## 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 Smal l 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 , 20112

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 Mandat es 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 Im pacts 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 Utilit ies

Is Justified

................................ ................................ ................................ ................................ .............. 29

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

................................ . 32

Comments related to general pol icy 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

................................ ................................ ................................ ......................... 523

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 boile rs. The current NSPS allows three ways to comply:

......................... 53

2. Modified boilers.

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

B. U. S. EPA Should Rescind Its Proposal and Reprop ose 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 SO 2 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 NO

x 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 Outp ut, 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.

..................... 624

XII. Monitoring Issues (testing compl iance 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 Ha waii and Alaska Oil Units

................. 74

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

......... 74

Conclusion s

................................ ................................ ................................ ................................ ................. 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 CO 2 Reg ulations 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. 2 4, 2011

................................ ................................ ................................ ............................. 82

M. Implications of Greater Reliance on Natural Gas for Electricity Generation

- APPA‘s Natural
Gas Study

................................ ................................ ................................ ................................ ................ 83

N. Curren t 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 Ca pacity Units & Date of Installation

................................ ............................... 835

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 4 6.4 % 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

 Appe ndices Figure 16



## Introduction/Executive Summary

Essential Corrections to EGU MACT Rule:

1) U. S. EPA should re

- propose the rule and the f inal 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 co

ops, IOUs and merchant power.

T hese 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 sign ificant risk to the public. If EPA believes that non mercury metals and acid gases must be regulated, EPA should regulate these H APs 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 min imize 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. Specif ically, APPA believes that EPA sh ould establish a MACT tha t
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 SO 2 , PM, and NO

x are , i n practice, NOT a chievable

.

 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 As ia and Mexico.7

 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 f ossil 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 u se of General ly 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 a re 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, physica l constraints limiting the foot print of plant s
, and age of plant s

. APPA strongly endorses

the ≤ 100 MW sub

- category. This ≤100 MW subcategory should apply to all in the u tility 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) sect ion 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, par ticularly 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

Pres idential extension provisions (t he 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 contr ols (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, permit ted 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 coal

fired to natural gas may require permitting, financing and building of natural gas pipeline extensions, as well as natural gas stora ge permitting and construction. This is particularly true if a public power authority does not have power of eminent domain.8

For some pipelines and l ocal d istribution c ompanies (LDCs), FERC and Public Utility Commissions (PUCs) may need to change standar ds that would harmonize the ―el ectric 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

admini strative 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 agen cies with delegated author ities, 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 e stablishing 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 small er in size, and are often space

- constrained by growth in the community surrounding the generating unit since its

initial construc tion. 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 tha t 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 m alfunction. Therefore those periods of operation should not be subject to the standards. A work pra ctice approach, similar to that

p romulgated 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 tha n the emission standards that they support, and therefore were no t ―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 u sing 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.



## C omments 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 government s , and certain small entities. Most p ublic power systems qualify under these general categories. EPA should have, but did not

, enga ge in an adequate process of consultation

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

evidence that EPA consider ed substantive alternative regulatory ap proaches in an effort to reduce the9

financial bur den 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 w ith 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

pres ence 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

detaile d 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 Budge t (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 R egulatory I mpact A nalysis ( 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 th e 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, 20 11 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 SE R 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

oi l

- 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 undere stimated 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 certainl y 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), 3 to convene a Small Business Advocacy Review Panel (SBAR) to thoroughly and accurately assess the imp act of the proposed regulations on utilities that qualify as small businesses. During the convened SB REFA SER panel

1 See ― Regulatory Flexibility and Unfunded Mandates Reduction A ct 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 s ince 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 business es in the federal regulatory process 4 and to create a more cooperative regulatory environment among agencies and small businesses that is less punit ive and more solution

- oriented. 5 Section 609 of SBREFA envisions that small business panels will review ―any material the agency has prepared in connection with this chapter

, ‖ including information required to be part of the initial regulatory flexibility analysis. 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, an d the clarification, consolidation, or simplification of compliance and reporting requirements for small entities. 7 At t he 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 do es not follow C ongress’ intent for how S BREFA 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 CO 2 .)

The highly abbreviated nature of this particular smal l 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 gi ven 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 consisten t 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

u northodox 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 CO 2 would be regulated . This was brough t about by the cascade regulation of stationary sources of CO 2 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 pan el. 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 Th e 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 impo rtant part of any major federal rulemaking. EPA should have factored that process into any rulemaking schedule it agreed to and defended before a fed eral district court judge. As a practical matter, the consent decree allows EPA to unilaterally return to t he 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 o nly 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 (UMRA 10 ) 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 impo se 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 , t hose 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 t he 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 perm its, 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 ec onomic realities facing the country today. It is noted that U. S. EPA has taken relatively little discretion in developing MACTs for virtually ever y 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 calculation s, 99.99% of all benefits from the proposed rule will

result from co

- benefits associated with estimated reductions of SO 2 and NO

x resulting in lower
ambient PM 2.5 and o zone levels. However, these co

- benefits would naturally follow the implementation of ot her CAA requirements currently in progress

, including the revised PM 2.5

and o zone NAAQS as well as the one hour SO 2 and NO

x NAAQS, which will lead to lower SO 2 and NO

x caps under the C lean A ir T ransport R ule (CATR now called C ross S tate A ir Pollution

R ule )

. 12

APPA respectfully submits that the U. S. EPA has faile d 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 SO 2 and NO

x cap under CATR.12

unintentional effects of federal mandates, includ ing 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

esp ecially 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 propo sed 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 eco nomic 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

con siderations 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 co sts and benefits of the proposed regulation on local governments

. N or did EPA‘s analysis exten d to which costs to loca l governments may be paid with f

ederal financial assistance or otherwise paid for by the Federal g overnment, 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 submi ts 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 developin g 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 Wa shington 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

elec ted 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 change d 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 ques tions or re quests from state o r 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, Nat ional Conference of State Legislatures, Council of State Governments, National League of Cities, US Conference of Mayors, National Association of Count ies, International City/County Management Association, National Association of Towns and Townships, Count y 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 pub lic power (along with investor

– owned utility) representatives to a meeti ng to discuss the potential regulatory impacts of th e 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 lo w

- 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 s tate, local, and tribal

gover nments, 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 f ederal law under which the rule is being promulgated; (2) a qualitative and quantitative assessment of the anticipated costs and benefits of the f ederal mandate, including the co sts and benefits to s tate, local, and tribal governments or the private sector, as well as the effect of the f ederal mandate on health, safety, and the natural

environment and such an assessment shall include

— (A) an analysis of the extent to which such c osts to s tate, local, and tribal governments may be paid with f

ederal financial assistance (or otherwise paid for by the f ederal

g overnment); and (B) the exten t to which there are available f ederal 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 f ederal mandate; and (B) any disproporti onate budgetary effects of the f ederal mandat e upon any particular regio ns of the nation or particular s tate, 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 e stimates 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 s tate, local, and tribal governments;

(6) a summ ary of the comments and c oncerns that were presented by s tate, 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 b efore establishin g 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 f ederal 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. Moreove r, 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 me etings 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 a nalysis, 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 signific ant 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) an d 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 ma de 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 us eful 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 a dditional 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 cos ts 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 o perating budgets during a very difficult economic time. APPA

members are not

- for

- profit entities, and as such se rve no shareholders. Increasing operating costs on these power producers would be passed on directly to rate payers. Significantly increased c osts 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 like ly 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 gove rn 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 s ignificant 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 suc h 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 compli ance 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 th at 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 p a nel meeting on

December 2 , 2010 . T he SER panelists explained in December 2010 that under these current economic conditions they have constraints on their ability to raise capital for the c onstruction of control projects and to acquire the necessary res our ces in order to meet a three

- year compliance

deadline.

In t he propo sed rule , EPA id entified a number of mechanisms

- such as work practice standards, sub

categorization, health based compliance options, and emissions averaging

- that it explains will lesse n 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 im pact 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 pr esent 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 2508316

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. C oal plant emissions control retrofits to reduce SO 2 emissions cost o n 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 NO

x 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 p lants that repr esent smaller electricity sales and those that exist on the margin will be incrementally charged more by vendors and contractors. J ust as home buyers looking for home repair or modification during the housing bubble paid a large time

- dependent scarcity pr ice 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 performanc e 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

equ ivalent to purc hasing a new gas

- fired power plant. In effect, by not sub categorizing to consider the disproportionately high cost on small communities the EPA is dictating a fuel switch

. See the s ection on page 1 7 regarding the details of subcategorizing units ≤ 100 MW

. This subcatego ry 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 ha ve 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 pr oposal, 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 project s, and to acquire the necessary res ources 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 re trofit time. T he 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 I mpact Analysis (RIA) states that the U. S. Small

Business Admi nistration (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 prop osed. 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, 201017

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 (b y 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 explana tion 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 sub category related to space constraints since 2004 so th is 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

shoul d 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 unit s 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 sm aller communities (especially in the Midwest) where many of the retrofit s 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 co ntrols, 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

inves tor 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 sub category is created, is only 5%. Thus this subcategory is not a ―loophole‖ and should not concern the U. S. EPA or public health officia ls . See

Table 1 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 Applyin g 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 r eported 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 stand ards 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 0.000 040

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 Tune

Up Every 18

Months Boiler T une

Up 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

bas ed on "Beyond the

Floor" analysis) 40 35 92 127

Number in Non

Mercury HAP Best Performing 12%

Calculation 2

(Hg Limit is

based on "Beyond the

Floor" analysis)" 127 35 92 127

C olor Code: No color No change in Estima ted Emissions Standard

Yellow Increased value Orange Decreased Value19

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) Inabi lity 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 sod ium content. These coal ash residual costs resulting from the DSI technology were not mentioned or considered in the pro posed 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 rulemaki ng
, 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 c ommercial market due to its very high sodium content. T he 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 conver gence of many EPA regulations on the utility sector in a short timeframe. Clearly th e 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 D SI 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 m ean 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 7 5

.

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

21 http://www.astm.org/ABO UT/overview.html

22 An APPA member noted that i f 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 f ly 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 anoth er 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 sub categorize 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 not es 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 (es pecially 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 Requirem ents and Financing of Projects

T he 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 re sults of an independent APPA

- commissioned survey 24 of the p ublic power industry and the types of problems

that members will have in com plying 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 particula

r 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 conce rns 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 extension s for up to two additional two

- year pe riods and the source

- by

- source showings that g overnors and m ayors should provide to be eligible for such extensions from compliance.

23 National Emission Standards f or 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 G21

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 v iolation 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 expediti ously 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 exe mption 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 a nd 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 ea ch 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 ru le 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 Febr uary 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 publicat ion of the Ut ility 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 authori ty.

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 com pliance 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 Boiler s and Process

Heaters , USEPA, 76FR15662.

29 Ibid., 76FR15665.22

U. S. EPA provided limited discussion of the complianc e schedule requirements in the p reamble 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 sy stems 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

exp ected 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 time

frame as specified in CAA sect ion 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 disc ussion 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 non

mercury 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 s taggered 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 RT Os/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 am bient 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 r egulated 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 Sotkiewic z, 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 ad dition to t he foregoing discussion in the p reamble 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 ef fort 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 20 15, 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 sy stem 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 w ould 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

p reamble.

In summa ry, 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 SO 2 in the flue gas to SO 3 , which can pass t hrough 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 SO 2 control system. If these systems are as effective as U. S. EPA as sumes, it raises the question of why they have not been placed in service to mitigate basic SO 2 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 t o 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 retrofit ted 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 wa s 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 o f 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

mini mize the cost of retrofits, and resulting electricity price increases. A consequence of this process was that those sites which have not yet retrofit ted advanced SO 2 or NO

x control hardware will face

more difficult retrofits. And at sites which have alre ady 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 planni ng 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 feasi bility, 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 c onsidered 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, an d 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 b oiler 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 ha ve 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 Pro cess 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 PJM 37 presentation cited by U. S. EPA in the

p reamble summed up the industry‘s dilem ma 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 e very 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 tim ing 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 ut ilities

 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 i n 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 1 3 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% SCR 40 (typically the same utilities were retrofitting both). About one

- half planned to rep lace or supplement existing ESPs

with new FF s

. 41

 About one

- fourth were moving forward with plans based on the notice of proposed rule (N O PR). 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 f rom 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 re spondents 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 p lans 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 cri terion 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 ther eby 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 sta ted 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 add ress 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 retrof it 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 retro fit 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 c ompliance 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 retr ofits. 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 retr ofitting 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 fil ter 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 co uld 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 powe r 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 sec ond 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 tim e 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 avera ges 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 a gency‘s compliance time analysis. For example, U. S. EPA‘s expectation of significant planning activ ity 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 b efore 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 misste ps.

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 p reamble 42 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 p reamble 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 S ection 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 eve n 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 utilit ies. 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 co mpleted within the compliance date deadline

.

U. S. EPA‘s lack of consideration of resource requirements by other rules under development by the

a gency, and the assumption ― that almost all future APC retrofits can be completed far more quickly

than were his torical 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 powe r. 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 NO

x SIP

- call) created a strong incentive to control the most easily retrofit units f irst. 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 s tate and local
governments. U. S. E PA‘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 obligati ons to public utilities in the p reamble, 44 but appears to believe that convening meetings with nati onal associations representing s tate and local governments relieves the a gency of the need to propose and evaluate

substan tive 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 ext ra 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 pol lution 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 u p 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 comp ete 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

pur chase 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 faci lities 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 eith er 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 Regul ation 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 clea r that all agencies (including I ndependent agencie s 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 A pproaches :

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 pu blic. 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 principa l 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 t he 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 Regis ter /Vol. 76, No. 14 / Friday, January 21, 201131 (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 contai ning 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 a dministrator (or a state with delegated Title V Permitting authority) would generally gra nt such extensions on a c ase

- by

- case basis for an existing source up to one additional year. 42 U.S.C. §112(i)(3)(B), the a gency 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 Ta nks, 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

prepar e 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

comp liance 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 provid e any information that would justify establishing a source

category

- 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 Provis ions 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 ti me beyond that which is a nticipated 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.

AP PA‘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 ad ditional 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 be come uneconomical due to the proposed rule because of age, size, or l essened 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.

Fur ther

, the U.S. EPA has a series of anticipated revisions to the existin g National Ambient Air Quality Standards (NAAQS) for tropospheric ozone, PM 2.5 , SO 2 and NO

x standards. These

, combined with state implementation plan ( SIP ) changes and revisions to eff luent 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 filter s 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 g igawatts of control technology being installed

. APPA believes this is a significant underestimate of the needed controls and add itional 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 Mid west,
Southeast and So uthwest. Other reliable estimates performe d by industry experts show 531

g igawatts 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 techn ical 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 i naccuracies of the U. S. EPA‘s Regulatory Impact Analysis.

APPA believes that the U. S. EPA has grossly under estimated the number of coal

- fired generation retirements at only 9.9 GW, which is only three percent of al l 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 Tra nsport Rule)

. M any published studies project retirements above 40 GW , when viewed in combination and under certai n 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

―S ubcategorization‖) 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 pro pose 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 Admi nistration (and presumably OMB ) expressed

c oncerns 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 t ype or by geographic isolation (rural) ) were even proposed by th e 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 SBREF A 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 Midwe st) where many of the retrofit or conversions to natural gas will take place

.

46 American Coalition for Clean Coal Electricity34

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

u tilities 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 fue l 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

- y ear compliance date feasibility presumption about DSI technology for all coal types, and ―che ck the box‖ exercise s 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 alterna tives 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 cost

effective, 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 A nalysis 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 price s 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 r ange 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 generati on 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 assumptio n 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 projecte d 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 indicat ion 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 d epletion 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 po licy considerations

The Final MACT Should Provide For An Administrati ve 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 categor ical extension) to reduce the regulatory burdens of complying with the proposed MACT standards, the agency must37

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 curr ently 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 pow er plants.

One of the benefits of this program would be to reduce the administrati ve burden on the U. S. EPA and

s tate agencies. Since 1997 , EPA has brought enforcement actions for Section 112 air toxics violations in over 500 administrative penalty ca ses 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 Justic e. Without this administrative mechanism for streamlining noncompliance schedules into Title V permits, the U. S. EPA, De partment of Justice, and their s tate 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 fede ral 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 m eet 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 t hat 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 resu lt 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 t h e 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 lab or 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 pub lic 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 M ACT 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 proce dures 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 b attery 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 t he 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 noncomplia nce 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 an d 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, lengt hy 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

- by

case review an d determinations, though AOCs typically involve far l ess 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 inappropri ate. M oreover, 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 ano ther 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 tre atment 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 are39

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

Thr ough 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 perm its 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, e mission 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 pro cedures 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 appr oval 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 modi fications. 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 th ey would be anticipation of non compliance rathe r than in disco very of past non compliance.)

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 affi davits of the efforts that the city had40

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 det ermines 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 fo r 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 entere d 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 l ikely that adoption of a compliance plan procedure requires additional public

comment.

Even though the Title V and EPA‘s discretionary en forcement 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

com pliance 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 w ith the Statute. T here is no need for any revision of the standard for gas and oil unit s

.



## 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 PM 2.5

. 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 wh o 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 PM 2.5 is c ontrolled under ozone and regional haze regulatory programs and State Implementation Plans (SIP). Further, particulate matter is

scheduled to be review ed for residual risk, which may lead to tightening of ozone, PM 2.5 , SO 2 , and NO

x under the National Ambie nt Air Quality Standards (NAAQS).

APPA believes that the U. S. EPA should re propose the rule to require reasonable mercury
reductions consistent with the intent of Section 112 of the Clean Air Act without the41

extraneous control requirements on non

- methyl mercury. APPA believes that this re

proposal 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, alo ng 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 t imeline suggests six years to accommodate these complex steps. In some states, permitting agencies might require up to six

months for permit approval processes . S ince the Clean Air Act‘s ―pollut ion exclusion‖ has been removed, u tilities may well trigger Ne w 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 ad ded 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. Ev aluating the balance of plant / ancillary changes that will be needed

d. Dete rmination 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, whi ch 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 fabri c 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 6 2
, 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 c onversion 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 t he 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, UA RG paper, Edward Cichanowicz, 201142

5. APPA does not believe that the EPA sufficiently considered its ability within the Clean Air Act to

use General ly A vailable 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 p ollutants (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 b e 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 t he use of GACT during the Dec. 2 , 2010 SBREFA SER panel and this reasonable request was ignored.

It seems inexplicab le 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 achiev e a reduction in toxic air pollutants.

Add itionally, 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 disc ussed 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 B est D e monstrated T echnology (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

standar ds.

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 2 011) report identifying 14,000 M W to retire between 2011 and 2020.

 Brattl e Group‘s forecast that 67,000 M W of existing coal

- fired power plants to retire in

same timeframe.

 Black & Veatch‘s December 2010 analysis stating that 52,000 M W of coal capacity would

retire.

 FBR

, Capital Ma rkets‘ expectation that 4 5,000 M W 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

, Decemb er 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.pdf43

APPA believes that t he U. S. EPA sho uld 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 SO

x control technology cost

, on average
, three times more per MW when performed on smaller generating units. In addition , the price of compliance doubles for NO

x control equipment as the size of the unit approaches 50 MW. APPA believes that the EPA di d not adequately consider the disproportionately large cost of compliance on small communities

.

Source: Bernstein Research coal plant SO 2 control retrofit analysis of capital cost by generating unit size

These disproportionately high er costs for smalle r 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 stres s due to fal ling tax

revenue from f

ewer 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

p ress 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. E PA‘s estimate of benefits and c osts resulting from this proposed rule exaggerate the human health benefits dramatically because of its inclusion of PM 2.5

. Additionally, APPA believes that the costs were underestimated by not including many

smaller utiliti es 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 l etter, 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 o nline publication, May 18, 201144 the r ule includes an alternate surrogate CO limit for additional compliance demonstration flexibility. A s urrogate CO limit [if set at a reasonable level (i.e., 0.25 l bs/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 ran k, 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 combusti ons 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 pro vide 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 r emediation 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 , g eneration dispatch, in cluding but not lim ited 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 retire ment or a few retirements might be possible, but many retirements group ed 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

A n analysis of the time it takes the PJM to respond to a generator request to shut down shows that without reliability issues they are abl e t o 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 wit h 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 sig nificant downtime as a majority of the existing fleet upgrades to environment al 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.ashx45  N

- 1

- 1 Thermal Violations,

 Generation Deliverability Violations,

 Common Mode N

- 1 Contingency Thermal Study Violations,

 C ommon 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 majo r 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 l ow load season has its r isks. 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 o n 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 Protec tion (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 genera ting 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 r esource identified in a transmission o perator‘s restor ation plan: (337 using

CIP

- 002

- 3, 540 using this criterion)

- 203 additional units

 Each generation f

acility necessary to avoid BES Adverse Reliability Impacts in the long

term 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 Relia bility 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, system s, 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.pdf46

Standard CIP

- 002

- 4

. S ome of th ese 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 Hom eland Security Procedures for handling P rotected Critical Infrastructure Information (PCII); Final Rule September 1, 2006: http://www.dhs.gov/xlibrary/assets/pcii_final_rule_federal_register9

- 1

- 06

- 2.pd f

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 an d reque sted 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. T he EPA did not properly and thoroughly investigate and address the significant cost imposed on all businesses that consume electricity by th is proposed rule
, therefore it should attempt to address the unproductive cost s 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. t he plants ar e determined to be

efficient by the market mechani sm ), 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 p lant 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 ref

lecting at least the compliance costs paid by other plants. RTO markets

therefore create an entire ly 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 electric it y consumers resulting from this rule. ) APPA bel ieves 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 t he 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 a t 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 g raphical 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 b aseload 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 onl y 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 approxi mately 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 signific ant 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 CO 2 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 : Sourc e

- 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

electrici ty market price increase

.

17. U. S. E PA 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 num ber of power plants within three years. APPA has p ointed 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 re quire a

p residential 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 be lieve 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) need s at least 5.5 years and perhaps as long as 77 months for planning, pro curing, construction, installation, and calibration. APPA believes the p residential 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 6 2

.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 utili ties, 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 p rovides 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 implemen t 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 exemption s 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 su pply 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 replac ement 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

assertion s of jobs to be lost on a state

- by

- state basis. The A merican C oalition for C lean C oal

E lectricity (ACCCE) took the EGU MACT proposed rule and the soon to be final Regional Transport R ule and determin ed 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 f

or 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 up s , shut down s and
malfunction s

. This is especially a concern because of the increasing number of ― load

following ‖ coal

- fired power plants backing up wind and solar power pl ants. The ramping up

58 http://www.publicpower.org/files/PDFs/ImplicationsOfGreaterRelianceOnNGforElectricityGeneration.pdf

59 http://www.publicpower.org/files/PDFs/IssueBriefWindfallProfitsandEPARegsMarch2011.pdf51 and down a s 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 Ne w 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 F ederal Cou rt 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 betw een 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. Fail ure 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 w ith Respect to Complying w ith the Proposed MACT Standard for Existing Units , Par ticularly If U. S. EPA Fails To Take

t he Recommended Actions To Reduce the Regulatory Burdens o f Complying w ith t he Proposed MACT.

Section 112(d)(4) of the Act provides that the Administr ator may distinguish among clas s es
, t ypes, 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 c arefully 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 ar e 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 public52 power and rural electric cooperatives that will make compliance with the proposed standards uniquely difficult:

(1) M any m

unicipal utilities are sp ace

- constrained and cannot build laterally. They must build vertically, but this makes co nstruction 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 an d possibly off

- site gas turbines for peaking. Quite a few also own wind and/or solar generation that provide s an interruptible

p ower 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 me rcury, but to reexamine the sub categorization 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 a chieved 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 mus t 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 nece ssitated it.

II. The Clean Air Act

A. APPA defers to the UARG letter on the legal and policy issues related to the various Cl ean Air Act p rograms, including the interplay of NSPS, NAAQS, PSD (BACT) and nonattainment

programs
, such as Lowest Available Emission s 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 PM 2.5 etc. APPA believes that the U. S. EPA has exaggerated the health and economic benefits of the proposed rulemaking by asserting benefits from PM 2.5 contr ols 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 PM 2.5 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 o f 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 co al

- 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 Sou rce: 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 heal th 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 associate d 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 th an 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 b een 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 thre e ways to comply:

(1) 0.015 lb/MBtu; (2) 0.14 lb/MWh (24

- hr avera ge); 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 o f Method 5 (filterable PM) plus Method 202 (condensable PM) and includes periods of startup /shutdown/malfunction. PDF, see pg . 487

- 88 of the pre

publication 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 f or 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.

Alternati vely; the limit of 15 ng/J was converted incorrectly from 0.034

lb/MMBtu

.

B. U. S. EPA Sho uld Rescind Its Proposal and Rep ropose its Defective NSPS Rule

1. U. S. EPA misstated the limit for modified boilers. The regulated community cannot provide intelli gent comment on the a gency‘s proposal and therefore the U. S. EPA

sho uld rescind its proposal and re propose the rule after correcting these defects.

C. U. S. EPA’s Choice of Best Demonstrated Technology Is C ontrary to Law

APPA defers to UARG in the more t horough 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 al low 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 Technolog

y. APPA defers to UARG‘s more thorough co mments 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 str ingent 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 ar bitrary 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 ha s not identified what the condensable is and how to control it, so the a gency cannot identify BDT or set an NSPS. (b) EPA‘s proposed rule eliminate s ESPs as a control option

. 1. APPA defers to UARG‘s more detailed comments regarding technical work to

be c ompleted both for new ( proposed as 0.006 lb/MBtu ) and for modified

units. 2. APPA defers to UARG regarding U. S. EPA‘s option tha t ESPs should be

retained as a control option.

E. APPA agrees with UARG that the U. S. EPA’s proposed NSPS is not a chievable

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 bas is to propose NSPS.

The data fo r these units differ from those employed for SO 2 and NO

x in that most data sets are limited to three independent, discrete measurements. A significant challenge in using data from these reference units is properly accountin g 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 o f 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 a gency‘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 variable s

. 62

UAR G 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 well

performing ESP at new units

. 63 APPA agrees with this analysis . S tarting with an average emi ssion 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 SO 2 NSPS

A. Background

1. New and reconstructed boilers. For most units, the current NSPS is 1.4 lb/MWh (0.16

lb/M Btu) or a 95% reduction.

a. U. S. EPA proposed 1.0 lb/MW h (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 tha t 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 propos al and rep ropose its defecti ve
NSPS rule

1. It is unclear to APPA in the proposal w hat 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 propose d 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 p reparation 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 re asonable 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 contr ol technology equipment , finance, permit , in stall 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 SO 2 NESHAP limits for new units are as stringent or more stringent. ( PDF, pp. 538

- 39 of pre

proposed rule. ) Yet § 111(a)(1) requires EPA to ―tak[e] into consideration the cost of achieving such reduc tion . . . .‖

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 remind s the U. S. EPA that UARG provided comments in January, 2011 on

what could constitute N SPS. 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 rem inds 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 na tionwide, regardless of specific fuel, climate, water availability, and many other highly case

- specific factors. As discussed below, U. S. EPA‘s proposed NSPS for SO 2 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 SO 2 emissions from representative units and concluded that combustion controls and FGD

at 24 new units and 32 retrofit ted units could achieve 1.3 lb/MW

- h (0.14 lb/MMBtu)

and a 96% removal efficienc y. 65 To justify its proposed revisions to the NSPS for

SO 2 , 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 SO 2 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 SO 2 controls at the newest units to lime

based dry FG D. 66 Analyzing both new and recent retrofits to ex isting 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 e ight new units that U. S. EPA

65 Cichanowicz, Discussion of Factors Affecting New Source Performance Standards for SO 2 , 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 Appen dix N

. One new unit (Spurlock Unit 3) has a fluidized bed design that is atypical of pulverized coal boilers and which inherently provides SO 2 removal through the limestone

- containing bubbling bed. Both the magnitude and variability of the SO 2 emissions f rom 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 fi ring PRB coal and using

lime

- based dry FGD with a fabric filter. This combination of coal and equipment provides stable and well

- controlled SO 2 emission s. 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 UAR G, 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 SO 2 improperly accounts for variability

. Table 17 reports for 15 units the highest 30

- day SO 2

remo val efficiency average based on daily averages of SO 2 emissions and monthly averages of coal sulfur content. As explained in detail in the Cichanowicz Report, 71

U. S. EPA’s SO 2 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 ―ma rgin‖ 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 nu mber of violations of the regulatory limit, which

is a measure of the risk of non compliance. This means U. S. EPA’s 97% SO 2 removal rate is at odds with U. S. EPA’s historical methodology in NSPS rulemakings, and results in a proposed NSPS that is not ach ievable 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 Syst ems 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 burn ing 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 SO 2 outlet rate or the percent SO 2 removal, a clear indication that U. S. EPA‘s proposed NSPS for SO 2 is

not achievable. U. S. EPA should apply UARG‘s and EPA‘s historical approach to variability.

UARG has provided the 30

– day SO 2 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 SO 2 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 SO 2 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 analyze d, the first calculated 30

- day SO 2 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 th e va lues of SO 2 emission rates should be increased to at leas t 1.30 lb/MWh to account for SO 2 startup. Otherwise, the U. S. EPA‘s proposed NSPS for SO 2 are not achievable as a

national standard.

VI. Proposed Revisions to NO

x 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 NO

x NSPS of 0.70 lb/MWh (based upn 30

- day roll) for new, reconstructed and modified units. This include s 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 pr eferred approach for new and

reconstructed boilers of 1.2 lb/MWh (0.13 lb/MBtu) for NO

x + CO

a. This standard is derived from 0.08 lb/MBtu NO

x ; 0.05 lb/MBtu CO (70 ppm @3% O 2 )

4. The U. S. EPA is also proposing its alternative and preferred approach for mo dified boilers of 1.8 lb/MWh (0.20 lb/MBtu) for NO

x + CO

72 Id. at __.

73 Id. at Table 2

- 1.

74 I d. at Table 2

- 2.60 a. This is derived from 0.08 lb/MBtu NO

x ; 0.12 lb/MBtu CO (160 ppm @3% O 2 )

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.

VI I. U. S. EPA Should Use Gross Output, Not Net Output, to Set NSPS

U. S. EPA has proposed output

- based NSPS for PM, SO 2 and NO

x 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 net

energy 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 u tility 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 auxili ary station transformers and then is distributed to the various load centers for power

- consuming auxiliarie s. 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 exi sting 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 decrea ses 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 an d 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

. Co al

- fired power plants that are required by U. S. EPA‘s rules to use equipment to control PM, SO 2 and NO

x 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 wa ter 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 widel y 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 th e 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 encoura ging 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 th at ―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 ca pture 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 energ y 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

genera te 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 green house 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 requir ing 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 u se of control technologies.
Such an approach would make NSPS especially stringent for coal (or natural gas fired) units that deploy geologic sequestration of CO 2 (or CCS). While APPA remains skeptical that CCS

will be commercially demonstrated for widespr ead application in the utility sector within the

81 Id

. 82 Id . at Figure 262 next decade, we certainly do not want to see the parasitic power issue make CCS less

economical or attractive as a solution for CO 2 due to the unintended consequences that might

result in the EGU MACT rulema king.

VIII. IGCC Units Should Continue To Be Regulated Under Subpart Da, Not Subpart KKKK
A. The U. S. EPA proposes that IGCC units that co produce hydrocarbons or hydrogen be subject

to the combustion turbin e NSPS because using new output

- based standards woul d 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 extension s 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 P resident 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 Stat es 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 complian ce 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 ex tension 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 describe d 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 technica l impediments to repowering and/ or retrofitting publicl y 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 m ayor 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 other63

words, APPA submits that these procedures should b e based on need and the demonstration of good faith progress toward compliance, not Clean Air Act technology

- based showings.

XI I . Monitoring Issues (testing compliance and maintenance)

APPA fully supports UARG’s comments on the emissions testing, complia nce 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 affec ted units 83 . 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 ha d 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 penetratio ns that comprise 33% of the stack circumference.

Clearly, drilling three new penetrations wo uld carry the risk of weakening c himney structure at EGUs across the nation. This poses not only a worker and community safety ramification, but also impacts gri d 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

mo nitoring 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 emp loy 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 a nd 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 us ing 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 m onitoring 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, f low, and

SO 2 /NOx/diluent, which may or may not be combined in o ne 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, th e 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 littl e 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 63.100 11(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 limit s 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 a nd PM CEMS, with the HCl limit using HCl CEMS or an SO 2 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. E PA 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

SO 2 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, source s 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 SO 2 as a surrogate for

HCl mus t test for HCl in addition to the SO 2 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 testin g 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 SO 2 CEMS to condu ct ―all applicable performance tests‖ for SO 2 and HCl annually and, for units with SO 2 controls, to65 conduct SO 2 emissions testing ―at least every other month.‖ See also Preamble, 76 Fed. Reg. at 25,051.

These requirement s are duplicative and must be re moved. 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 app licable 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 em ission 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 Complianc e 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 shoul d 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 m onitoring 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 t esting

The requirement for annual PM te sting at EGUs that choose to comply

with the non

- Hg me tals 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 requirements66 (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 m etals

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 da te 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 t o 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 specificati on, 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 option s.

(2) U. S. EPA must clarify the subsequent performance testing requirements for units “without SO 2 CEM”

Proposed § 63.10006(h) require s EGUs ―without SO 2 CEMS but with installed systems that use wet or dry flue gas desulfurization technology‖ to conduct ―al l applicable performance

tests for SO 2 and HCl emissions‖ at least every year and to ―conduct SO 2 emissions testing‖ at least every month. Proposed § 63.10006(i) requires EGUs ―without SO 2 CEMS and without installed systems that use wet or dry flue gas de sulfurization technology‖ to conduct ―all applicable performance tests for SO 2 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 H Cl CEMS. As discussed above, there is no basis for testing of the surrogate SO 2 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 SO 2 performance t esting or an SO 2 emissions standard other than those applicable to units with SO 2 CEMS. Obviously, U. S. EPA did not intend and would have no basis to require EGUs to use both an HCl CEMS and an SO 2 CEMS.

(3) The p roposed HCl Limit is at or near the detection limit for current

HC l 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 prop osed 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 SO 2 for units without SO 2 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 SO 2 at a unit that is complying with the HCl stand ard. In addition, the proposed rule does not provide any procedure for SO 2 performance testing or an SO 2 emissions standard other than those applicable to units with SO 2 CEMS. Obviously, U. S. EPA has no basis to require EGUs that choose to comply throug h stack testing to also install an SO 2 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. SO 2 CEMS

(1) U. S. EPA should clarify t he requirement for use of SO 2 con trols

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 SO 2 controls intermittently, and not to disqualify EGUs that experience SO 2 control device malfunctions or that must turn off controls to perform maintenance. The higher SO 2 recorded by the CEMS during such periods will reflect the poten tial 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 SO 2 standard.

(2) U. S. EPA should allow all part 75 exceptions

Proposed 63.10010(e) allows use of an SO 2 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 subseq uent 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 with out 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 SO 2 CEMS. As discussed above, there is no basis for testing of HCl at a unit that is complying

with the surro gate SO 2 limit.

(4) U. S. EPA should add reference to use of part 75 in the continuous compliance provisions68 Proposed § 63.10021(a)(13) sets out the ongoing requirement for SO 2 CEMS. The proposed requirements are similar to proposed § 63.10010(e), except thi s 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 a nd 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. Preamb le 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 accura cy of Hg CEMS at or near the proposed Hg limit

for exi sting sources is questiona ble

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 th e 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 LEEs69 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 oper ating 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 devi ce 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 exceed ing those limits therefore indicate s an exceedance of the emission limit as w ell. 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 li mit, 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 i f 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 so urces 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 perfo rmance 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 sou rces 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 ―pos sible 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 wi th 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

E SP. 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 th ose 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 lo ad 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 fr om 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, impositi on 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 wi th 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 scrubbe r 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 f

or 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 Du ring 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 star tup. Id.

U. S. EPA‘s preamble assertions regarding startup and shutdown are inapplicable to control device operating parameter limits, which ar e based on 12

- hour averages (30

- day rolling averages) established during performance test s (not based on CEMS d ata 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 par ameter 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 unreasonabl e. 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

- d ay rolling averages with SSM could result in exceedances of the 30

- day

standards. Th e 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

foll owing 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/ M Mbtu (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 t he nu mber 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‖) i s 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 emissio ns. 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 exceedan ce. 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 wo uld take to exceed
the U. S. EPA‘s 30

- day s tandard 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 : G raph 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 Agree s 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

leve l 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, unit s 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 withou t 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 operatin g 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 subject ing 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

detect ing 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 duratio n of alarms does not exceed 5% of the operating time during any 6

- month period. Proposed §§ 63.10011(b)(6)(v);

63.10 21(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 demo nstrate 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 manufa cturer. 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

X V

. 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 na tional 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 betwe en investor, electric co

op 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 ). Appen dix O shows the Guam Oil

- Fired capacity units and

date of installation

. 85

X VII

. 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 comme rcially 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.html75 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 sodi um 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 commun ity 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 bet ween 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

Util ity 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 Agenc y 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, N ovember, 2010.

Disposal of CCRs as hazardous waste (estimated at the very conservative fig ure 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 EP A 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 incr eases 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 b e $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 a c tivated 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 residua ls 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 associated76 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 2 009 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 injectio n and ACI technologies by power generation facilities, however, will render the vast majority of this approximate ly 12 million tons of CCRs generated annually unfit for these beneficial use applications, causing this significant volume of CCRs to have be d isposed 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 fo r 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% ava ilable 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 rec lamation 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 Reduc tions 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 f or 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 c an typically replace between 15% and 30% o f 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 nearl y 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, equ ivalent 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

uni ts 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, g rain 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 S ee also Testimony of Barry Breen, Acting Assistant Administrator Office of Solid Waste and Emergency Response before the House
Committee on Transportation and Infrastruc ture, 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

r ailroad 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 ar e 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 consequ ences 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 rel iant 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 t o 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 subcategoriz e between eastern and western coal represents a serious technical flaw which is unlikely to survive judicial challenge.

Conclusion s

Essential Corrections to EGU MACT Rule:

1) U. S. EPA should re

- propose the rule and the f inal EGU MACT should not include aci d 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 flexibi lity including subcategories for public power, electric co

ops, 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 C IP 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 Clea n Air Act regulations.79

 APPA believes that the U. S. EPA has grossly under estimated the number of coal

- fired generation retirements at only 9.9 GW, which is only 3% of al l coal

- fired capacity

, by the year 2015

.

 Natural g as prices for consumers and utilities will almost certainly increase more than projected by

U. S. EPA's RIA

.

 APPA believe s that three years from the date of publication of the final rule is an unrealistic timeline for compliance given the need for municipal government s 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 pro jects 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 compl iance 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 NESHA P program by adding extraneous regulatory controls for acid gases and PM 2.5

.

 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 analys is 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 b elieve 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 s pace 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 p lants 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 PM 2 .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 SO 2 , PM, and NO

x are NOT Achiev able.

 U. S. EPA did not properly and thoroughly investigate and address the significant cost s 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 du e 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 require d 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 c ompliance 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, 201182



## Appendices

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

www.publicpower.org/fil es/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. S mall B usiness A dministration (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 E GU 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%2D1 1.pdf

J. Neophytes Guide www.publicpower.org/files/Neophytes%20Guide.pdf

K. Why New CO 2 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. 2 4 , 2011 www.publicpower.org/ files/Retire%20or%20retrofit%20%2D%20%20A%20look%20at%20 US%20regional%20scrubbed%20coal%20capacity.pdf83 Upcoming, Recent Coal

- Fired Power Unit Retirements, SNL Energy Data Dispatch Article,

Feb. 2 2 , 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 Techno logies by Ed Cichanowicz www.publicpower.org/files/PDFs/CichanowiczCostEffectiveness.pdf

O. Guam‘s Oil

- Fired Ca pacity 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 L ow 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 Caterp illar 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 Ul tra 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