multiple measurement issues, EGUs should use PM 

CEMS data as indicator monitoring only

(6) U. S. EPA should provide alternative emission limits for PM, SO2, 

HCl and Hg during periods of PS 11 correlation testing

ii. Performance Stack Testing:

(1) U. S. EPA must remove the requirement for annual PM testing

The requirement for annual PM testing at EGUs that choose to comply 

with the non-Hg metals limit is not reasonable. U. S. EPA provides no 

justification for this requirement. Proposed Tables 1 and 2 clearly 

provide sources the option of meeting a PM or non-Hg metals limit. 

Testing for PM if no limit applies is nonsensical. Moreover, if non-Hg 

metals testing with Method 29 includes analysis of the impinger, any 

condensable metal will be measured by that test. U. S. EPA must 

remove references to PM testing under § 63.1006(d). 

(2) U. S. EPA should re-evaluate the proposed operating parameter 

requirements
66

(3) U. S. EPA should specify minimum detection limits for laboratory 

analysis and provide procedures for calculating combined 

concentrations of single metals and total non-Hg metals

b. Options for Acid Gases

iii. HCl CEMS

(1) Performance Specifications (PS) 15 and 6 are not applicable to HCl 

CEMs

U. S. EPA proposes to require certification of HCl CEMS according to PS 15 or PS 6. As 

U. S. EPA acknowledges in the preamble, PS 15 applies only to FTIR CEMS. PS 6 applies 

to continuous emission rate monitoring systems (CERM), which measure mass emissions rate 

per unit of time. In order to provide an HCl CEMS option, U. S. EPA says, ―we expect to 

publish [a performance specification] prior to the compliance date of this proposed rule and 

to make it available to source owners and operators.‖ 76. Fed. Reg. at 25,031.

FTIR CEMS is not a viable option and sources need a well-documented HCl performance 

specification well in advance of the compliance date in order to evaluate and procure 

appropriate instrumentation. APPA supports U. S. EPA‘s decision to convene a workgroup 

of interested stakeholders to aid in development of an appropriate performance specification. 

However, in the absence of an existing specification, U. S. EPA should recognize in the rule 

that PS 15 does not apply to HCl CEMS and allow EGUs to petition U. S. EPA for use of an 

alternative specification if none has been promulgated by the time EGUs need to make 

decisions about their compliance options. 

(2) U. S. EPA must clarify the subsequent performance testing 

requirements for units “without SO2 CEM”

Proposed § 63.10006(h) requires EGUs ―without SO2 CEMS but with installed systems that 

use wet or dry flue gas desulfurization technology‖ to conduct ―all applicable performance 

tests for SO2 and HCl emissions‖ at least every year and to ―conduct SO2 emissions testing‖ 

at least every month. Proposed § 63.10006(i) requires EGUs ―without SO2 CEMS and 

without installed systems that use wet or dry flue gas desulfurization technology‖ to conduct 

―all applicable performance tests for SO2 and HCl emissions‖ at least every year and to 

―conduct HCl emissions testing‖ at least every month. 

U. S. EPA must make clear that these provisions do not apply to EGUs with HCl CEMS. As 

discussed above, there is no basis for testing of the surrogate SO2 at a unit that is complying 

with the HCl standard or for HCl emissions testing at a unit with HCl CEMS. The proposed 

rule does not provide any procedure for SO2 performance testing or an SO2 emissions 

standard other than those applicable to units with SO2 CEMS. Obviously, U. S. EPA did not 

intend and would have no basis to require EGUs to use both an HCl CEMS and an SO2

CEMS.

(3) The proposed HCl Limit is at or near the detection limit for current

HCl CEMS

Although APPA supports the option for use of HCl CEMS and urges U. S. EPA to complete 

work on a reasonable performance specification, APPA is concerned about the ability of HCl 

CEMS to accurately measure compliance with the proposed standard because the limit is at or 

near the detection limit for current HCl CEMS technology. 
67

c. STACK TESTING:

(1) U.S. EPA must remove the requirement for SO2 performance testing

Proposed § 63.10006(h) and (i) include testing provisions for SO2 for units without SO2

CEMS. U. S. EPA must make clear that these provisions do not apply to EGUs complying 

through HCl stack performance testing. As discussed above, there is no basis for testing of 

the surrogate SO2 at a unit that is complying with the HCl standard. In addition, the proposed 

rule does not provide any procedure for SO2 performance testing or an SO2 emissions 

standard other than those applicable to units with SO2 CEMS. Obviously, U. S. EPA has no 

basis to require EGUs that choose to comply through stack testing to also install an SO2

CEMS.

(2) U. S. EPA should re-evaluate the proposed operating parameter 

requirements

As described below, the operating parameters specified for HCl are not sufficiently connected 

to HCl removal or sufficiently flexible to be used as enforceable limits. U. S. EPA also must 

allow for adjustment of load-dependent operating parameters to account for load changes, and 

should use the operating parameters as indicators, not enforceable limits.

iv. SO2 CEMS

(1) U. S. EPA should clarify the requirement for use of SO2 controls

To qualify for this option, wet or dry flue gas desulfurization technology must be operated ―at 

all times.‖ Proposed § 63.9991(a)(1)(iii). U. S. EPA should make clear that this requirement 

is intended to disqualify EGUs that operate SO2 controls intermittently, and not to disqualify 

EGUs that experience SO2 control device malfunctions or that must turn off controls to 

perform maintenance. The higher SO2 recorded by the CEMS during such periods will 

reflect the potential for higher HCl as well. U. S. EPA should also make clear that the 

existence of a bypass stack does not disqualify an EGU from complying with the SO2

standard. 

(2) U. S. EPA should allow all part 75 exceptions

Proposed 63.10010(e) allows use of an SO2 meeting Part 75, but disallows the linearity and 7-

day calibration error test exceptions and requires a calibration gas at a level equivalent to the 

emission limit (even if it is a fourth level). Proposed § 63.10010(e). 

(3) U. S. EPA must clarify the subsequent performance testing 

requirements for units “without HCl CEM”

Proposed § 63.10006(j) requires EGUs ―without HCl CEMS but with HCl emissions 

controls‖ to test for HCl at least every month. Proposed § 63.10006(k) requires EGUs 

―without HCl CEMS and without HCl emissions controls to test for HCl at least every other 

month.‖ U.S. EPA must make clear that these provisions do not apply to EGUs with SO2

CEMS. As discussed above, there is no basis for testing of HCl at a unit that is complying 

with the surrogate SO2 limit. 

(4) U. S. EPA should add reference to use of part 75 in the continuous 

compliance provisions
68

Proposed § 63.10021(a)(13) sets out the ongoing requirement for SO2 CEMS. The proposed 

requirements are similar to proposed § 63.10010(e), except this provision does not reference 

the Part 75 option. U. S. EPA should reference the Part 75 alternative in this provision as 

well or consolidate the two provisions. 

v. Options for Mercury (Hg)

If the EGU does not qualify as a low emitting EGU (LEE), initial and continuous compliance 

must be demonstrated using either (1) an Hg CEMS, or (2) a sorbent trap monitoring system. 

Proposed § 63.1000(c)(1). 

a. Hg CEMS

(5) U. S. EPA should remove the reference to Procedure 5

U. S. EPA proposes ongoing quality assurance (QA) requirements for Hg CEMS in Appendix 

A. However, U. S. EPA also proposes in § 63.10021(1)(14) to require compliance with 

quarterly accuracy determinations and calibration drift tests in accordance with Part 60, 

Appendix F, Procedure 5. The quarterly and daily requirements in Procedure 5 are 

duplicative of and conflict with some of the proposed requirements in Appendix A. Use of 

Procedure 5 also is inconsistent with U. S. EPA‘s preamble statement that it considered and 

rejected using Procedure 5. Preamble 75 Fed. Reg. at 25,032. U. S. EPA should remove the 

reference to Procedure 5. If U. S. EPA intends to require use of Procedure 5, U. S. EPA must 

issue a new proposal and make that clear.

(6) The accuracy of Hg CEMS at or near the proposed Hg limit 

for existing sources is questionable

APPA supports the option for use of Hg CEMS. However, the accuracy of Hg CEMS at or 

near the concentration of the proposed existing source limit is questionable. Hg CEMS will 

not be a viable option at the proposed level of the new source limit. 

vi. Sorbent Trap Monitoring System

Low Emission EGU (LEE)

As discussed above, it is not clear whether U. S. EPA intended that the proposed fuel input 

limit on Hg, and additional operating limits on Hg controls and load apply. Proposed § 

63.10011(b), Tables 4 - 8. U. S. EPA should make clear that the fuel input, control device 

operating limits and load limit do not apply. 

If LEE status is lost, conduct periodic emissions testing within 6 months for all HAPs or 

surrogates except Hg. For Hg, install a CEMS or sorbent trap system within one year. 

Proposed § 63.100006(c).

(1) U. S. EPA should expand the LEE option to new units

As proposed, the option to qualify a unit as a LEE applies only to existing units. New units 

also should be eligible.

(2) U. S. EPA should remove or explain the references to 

operating parameter limits for LEEs
69

Proposed § 63.10005(k)(3) and § 63.10006(c) refer to establishment and maintenance of 

operating parameter limits. However, the provision cited for establishing such limits does not 

exist and no other provision addresses parameters for LEE. Proposed § 63.10021(a)(17) 

states that for LEEs, results of emissions tests and fuel analysis demonstrate continuous 

compliance. The provision does not mention operating limits. Moreover, U. S. EPA‘s 

descriptions of the requirements for both LEEs suggest they are not required to establish or 

comply with operating parameter limits. 

(3) U. S. EPA should clarify the required testing period

Proposed § 63.10005(k) refers to a 28-30 operating day performance test. Proposed Table 5 

requires 30 days. 

(4) U. S. EPA should explain the 10-day limit on use of trap

Under proposed Table 2, LEE testing is limited to 10 days per run. The purpose of this limit 

is not explained. U. S. EPA‘s Appendix A allows up to 14 days.

U. S. EPA’s Proposed Operating Parameters Are Not Sufficiently Connected to 

Emission Limits to Be Enforceable Limits

APPA agrees with UARGs objections to U. S. EPA‘s proposal to set enforceable operating 

limits based on control device parameters measured during performance testing. 

Establishment of such limits reduces operational flexibility, deprives sources of the use of 

any control device margin, and allows enforcement for events beyond the owner/operator‘s 

control. 

U. S. EPA‘s current proposal is based on the faulty assumptions that the values of the 

parameters identified by U.S. EPA have a direct relationship to the level of emissions, and 

that exceeding those limits therefore indicates an exceedance of the emission limit as well. 

To the extent possible, source owners and operators will contract for control equipment that is 

designed to provide a ―margin of compliance‖ with the applicable emission limitation. In 

addition to reducing the possibility of an exceedance of the limit, this margin is intended to 

provide flexibility for the source to account for an inevitable control equipment or operational 

problem. Any source that is able to normally operate with a margin of compliance will lose

part of that margin of compliance if they conduct performance testing under normal 

operations, because they will establish operating limits that would require them to continue to 

over-control forever. The only way such sources could avoid surrendering whatever margin 

of compliance they have would be to deliberately reduce performance of their controls to 

attempt to generate the least stringent operating limits consistent with achievement of the 

applicable emission standard. U. S. EPA‘s proposal thus has the perverse result of 

encouraging sources to focus their attention on learning how to manipulate their operations to 

allow testing as close as possible to their emission limit by reducing the performance of their 

controls. 

Unfortunately, even the ―detuning‖ of a control device during performance testing will not 

ensure that the operating limits established during the test are reasonable or necessary for 

achievement of the applicable emission limit. As U. S. EPA has previously recognized in the 

context of the NSPS and the CAM rule ―many sources operate well within permitted limits 

over a range of process and pollution control device operating parameters,‖ and requiring 

sources to continuously maintain parameters that ―happened to exist‖ during the most recent 

performance test may not be ―possible or wise.‖ 62 Fed. Reg. 54,900, 54,907, 54,926-27. 
70

That is because control device parameters, such as those identified by U. S. EPA for 

scrubbers and ESPs, do not necessarily have a direct relationship to emissions, but instead are 

interrelated with the design of the control device and the interaction of various parameters. 

As a result, a single parameter may vary widely with little effect on emissions.84 For 

example, ESP power may be completely unrelated to ESP performance for a multi-sectional 

ESP. Id. at 2 and Appendix 1. This power approach for ESPs simply does not work and that 

fact is easily demonstrated in the cited material. Similarly, because scrubber pressure drop 

and liquid flow rate are usually a function of boiler load, levels of those parameters above or 

below those recorded during a performance test are not necessarily indicative of emissions 

levels at a different load. Id at 2. Many industrial boilers operate at variable load levels 

because they follow process demand. As the load drops, the scrubber pressure drop also 

moves down. This change does not necessarily indicate a drop in scrubber performance. In 

fact, the scrubber performance is likely to improve at reduced load. 

Although U. S. EPA‘s provision of a 10% difference from the average tested value 

recognizes some of the normal operational variability of control devices, it may not be 

sufficient in some circumstances. Without a clear correlation between such operating 

parameters and the applicable emission limit, imposition of those values as enforceable limits 

would unreasonably restrict source and control device operation and subject sources to 

potential enforcement without any evidence that an emission limits has been violated. 

Issues With Use of ESP Power

Under U. S. EPA‘s proposal, units that use an ESP in combination with a wet scrubber must 

comply with operating limits on secondary power input to the ESP collection plates. 

Proposed § 63.10011(b)(6)(iii). U. S. EPA‘s proposal is flawed. ESP power input simply is 

not directly related to PM removal performance, particularly for the modern multi-section 

ESPs that are likely to be installed to comply with a proposed MACT. See UARG Comments 

on Proposed Reconsideration and Revision of New Source Performance Standards, U. S. 

EPA-HQ-OAR-2005-0031-0246 (Mar. 27, 2007) at 21-22, and Attachment 2 (incorporated 

by reference); UARG Comments U.S . EPA-HQ-OAR-2002-0058-0413, Attachment C, 

Appendix 1. Moreover, none of the ESP parameters are likely to have any relationship to PM

at units that also have a wet scrubber, since those systems also are highly effective in 

controlling high levels of PM coming out of an ESP that is not performing at its intended 

control efficiency. See U. S. EPA-HQ-OAR-2005-0031-0246 at 15-16.

Issues with Use of pH, Pressure Drop, Liquid Flow-Rate, and Sorbent Injection Rate for 

Scrubbers

Under U. S. EPA‘s proposal, units that use a wet scrubber must comply with operating limits 

for pH, pressure drop and liquid flow-rate; and units that use a dry scrubber must comply 

with an operating limit on sorbent injection rate. Proposed § 63.20011b)(6)(i), (ii), and (iv). 

U. S. EPA‘s proposal to use these parameters is subject to the same flaws as U. S. EPA‘s 

other proposed operating limits -- namely the lack of a sufficient relationship between the 

parameters measured during performance testing and actual emissions. For example, as 

described above, because scrubber pressure drop, liquid flow rate, and sorbent injection rate 

vary with boiler load, establishment of a limit based on conditions during performance testing 

may tell U. S. EPA little about actual emissions under other load conditions. Moreover, when 

U. S. EPA in 2008 considered the relationship between liquid flow rate and PM in the context 

 

84 See UARG Comments on Proposed National Emission Standards (Mar. 14, 2003), U. S. EPA-HQ-OAR-2002-0058-0413, Attachment C 

(incorporated by reference).
71

of the NSPS for electric steam generating units at 40 C.F.R. Subpart Da, U. S. EPA 

concluded that, at the level of the NSPS (i.e., 0.015 lb/mmBtu), PM emissions controlled by 

an ESP were not particularly sensitive to the actual liquid flow rate. U. S. EPA ―Response to

Public Comments on Rule Amendments Proposed June 12, 2008 (73 FR 33642)‖ (Nov. 

2008), U.S. EPA-HQ-OAR-2005-0031-0284, at § 2.5.3. 

U. S. EPA Has No Basis To Expect That Operating Parameter Limits Established 

During Performance Tests Will Be Achievable During Startup, Shutdown, and 

Malfunction

APPA is very concerned about the potential for enforcement of operating parameter and 

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

malfunction. U. S. EPA‘s current proposal would allow enforcement of deviations from 

operating parameters during periods of startup and shutdown, when controls would not be 

expected to be operating at the same levels as during performance tests. In the preamble, 

U. S. EPA discusses its approach to these events. 76 Fed. Reg. at 25,028. Regarding startup 

and shutdown, U. S. EPA asserts that it has taken these periods into account by proposing use 

of 30-boiler-operating-day rolling averages and by the fact that EGUs often use cleaner fuel 

during startup. Id. 

U. S. EPA‘s preamble assertions regarding startup and shutdown are inapplicable to control 

device operating parameter limits, which are based on 12-hour averages (30-day rolling 

averages) established during performance tests (not based on CEMS data that include startup 

and shutdown). In short, U. S. EPA has made absolutely no allowance in its operating 

limits for periods of startup and shutdown. To the contrary, U. S. 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,” or other 

frequently used loads, and then maintain those levels during other periods, including 

startup and shutdown. U. S. EPA‘s proposal is patently unreasonable. U. S. EPA must 

address these periods in some other manner, for example by establishing simple work 

practice standards in lieu of operating parameters. 

The use of 30-day rolling averages with SSM could result in exceedances of the 30-day 

standards. The following comments provide a mathematical example of the error in U. S. 

EPA‘s inclusion of SSM instances in the rolling averages. This is tantamount to gaming the 

system to tighten standards by using circumstances outside of an entities control. The 

following example uses particulate matter (PM), but the same would apply to other 

pollutants:

Given:

A = average PM emission rate during SSM, lb/MMbtu

B = average PM emission rate during normal operation, lb/MMbtu

X = time fraction spent during SSM at ―A‖ lb/MMbtu

(1 – X) = time fraction spent during ―normal‖ operation at ―B‖ lb/MMbtu

0.03 = 30 day rolling average PM standard under MACT

Then you can say:

A*X + (1 – X) *B = 0.03

Solving for ―X‖ :
72

X = (0.03 – B)/(A – B)

Multiplying ―X‖ by 720 hrs gives you the number of SSM hours out of the 30-day rolling 

average that will result in exceedance of the standard (―hours-to-exceed‖).

If a PM emission rate during startup without an ESP, was 0.45 lb/MMbtu (―A‖). The annual 

average PM during normal operation (―B‖) is 0.02 lb/MMbtu.

This gives an ―X‖ of 0.023 or 16.7 hours. Thus theoretically, it is possible that several short 

back-to-back outages could exceed the 30-day standard. 

Additionally, if a scrubber is in operation it has the potential to increase PM emissions. If we 

assume a ―normal‖ PM emission rate of 0.28 lb/MMbtu (―B‖) with the scrubber in service 

combined with an SSM emission rate of 0.45 (―B‖), then the hours-to-exceed becomes only 

3.4 hours. In this case, one forced outage might then cause an exceedance. A forced 

outage is out of the utility’s control and should not ever be able to cause an exceedance 

of emissions limits. By excluding SSM, EPA has mandated a more stringent standard 

than 0.03 lb/MMbtu, in some cases this standard is MUCH more stringent depending on 

the SSM operating emission rate. A graph of the hours of operation it would take to exceed 

the U. S. EPA‘s 30-day standard as a function of "Normal" emission rate for various SSM 

PM emission rates in lb/MMbtu can be found below in Figure 6.

Figure 6: Graph of hours of operation it would take to Exceed EPA‘s 30 Day Standard as a function of 

"Normal" emission Rate for Various SSM PM Emission Rates in lb/MMbtu.
73

APPA Agrees with UARG’s Assertion that U. S. EPA Should Require Sources To 

Establish Source-Specific Control Device Parameter Ranges And Enforceable Response 

Requirements, Not Enforceable Operating Limits

Rather than establish enforceable operating limits, U. S. EPA should use the approach taken 

in the CAM rule and require sources to establish site-specific operating parameter ranges to 

define conditions under which compliance with the applicable limit can be reasonably 

assured. This approach already has been upheld as sufficient to satisfy the CAA’s

requirements for demonstrating continuous compliance. See NRDC v. U.S. EPA, 194 F.3d 

130, 135-37 (D.C. Cir. 1999) (rejecting NRDC‘s argument that the CAM rule‘s ―reasonable 

assurance of compliance‖ is not sufficient to assure continuous compliance as required by the 

CAA). Source owners and operators would then be required to monitor those parameters and 

respond to changes that indicate problems with the controls that could jeopardize compliance. 

Whether using a single control device or combination of devices, sources are in the best 

position to determine what parameters and levels are consistent with compliance. In many 

cases, multiple parameter relationships or supplemental operational data will provide a higher 

level of compliance assurance than the level that happens to be measured during a discrete 

performance test. This is particularly true for sources with a significant margin of 

compliance. U. S. EPA-HQ-OAR-2002-0058-0413, Attachment C at 4. In addition, units 

with significant margins of compliance should be allowed to establish operating levels by 

extrapolating parameter data beyond that obtained during a performance test, based on other 

information. Allowing such extrapolations is essential for some sources to provide needed 

operational flexibility. Attempting to establish ―worst case‖ test conditions on a scrubber or 

multi-section ESP, where the possible combinations of parameters are numerous, would at 

the least be difficult and could be impossible without a major research effort. Id. Allowing 

extrapolation of results avoids the necessity of repeated testing. 

Once sources have established appropriate operating parameter ranges based on data 

collected during performance tests, as well as other operating data and engineering principles, 

those parameters would be monitored and any deviation from them would trigger a 

requirement for investigation and corrective action to return the parameter to the appropriate 

range. Although this range may in some cases be similar to the minimum values that would 

be established under U.S. EPA‘s proposed rule, allowing sources to respond with corrective 

action (rather than simply record exceedances and report deviations) achieves U. S. EPA‘s 

intended result without subjecting sources to potential unreasonable enforcement.

Bag Leak Detection Systems

Under U. S. EPA‘s proposal, units that use a fabric filter (whether or not using a wet 

scrubber) and that ―choose to demonstrate continuous compliance using a BLDS‖ must 

install, operate, calibrate and maintain a BLDS in accordance with U. S. EPA‘s ―Fabric Filter 

Bag Leak Detection Guidance,‖ U. S. EPA-454/R-98-015 (Sept. 1997). Proposed §§ 

63.10010(h)(2)(v). The BLDS must be certified by the manufacturer to be capable of 

detecting PM at a concentration of 10 milligrams per actual cubic meter or less. Id. The 

BLDS must be operated such that the sum of the duration of alarms does not exceed 5% of 

the operating time during any 6-month period. Proposed §§ 63.10011(b)(6)(v); 

63.1021(a)(9). Records must be kept of each alarm period. If inspection of the bag 

demonstrates that no corrective action is required, no alarm time is counted. If corrective 

action is required, the alarm time is counted as the actual time taken to initiate corrective 

action with a minimum of one hour counted for each alarm. Proposed § 63.1021(a)(9). 
74

Applicability of the requirements for fabric filters is unclear. Although several provisions 

suggests that BLDS are required only if an EGU ―chooses‖ to demonstrate compliance using 

a BLDS, other provisions appear to require any EGU with a fabric filter to employ a BLDS 

along with any other applicable operating limits. Proposed Tables 4-8. U. S. EPA should 

issue a proposal that makes clear when a BLDS would be required and to justify that 

requirement. 

In addition, U. S. EPA‘s guidance has no place as a regulatory requirement. U. S. EPA‘s 

guidance addresses only one type of BLDS (the ―triboelectric‖) and is based on information 

provided by a single manufacturer. The definition of BLDS clearly allows use of a variety of 

technologies, including electrodynamic, light scattering, and light transmittance. Proposed § 

63.10042. The guidance explains that the alarm setting procedure is dependent on the type 

and configuration of the fabric filter and filter cleaning cycle. But it addresses only one 

baghouse configuration. The document excludes all other technologies (e.g., light scattering, 

light transmission, optical scintillation, and electro-dynamic devices). In short, the existing 

Guidance Document is out of date and is technically flawed.

D. Reporting

1. Reporting Using ERT

(a) U. S. EPA Cannot Require Sources to Report Using ERT

XV. Oil-fired units in Alaska, Puerto Rico, American Samoa, and Guam require special 

considerations: APPA supports waiver for oil-fired units in Guam, Puerto Rico Hawaii and Alaska 

Oil Units

APPA has member utilities in locations that are uniquely isolated including islands, or areas 

of the country that are not connected to the national utility or industrial infrastructure. These 

locations have special needs for delivery of pollution control devices, installation, working 

around seasonal loads, scheduled outages and extreme economic impacts due to extended 

outages for installation.

APPA supports the petitions presented by Guam, Puerto Rico, Hawaii, and Alaska to exempt 

their oil-fired power plants from the new nickel limits. APPA defers to that petition as to the 

specific treatment. APPA notes that because of the relationship between investor, electric coop and public power (municipal or state owned utilities), we believe the language offered by 

the petitioners should cover all utilities on those ―islands‖ (including Alaska, which functions 

as an island due to its isolation). Appendix O shows the Guam Oil-Fired capacity units and 

date of installation.

85

XVII. Relationship between EGU MACT and Coal Ash/Coal Combustion Residuals Rulemaking

APPA believes that the U. S. EPA has proposed a rule that would make many coal-fired 

power plants seek to use DSI as a control technology in order to maintain some fuel diversity 

in their utility portfolio. As a result of using DSI as a control technology, many existing 

power plants using coal may learn that their coal ash may not be tradable or commercially 

viable for sale to a cement company due to the sodium content. The cement industry has 

ASTM (formally known as American Society for Testing and Materials)86 standards on 

sodium content. The DSI control technology will have an unintended consequence of 

 

85 FY 2008 Guam Generation Resource Handbook

86 http://www.astm.org/ABOUT/overview.html
75

increasing the sodium content making it unsuitable to the commercial users of coal ash.

For municipal electric utilities, simply making the ash undesirable to the cement industry 

(due to sodium content from DSI technology) would often mean a dramatic increase in the 

cost of disposal. In fact, it would be akin to designating the coal ash as a hazardous substance 

since the public power utilities would not have the ability to sell or trade the ash to a local 

cement industry. Ash disposal costs to a community owned utility can be enormously 

expensive. These coal ash disposal costs can range between 5% and 24% of a municipal 

government‘s revenues (when considering larger public power utilities that exceed the 

SBREFA threshold). The typical cost range is between 2% and 14%, depending upon 

proximity to a hazardous waste landfill (Source: APPA‘s comments to the U. S. EPA on coal 

ash, Nov. 2010).

Table 3 - Examples of Additional Costs to Some Smaller Municipal Utilities for CCR Disposal as 

Hazardous Waste

Utility Total 

Ultimate 

Customer

s

Residential 

Customers

Amount 

of CCR 

(tons)

Disposal Cost 

at $100/ton

Revenues Percent of

Revenues for 

Disposal as 

Hazardous Waste

Muscatine, IA 11,797 9,663 44,196 $4,419,600 $68,200,000 6.5%

Orrville, OH 6,933 6,076 20,000 $2,000,000 $22,336,000 9.0%

Holland, MI 30,136 25,375 23,086 $2,308,600 $78,195,000[1] 3.0%

Manitowoc, WI 17,828 15,621 79,774 $7,977,400 $54,290,000 14.7%

Painesville, OH 12,056 10,167 5,396 $539,600 $22,150,000 2.4%

Michigan South 

Central Power 

Agency

20,606 17,170 28,596 $2,859,600 $47,987,421 6.0%

Marquette, MI 15,675 13,845 23,926 

 

$2,392,600 $23,934,000 10.0%

Hamilton, OH[2] 29,480 26,481 32,782 $3,278,200 $59,567,000 5.5%

Source: APPA‘s comments to EPA on proposed RCRA regulation, November, 2010.

Disposal of CCRs as hazardous waste (estimated at the very conservative figure of $100/ton) 

could reach 21% of the revenues for some governmental or municipal utilities. From the 

cost estimates offered by municipal utilities during the EPA coal ash or CCR comment 

period, it is clear that the EPA‘s estimated $100/ton disposal cost was too low. Many utilities 

offered disposal costs that could exceed $200/ton, depending on the details of EPA‘s final 

coal ash or CCR rule. Much of the cost increases are increased disposal costs and 

transportation costs. Ohio, for example, has only one hazardous waste landfill which is across 

the state from Orrville (a public power or community owned electric utility); Orrville 

estimated their disposal costs to be $100/ton.

Another key flaw in the proposal is the RIA‘s failure to consider the adverse impacts that 

certain of the control technologies upon which the emission controls are predicated –

including in particular sodium-based dry sorbent injection and activated carbon injection 

(ACI) – will have on the marketability and beneficial use of fly ash in important industry 

segments. The loss of these important beneficial uses – which comprise a material 

percentage of the total amount of coal combustion residuals beneficially used on an annual 

basis – will cause these CCRs to have to be disposed of, as opposed to being beneficially 

used, causing significant and new economic and operational burdens on power generation 

facilities and resulting in the forfeiture of significant greenhouse gas (GHG) emission 

reductions achieved through these beneficial uses. These economic burdens and associated 
76

loss of carbon reductions must be evaluated by EPA as part of this rulemaking.

The Recycling of Fly Ash Will Be Undermined Because of Emission Control 

Technologies Contemplated in the Proposal

Currently, approximately 134 million tons of CCRs are generated annually, of which 

approximately 56 million tons, or approximately 41%, are recycled in a variety of 

applications. See 2009 Coal Combustion Product (CCP) Product and Use Survey, American 

Coal Ash Association (―ACAA Survey‖). Of critical importance to this rulemaking, almost a 

quarter of these beneficial use applications involves the use of fly ash as replacement for 

cement in the production of concrete (in the ready mix concrete industry) and as a raw feed 

material in the manufacture of cement (a combined total of approximately 12 million tons per 

year). See ACAA Survey. The employment of sodium-based dry sorbent injection and ACI 

technologies by power generation facilities, however, will render the vast majority of this 

approximately 12 million tons of CCRs generated annually unfit for these beneficial use 

applications, causing this significant volume of CCRs to have be disposed of instead of 

entering the beneficial use market.

The problem arises because, for fly ash to be used in certain applications, the fly ash must 

meet product specifications. For example, the American Association of State Highway and 

Transportation Officials (―AASHTO‖) has set a maximum allowed ―alkali‖ content for the 

use of fly ash in concrete at a maximum of 1.5%. AASHTO M295. AASHTO M 295 (along 

with ASTM C 618) are used within the industry to provide a guide to assure that fly ash when 

used as a concrete admixture conforms to a specified range of physical and chemical 

properties. Conformity assures that a consistent, high quality product is produced. Alkali 

silica reaction (ASR) is the reaction between the alkali hydroxide in Portland cement and 

certain siliceous rocks and minerals present in the aggregates. The products of this reaction 

often result in significant concrete expansion and cracking, and ultimately failure of the 

concrete structure. Therefore, an alkali limit was established for mineral admixtures such as 

fly ash that are used in concrete containing reactive aggregate and cement.

Preliminary testing, however, shows that sodium-based sorbent injection technologies will 

cause fly ash to exceed the 1.5% available alkali criteria. Sodium-based dry sorbents are 

soluble and therefore contribute greatly to the available alkali content. As a result, fly ash 

produced with emission controls systems employing sodium-based dry sorbent injection 

technologies – upon which EPA based certain key emission and cost assumptions in the 

proposal – will no longer be suitable for use in the ready-mix concrete industry.

Compounding this problem is that the use of sodium-based dry sorbent injection technologies 

also increases the solubility of certain other constituents in the fly ash, which would 

potentially make it unsuitable for other established and environmentally beneficial uses, 

including for mine reclamation. In 2009, approximately two million tons of fly ash were

beneficially used in mine reclamation projects (ACAA Survey). These fly ash beneficial use 

applications would also be at risk if sodium-based dry sorbent injection technologies serve as 

the basis for key emission control strategies in the final rule.

In addition to sodium-based dry sorbent injection, the use of ACI technologies will cause 

some fly ash to be unsuitable for use as a cement replacement in ready mix concrete due to 

increased carbon content. The increased carbon content attributable to ACI renders the fly 

ash unsuitable for use in ready mix concrete because the highly reactive carbon adsorbs air 

entraining agents.
77

The RIA Must Account for Lost Emission Reductions and Increased CCR Management 

Costs Due to the Emission Control Technologies Contemplated in the Proposal

EPA has consistently extolled the environmental benefits of the beneficial use of CCRs. In 

Congressional testimony, EPA testified that the ―beneficial use of CCR saves virgin 

resources, reduces energy consumption, reduces GHG emissions, and reduces the need for 

land disposal.‖ See EPA Written Testimony before the Senate Committee on Environment 

and Public Works (Jan. 8, 2009) (―EPA Testimony‖). Of particular relevance to this 

proposal, EPA emphasized that ―coal ash can typically replace between 15% and 30% of the 

Portland cement used in concrete.‖ The GHG savings from these beneficial use practices are 

dramatic – in 2007 alone, EPA reported that ―by recycling 13.7 million tons of fly ash and 

using it in place of Portland cement, the United States saved nearly 73 trillion BTUs of 

energy, equivalent to the annual energy consumption of more than 676,000 households.‖ Id. 

at 8. These beneficial use activities also resulted in GHG emissions reductions ―by 12.4 

million metric tons of carbon dioxide equivalent, equivalent to the annual GHG emissions of 

2.3 million cars.‖ Id.

87

Any environmental forfeiture of this magnitude caused by reliance on the sodium-based dry 

sorbent injection and ACI technologies contemplated in the proposal must be assessed and 

considered in the overall policy evaluation and RIA underlying the proposal. EPA has not 

conducted this evaluation in the proposal’s RIA.

Not only will reliance on these emission control technologies result in the forfeiture of 

significant GHG emission reductions, they also will result in greater volumes of CCRs having 

to be disposed of. Specifically, establishment of emission control technologies predicated on 

sodium-based dry sorbent injection and ACI will likely mean that approximately 12 million 

tons of fly ash (if not more) will be diverted on an annual basis from its beneficial use in the 

cement/concrete industries to CCR disposal units. Coal-based facilities will need to 

accommodate these additional volumes of CCRs through expansions of existing disposal 

units and/or construction of new units. The design, planning, permitting and construction of 

this additional disposal capacity can take many years and cost millions of dollars per unit. 

The RIA must take into account the additional construction and disposal costs that coal-based 

generating units will have to incur to dispose of additional CCRs that will be diverted from 

the beneficial use market to the disposal market as a result of the contemplated emission 

control technologies underlying the proposal.

U. S. EPA has underestimated higher coal transportation costs affected by the U. S. 

EPA EGU MACT rulemaking: more captive rail impacts resulting from reliance upon 

western coal and transport of coal ash to permitted landfills.

 

The electric utility sector has transportation costs that are influenced by the limitations of the 

U. S. rail system. Captive rail customers are shippers who must rely on a single railroad to 

deliver their products. These customers usually move bulk commodities such as coal, grain or 

lumber, or certain materials that, due to size or characteristics, cannot be moved on our 

nation's highways.

 

Historically, 20-30 percent of the nation‘s rail movements have been ―captive,‖ with many of 

these movements covering rural America. According to a recent study commissioned by the 

 

87 See also Testimony of Barry Breen, Acting Assistant Administrator Office of Solid Waste and Emergency Response before the House 

Committee on Transportation and Infrastructure, Subcommittee on Water Resources and the Environment (April 30, 2009).
78

Surface Transportation Board, 44% of all tonnage shipped by freight rail is “captive”

(routes served by only one rail carrier line). The study, which was commissioned by the 

Surface Transportation Board (STB), provides evidence previously denied by the freight 

railroad industry that they are abusing their unique exemption from antitrust law to exert 

anticompetitive business practices – by charging shipping rates 500 to 700 percent above cost 

and refusing to provide adequate service to freight rail shippers who are captive to only one 

railroad. For additional information on captive rail, please see 

http://www.railcure.org/about/about_customer.asp. 

APPA notes that there may be unintended cost consequences to eastern coal varieties because 

utilities using eastern coal may not be able to meet the EGU MACT/NSPS proposed rule. 

APPA notes that use of western coals by the remaining coal fired power plants may well 

cause utilities of all sizes to be more reliant upon rail transportation due to moving more 

western coal to more power plants. As captive customers of rail companies, power plants 

would pay significantly more for delivery of western coals. The displacement of the eastern 

coal, cost and the related transportation impacts were not considered by the U. S. EPA. The 

costs of transportation of coal are almost always more expensive than the cost of the coal 

itself. If the U. S. EPA‘s final EGU MACT/NSPS rulemaking causes more fuel switching 

from eastern to western coals, the additional transportation costs (and captive rail cost 

concerns) may well be another major factor not considered in the U. S. EPA Regulatory 

Impact Analysis (RIA). This is yet another reason why the U. S. EPA‘s failure to 

subcategorize between eastern and western coal represents a serious technical flaw which is 

unlikely to survive judicial challenge.

Conclusions

Essential Corrections to EGU MACT Rule:

1) U. S. EPA should re-propose the rule and the final EGU MACT should not include acid gases or 

PM regulatory controls.

2) Public power utilities need more time for compliance for planning, public hearings, financing, 

procurement and construction so the U. S. EPA and the President should grant extensions.

3) U. S. EPA should provide more flexibility including subcategories for public power, electric coops, IOUs and merchant power. 

These subcategories include: 

- ≤100 MW for all types of utilities

- ≤30% capacity factor peaking units (limited use – mostly for renewables)

- NERC Reliability Standard CIP 002-4 units

- By fuel type

- Those utilities with physical space constraints

 APPA believes that the U. S. EPA did not carry out its statutorily required actions and full analysis 

under RFA ―Reg Flex‖ and UMRA as well as SBREFA. This poor analysis reflects both a poor 

analytical preparation for the rulemaking and a disregard to what the EPA was told during the U. S. 

EPA SBREFA SER panel meeting on December 2, 2010. 

 APPA believes that the EPA did not adequately consider the disproportionately large cost of 

compliance faced by small communities. 

 The EPA RIA failed to identify how many of the public power units will be implementing control 

technologies under separate Clean Air Act regulations.
79

 APPA believes that the U. S. EPA has grossly underestimated the number of coal-fired generation 

retirements at only 9.9 GW, which is only 3% of all coal-fired capacity, by the year 2015.

 Natural gas prices for consumers and utilities will almost certainly increase more than projected by

U. S. EPA's RIA.

 APPA believes that three years from the date of publication of the final rule is an unrealistic timeline 

for compliance given the need for municipal governments to issue and conduct resource planning for 

fuels, issue and review requests for proposal, obtain financing or issue debt/bonds to pay for projects, 

and coordinate with contractors, labor unions, and crane operators, along with any permits needed for 

construction and transportation.

 As part of providing for the 77 months needed to complete pollution control projects APPA strongly 

urges the U. S. EPA to provide an industry wide extension, or one-year along with Presidential 

extensions, to reduce the burden on electric utilities, state permitting agencies and the consumers of 

electricity who will pay for the compliance costs. Further, public power utilities need a categorical 

extension based upon time constrained feasibility due to local ordinance duties.

 APPA believes that the U. S. EPA has made a significant error in its proposed rule on mercury under 

the NESHAP program by adding extraneous regulatory controls for acid gases and PM2.5.

 APPA is a member of UARG and endorses UARG‘s technical comments on this proposed EGU or 

Mercury MACT and the proposed NSPS rulemaking pertaining to data availability, data analysis and 

the identification of conversion errors. APPA also endorses UARG‘s comments offered separately on 

EGU MACT monitoring.

 EPA did not adequately subcategorize to accommodate many of APPA‘s small and medium-sized 

public power utilities. In particular, EPA did not avail itself of the opportunity to use subcategories 

for public power electric utilities, HCl, coal rank, and for rural and isolated power plants that may not 

have equal options for fuel and many other fuel type subcategories.

 APPA does not believe that the U. S. EPA sufficiently considered its ability within the Clean Air Act 

to use Generally Available Control Technology (GACT) for smaller emitters of air toxics.

 U. S. EPA‘s feasibility and cost analysis did not adequately address physical space and age of plant 

issues when setting Best Demonstrated Technology (BDT), MACT and NSPS. In not addressing the 

age and space issues associated with including so many control technologies, the U. S. EPA has 

wrongly produced a rule that will make older plants and smaller plants unable to meet the new 

standards. 

 The U. S. EPA should acknowledge that the price of compliance increases as the size of the

generating unit decreases.

 APPA believes that the U. S. EPA‘s estimate of benefits and costs resulting from this proposed rule 

exaggerate the human health benefits dramatically because of its inclusion of PM2.5.

 APPA believes that the proposed rule‘s initial new source limits were unrealistic and miscalculated 

based upon contractor errors (See UARG letter to U. S. EPA, dated May 6, 2011 in Appendix G). 
80

 APPA believes the U. S. EPA should be commended for using work practices in lieu of CO limits but 

we do ask EPA to consider UARG‘s technical comments.

 The proposed NSPS for SO2, PM, and NOx are NOT Achievable.

 U. S. EPA did not properly and thoroughly investigate and address the significant costs

imposed on all electricity customers by this proposed rule. The U. S. EPA also should attempt 

to address the unproductive costs of compliance that will occur due to RTO market structures.

 U. S. EPA‘s final EGU MACT (without the unnecessary acid gas or PM limit related controls) should 

include an administrative noncompliance procedure under the Clean Air Act‘s Title V permitting 

program. This would ensure timely reductions in mercury in the instances where electric utilities 

required to provide electricity under local laws (―obligation to serve‖) are unable to procure, finance, 

construct, install and calibrate the pollution control equipment by the final rule‘s compliance date. 

This procedure is allowed under the existing Clean Air Act.

 The U. S. EPA should correct the New Source Review (NSR) enforcement policy, given the 

significant pollution control equipment installations.
81

Prepared by 

Alex Hofmann

Senior Energy & Environmental Services Engineer

APPA

ahofmann@publicpower.org

202 467 2956

Theresa Pugh

Director, Environmental Services

APPA

tpugh@publicpower.org

202 467 2943

August 2, 2011
82

Appendices

A. Development of Additional Subcategory for Electric Generating Units Less Than 100 MW

www.publicpower.org/files/appa%5Fsupport%5Ffor%5Fsmall%5Funit%5Fsubcategory%5Ff

inal.pdf (Full text available on the following pages of these appendices)

B. Payments and Contributions by Public Power Distribution Systems to State and Local 

Governments, 2008 Data 

www.publicpower.org/files/Pilot%20Report%202008.pdf

C. Small Business Administration (SBA) Letter on EGU GHG NSPS to U. S. EPA (6/13/2011) 

www.publicpower.org/files/SBA%20EGU%20GHG%20NSPS%20%2D%20Response%20to

%20convening%20%2D%20Public%20%2D%202011%2D06%2D13.pdf

D. Unfunded Mandates Reform Act of 1995

www.publicpower.org/files/Unfunded%20Mandates%20Act%20of%201995%2E%20%28Autosaved%29%202.doc

E. APPA‘s Comments to U. S. EPA and SBA regarding EGU MACT (and pointing out the 

benefits of using GACT to reduce regulatory costs and burdens) – December 2, 2010

http://www.publicpower.org/files/PDFs/Comments%20to%20SBA%20on%20EGU%20MA

CT%20rule_%2833698244%29.pdf (Full text available on the following pages of these 

appendices)

F. APPA‘s Clean Air Mercury Rule Comments www.publicpower.org/files/EPA20040629captrade.pdf 

G. The Feasibility of EPA‘s Proposed Utility HAP Compliance Requirements

www.publicpower.org/files/Compliance%20deadline%20feasibility%2023July%5FFNL%5Ft

imeline%20%282%29%20%2D%20Doug%20Carter.pdf

H. Technical Report from UARG

www.publicpower.org/files/UARG%20Comments%202010.pdf

I. UARG Request for MACT Comments Extension, May 6, 2011

www.publicpower.org/files/uarg%20request%20mact%20extension%205%2D11.pdf

J. Neophytes Guide

www.publicpower.org/files/Neophytes%20Guide.pdf

K. Why New CO2 Regulations Could Produce Windfall Profits and Unproductive Costs for 

Consumers

www.publicpower.org/files/PDFs/IssueBriefWindfallProfitsandEPARegsMarch2011.pdf

(Full text available on the following pages of these appendices)

L. Retire or Retrofit? A Look at U. S. Regional Scrubbed Coal Capacity, SNL Energy Data 

Dispatch Article, Feb. 24, 2011

www.publicpower.org/files/Retire%20or%20retrofit%20%2D%20%20A%20look%20at%20

US%20regional%20scrubbed%20coal%20capacity.pdf
83

Upcoming, Recent Coal-Fired Power Unit Retirements, SNL Energy Data Dispatch Article, 

Feb. 22, 2011

www.publicpower.org/files/Upcoming%2C%20recent%20coal%2Dfired%20power%20unit%20retirements.pdf

M. Implications of Greater Reliance on Natural Gas for Electricity Generation - APPA‘s Natural

Gas Study

https://appanet.cms-plus.com/files/PDFs/ImplicationsOfGreaterRelianceOnNGforElectricityGeneration.pdf

N. Current Capital Cost and Cost-Effectiveness of Power Plant Emissions Control Technologies 

by Ed Cichanowicz www.publicpower.org/files/PDFs/CichanowiczCostEffectiveness.pdf

O. Guam‘s Oil-Fired Capacity Units & Date of Installation

Unit Year Unit 

Installed

Nameplate 

Capacity 

Rating

Technology Primary Fuel MACT 

Affected

Cabras #1 1974 66.0 Steam Residual Fuel Oil Yes

Cabras #2 1975 66.0 Steam Residual Fuel Oil Yes

Cabras #3 1995 39.3 Slow Speed Diesel Residual Fuel Oil Yes

Cabras #4 1996 39.3 Slow Speed Diesel Residual Fuel Oil Yes

MEC #8 1999 44.2 Slow Speed Diesel Residual Fuel Oil Yes

MEC #9 1999 44.2 Slow Speed Diesel Residual Fuel Oil Yes

Tanguisson #1 1971 26.5 Steam Residual Fuel Oil Yes

Tanguisson #2 1973 26.5 Steam Residual Fuel Oil Yes

Dededo C.T. #1 1992 23.0 Frame 5 Ultra Low Sulfur Diesel Oil No

Dededo C.T. #2 1994 22.0 Frame 5 Ultra Low Sulfur Diesel Oil No

Macheche C.T. 1993 22.0 LM2500 Ultra Low Sulfur Diesel Oil No

Marbo C.T. 1995 16.0 FIAT TG-16 Ultra Low Sulfur Diesel Oil No

Yigo C.T. 1993 22.0 LM2500 Ultra Low Sulfur Diesel Oil No

Tenjo #1 1993 4.4 Caterpillar Model 3616 Ultra Low Sulfur Diesel Oil No

Tenjo #2 1993 4.4 Caterpillar Model 3616 Ultra Low Sulfur Diesel Oil No

Tenjo #3 1993 4.4 Caterpillar Model 3616 Ultra Low Sulfur Diesel Oil No

Tenjo #4 1993 4.4 Caterpillar Model 3616 Ultra Low Sulfur Diesel Oil No

Tenjo #5 1993 4.4 Caterpillar Model 3616 Ultra Low Sulfur Diesel Oil No

Tenjo #6 1993 4.4 Caterpillar Model 3616 Ultra Low Sulfur Diesel Oil No

Dededo Ultra Low 

Sulfur Diesel Oil #1 1971 2.5 Diesel Unit Ultra Low Sulfur Diesel Oil No

Dededo Ultra Low 

Sulfur Diesel Oil #2 1971 2.5 Diesel Unit Ultra Low Sulfur Diesel Oil No

Dededo Ultra Low 

Sulfur Diesel Oil #3 1971 2.5 Diesel Unit Ultra Low Sulfur Diesel Oil No

Dededo Ultra Low 

Sulfur Diesel Oil #4 1971 2.5 Diesel Unit Ultra Low Sulfur Diesel Oil No

Manenggon #1 (MDI) 1994 5.3 Wartsila, Model 16V32 Ultra Low Sulfur Diesel Oil No

Manenggon #2 (MDI) 1994 5.3 Wartsila, Model 16V32 Ultra Low Sulfur Diesel Oil No

Talofofo #1 1993 4.4 Caterpillar Model 3616 Ultra Low Sulfur Diesel Oil No

Talofofo #2 1993 4.4 Caterpillar Model 3616 Ultra Low Sulfur Diesel Oil No

TEMES 1998 40.0 Frame 6 Ultra Low Sulfur Diesel Oil Yes

Total Installed Capacity (MW) 552.8