SUPPORTING STATEMENT

STANDARDS OF PERFORMANCE FOR NEW AND EXISTING STATIONARY SOURCES:
ELECTRIC UTILITY STEAM GENERATING UNITS: FINAL RULE

EPA ICR No. 2137.02

	

PART A										

1.0  Identification of the Information Collection

(a)  Title and Number of the Information Collection.

(Standards of Performance for New and Existing Stationary Sources: 
Electric Utility Steam Generating Units(Final Rule).( This is a revision
of EPA ICR 2137.01 that was originally titled at proposal, (NESHAP for
Coal- and Oil-Fired Electric Utility Steam Generating Units:  Proposed
Rule (40 CFR Part 63, subpart UUUUU).(  This revision incorporates the
new burden estimates that have been made for the recordkeeping and
reporting requirements in the final rule.  As explained below, we
received no comments from OMB or the public on the burden estimates in
the initial version of the ICR that was docketed with the proposed rule.

(b)  Short Characterization.

Respondents are owners or operators of existing and new coal-fired
electric utility steam generating units (Utility Units) capable of
firing more than 73 megawatts (MW) (250 million Btu/hour) heat input
including industrial cogeneration facilities that sell more than 25 MW
of electrical output and more than one-third of their potential output
capacity to any utility power distribution system.  The final rule
amends 40 CFR parts 60, 63, 72, and 75 to establish standards of
performance for mercury (Hg) for new and existing coal-fired Utility
Units, as defined in Clean Air Act (CAA) section 111.  For the purpose
of implementing the final rule, a coal-fired Utility Unit is an electric
utility steam generating unit that burns coal, coal refuse, or a
synthetic gas derived from coal either exclusively, in any combination
together, or in any combination with other supplemental fuels (e.g.,
petroleum coke and tire-derived fuels).

The final rule amends 40 CFR parts 72 and 75 to establish a mechanism
by which Hg emissions from new and existing coal-fired Utility Units are
capped at specified, nation-wide levels.  Under this cap-and-trade
program, the EPA assigns Hg emission allocations or (budgets( on a
State-by-State basis.  Each State and affected Tribal government
participating in the cap-and-trade program has the flexibility to
distribute however they choose their assigned total Hg emission budget
to each of the coal-fired units operating under their jurisdiction, so
long as certain timing requirements are met.  States and affected Tribal
governments may choose to participate in the EPA-administered
cap-and-trade program.  They can adopt the Hg cap-and-trade program
either by incorporating by reference the model cap-and-trade rule
promulgated by this rulemaking under 40 CFR 60 subpart HHHH or codifying
the provisions of the rule, in order to participate in the
EPA-administered Hg cap-and-trade program.  The program is designed to
integrate with the existing sulfur dioxide (SO2) and nitrogen oxides
(NOx) emission cap-and-trade program under the Agency(s Acid Rain
program and final Clean Air Interstate Rule (CAIR).

In addition, the final rules amend the new source performance standards
(NSPS) for Utility Units in 40 CFR 60 subpart Da by adding Hg emission
limits for coal-fired Utility Units (oil-fired and gas-fired Utility
Units are not subject to the Hg emission limits).  Separate NSPS
emission limits expressed in units of pounds of Hg per gross-MW output
are established by coal subcategories:  bituminous coal, subbituminous
coal, lignite, coal refuse, and synthetic gas derived from coal (i.e.,
integrated gasification combined cycle (IGCC) units).  Compliance with
the applicable emission limit is determined on a 12-month rolling
average basis.  These new units are included under the Hg emissions
cap-and-trade program.

Only those coal-fired units for which construction, modification, or
reconstruction is commenced after January 30, 2004, are subject to the
Hg emission limits in subpart Da.  However, all affected coal-fired
Utility Units existing on, or constructed after, January 30, 2004, can
participate in the Hg cap-and-trade program.

Under the final rule, existing affected coal-fired Utility Units with
Hg emissions at or below 29 lb of Hg per year are designated as (low
mass emitters( or LME.  Owners and operators of LME units are required
to perform periodic Hg emission testing.  Owners and operators of
existing affected coal-fired Utility Units with Hg emissions greater
than 29 lb of Hg per year and all new affected coal-fired Utility Units
are required to use a Hg continuous emission monitoring system (CEMS) or
a Hg sorbent trap method for semi-continuous Hg sampling.  The
rulemaking finalizes Performance Specification 12A, (Specification and
Test Methods for Total Vapor Phase Mercury Continuous Emission
Monitoring Systems in Stationary Sources( in 40 CFR part 60, appendix B,
and (Quality Assurance and Operating Procedures for Sorbent Trap
Monitoring Systems( in appendix K to 40 CFR part 75.

Owners and operators of existing coal-fired Utility Units maintain
records and report their emissions following the requirements 40 CFR
part 75.  The final rule amends these existing requirements to include
information used to demonstrate compliance with a coal-fired Utility
Unit(s Hg emissions allocation.  Source information management,
emissions data reporting, and allowance trading is conducted through
electronic data systems similar to those currently used for the Acid
Rain SO2 and NOx SIP Call programs.  Reporting and recordkeeping
requirements for the Hg cap-and-trade program are summarized in Exhibit
1.

In addition, owners and operators of those affected coal-fired Utility
Units subject to the NSPS under 40 CFR 60 subpart Da are required to
prepare site-specific compliance plans; submit notifications of
compliance status and semiannual compliance reports; and maintain
records of specific information to ensure that the rule requirements are
being achieved.  The final rule amends these existing requirements to
include specific information about the Hg monitoring and compliance
determinations used by the owner or operator to demonstrate compliance
with the applicable Hg emissions limit.  Reporting and recordkeeping
requirements for subpart Da are summarized in Exhibit 2.

2.0  Need for and Use of the Collection

(a)  Need/Authority for the Collection.

CAA section 111 establishes authority for the EPA to regulate
categories of stationary sources which cause, or contribute
significantly to, air pollution which may reasonably be anticipated to
endanger public health or welfare.  CAA section 111(b) authorizes the
EPA to establish NSPS that reflect the application of the best system of
emission reduction which (taking into consideration the cost of
achieving such emission reduction, any non-air quality health and
environmental impact and energy requirements) the Administrator
determines has been adequately demonstrated.  To implement and enforce
NSPS, certain types of information are needed by the EPA to:  (1)
confirm the compliance status of affected sources and identify new or
reconstructed sources subject to the standards; and (2) ensure that the
applicable standards are being achieved.  These recordkeeping and
reporting requirements are specifically authorized by CAA section 114
(42 U.S.C. 7414) and are codified in the NSPS General Provisions (40 CFR
60 subpart A) and in the applicable source-specific rule (in this case
40 CFR subpart Da).

Existing sources are addressed under CAA section 111(d).  The EPA can
issue standards of performance for existing sources in a source category
only if it has established standards of performance for new sources in
that same category under CAA section 111(b), and only for designated
pollutants, as that term is defined in the final rule.  (CAA section
111(d)(1)).  CAA section 111(d) authorizes EPA to promulgate standards
of performance that States must adopt through a SIP-like process, which
requires State rulemaking action followed by review and approval of
State plans by EPA.  If a State fails to submit a satisfactory plan, the
EPA has the authority to prescribe a plan for the State.  (CAA section
111(d)(2(A)).  The EPA is interpreting the term (standard of
performance,( as applied to existing coal-fired Utility Units, to
include a Hg cap-and-trade program.  The final standards, which include
recordkeeping and reporting requirements, will be published at 40 CFR
part 60, subpart HHHH.

(b)  Use/Users of the Data.

The information required by the final rule will be used by State and
EPA enforcement personnel to ensure that the cap-and-trade program Hg
emissions allocation and the NSPS emission limit, as applicable to a
given coal-fired Utility Unit, are being achieved.  Based on review of
the recorded information at the site and the reported information, the
EPA can identify units that may not be in compliance and decide which
facilities require additional compliance or enforcement action.

3.0  Nonduplication, Consultations, and Other Collection Criteria

(a)  Nonduplication.

A computer search of the Federal Information Locator System indicated
that there are no similar information requests being carried out by the
Federal government, with the exception of the provisions of the NSPS for
Utility Units and the Acid Rain cap-and-trade program related to SO2 and
NOx emissions.  These programs have similar reporting and recordkeeping
requirements but do not involve the monitoring of Hg emissions;
therefore, there is no duplication of effort.  A similar search of the
EPA(s ongoing ICR(s revealed no duplication of information-gathering
efforts.  Certain reports required by State or local agencies may
duplicate information required by the final rule.  Sources, therefore,
may submit to EPA a copy of the report submitted to their respective
State or local agency provided the information in that report satisfies
the requirements of the final rule.

(b)  Public Notice Required Prior to ICR Submission to OMB.

This section is not applicable because this is a rule-related ICR.

(c)  Consultations.

The proposed rule was posted on the Agency(s Internet website and
entered into the docket (OAR-2002-0056) for public review.  Following
publication of the notice of proposed rulemaking (NPR) in the Federal
Register (69 FR 4652; January 30, 2004), a 60-day public comment period
ensued.  Concurrent public hearings were held in Research Triangle Park,
NC, Philadelphia, PA, and Chicago, IL, on February 25 and 26, 2004, at
which time any member of the public could provide oral comment on the
NPR.  On March 16, 2004, a supplemental notice of proposed rulemaking
(SNPR) was published in the Federal Register (69 FR 12398).  On March
17, 2004, EPA announced that the public comment period on the NPR and
SNPR had been extended to April 30, 2004.  A public hearing on the SNPR
was held in Denver, CO, on March 31, 2004, during which time members of
the public could provide oral comment on any aspect of the NPR or SNPR. 
On May 5, 2004, EPA announced (69 FR 25052) that the public comment
period for the NPR and SNPR had been reopened and extended until June
29, 2004.  On December 1, 2004, EPA published a notice of data
availability (NODA) with a public comment period until January 3, 2005
(69 FR 69864).

In addition to the above-noted public comment process, EPA met with a
number of stakeholder groups and has placed in the docket records of
these meetings.  Approximately 500,000 public comments were received
during the comment period, indicating wide public interest and access.

At proposal, the draft information collection request was submitted to
OMB for review and was also posted on the Agency(s Internet website and
entered into the docket (OAR-2002-0056) for public review.  EPA received
no comments specific to the information collection burden identified in
the initial ICR in support of the proposed rule.  As explained further
below, this revision incorporates the new burden estimates that have
been made for the recordkeeping and reporting requirements in the final
rule.  We modified these burden estimates, in part, because of  certain
changes made to the monitoring requirements in the final rule in
response to comments.

(d)  Effects of Less Frequent Collection.

If the relevant information required by the final rule were collected
less frequently, the EPA would not be reasonably assured that a Utility
Unit is in compliance with its annual cap-and-trade program Hg emissions
allocation and the 12-month rolling average NSPS emission limit, as
applicable to a given coal-fired Utility Unit.

(e)  General Guidelines.

The final rule would require owners or operators of an affected source
to retain records for 5 years, which exceeds the 3-year retention
period contained in the guidelines in 5 CFR 1320.10.  40 CFR 60.7(f)
requires that records be retained for at least 2 years.  The 5-year
retention period is consistent with the requirement in the operating
permit program under Title V of the CAA.  These records must be kept on
file for use, if needed, by the regulating authority to ensure that the
plant personnel are operating and maintaining the unit and the control
equipment properly.  All subsequent general guidelines have been
followed and do not violate any of the Paperwork Reduction Act
guidelines contained in 5 CFR 1320.

(f)  Confidentiality.

All information submitted to the EPA for which a claim of
confidentiality is made will be safeguarded according to the Agency
policies set forth in Title 40, Chapter 1, part 2, subpart B --
Confidentiality of Business Information (see 40 CFR 2; 41 FR 36902,
September 1, 1976; amended by 43 FR 39999, September 28, 1978; 43 FR
42251, September 28, 1978; 44 FR 17674, March 23, 1979).

(g)  Sensitive Questions.

This section is not applicable because this ICR does not involve matters
of a sensitive nature.

4.  The Respondents and the Information Requested

(a)  Respondents/NAIC Codes.

Potential respondents under the final rule are owners or operators of
coal-fired Utility Units; oil-fired and natural gas-fired units are not
affected.  The NAIC codes for this industry are 221112 (Fossil
Fuel-Fired Steam Generating Units (including those owned or operated by
the Federal government or municipalities) and 921150 (American Indian
and Alaska Native Tribal Governments.(

(b)  Information Requested.

(i)  Data Items, Including Recordkeeping Requirements.  Exhibits 1 and
2, Source Data and Information Requirements, summarize the recordkeeping
and reporting requirements in the final rule.

(ii)  Respondent Activities.  The respondent activities required by the
final rule are identified in Exhibit 3 and introduced in section 6(a).

5.0  The Information Collected(Agency Activities, Collection
Methodology, and Information Management

(a)  Agency Activities.

A list of Agency activities is provided in Exhibit 4 and introduced in
section 6(c).

(b)  Collection Methodology and Management.

This is not relevant to this information collection request.

(c)  Small Entity Flexibility.

According to the Small Business Administration size standards for the
NAICS categories, a small entity is a small business that, including its
affiliates, is primarily engaged in the generation, transmission, and/or
distribution of electric energy for sale and whose total electric output
for the preceding fiscal year did not exceed 4 million Megawatt hours
(MWh). 

This rule would not directly establish requirements applicable to
existing small entities.  Instead, it would require States and affected
Tribal governments to develop, adopt, and submit a plan that would
achieve the necessary Hg emissions reductions, and would leave to the
States the task of determining how to obtain those reductions, including
which coal-fired Utility Units to regulate.

EPA(s analysis of the final rule found that the rule would not have a
significant impact on a substantial number of existing small entities. 
Analysis conducted for the final rule projects that in 2020, two years
into the start of the second phase of the cap-and-trade program, the
total compliance costs to small entities under the rule would be
approximately $37 million.  This is just under 1 percent of the total
projected electricity generation revenues to small entities for 2020.  A
few of the 80 small entities identified in EPA analysis may experience
significant costs in 2020.  These entities do not bank allowances over
the course of the program, and must purchase allowances in 2020 to cover
their emissions.  It is important to note that the marginal cost of Hg
control in 2020 projected by EPA modeling is largely responsible for the
presence of significant impacts.  The EPA modeling assumes no
improvements in the cost or effectiveness of Hg control technology over
time.  In reality, by 2020, costs of Hg control are expected to have
declined, such that the actual impacts of the cap-and-trade program on
small entities will be less than projected.  Additionally, given that
most of the small entities identified operate in market environments in
which they can pass on compliance costs to consumers, most of these
entities should be able to recover their costs of compliance with the
rule.

Two other points should be considered when evaluating the impact of
final rule, specifically, and cap-and-trade programs more generally, on
existing small entities.  First, under the final rule, the cap-and-trade
program is designed such that States determine how Hg allowances are to
be allocated across units.  A State that wishes to mitigate the impact
of the rule on small entities might choose to allocate Hg allowances in
a manner that is favorable to small entities.  Finally, the use of
cap-and-trade in general will limit impacts on small entities relative
to a less flexible command-and-control program.

The final rule would impose requirements on a new source, even if
owned/operated by a small entity.  The final rule does not contain any
provisions reserved exclusively for the benefit of small entities,
including new sources that could be owned/operated by small entities. 
However, the final rule does contain several provisions that reduce the
impact on all regulated entities, which include small entities (e.g.,
allowing any source to use the sorbent trap option, compliance
flexibility for low emitters, relaxed missing data procedures, revision
of Hg-diluent monitoring system requirements).

(d)  Collection Schedule.

Information contained in the one-time only reports will be entered into
the National Compliance Data System operated and maintained by EPA(s
Office of Enforcement and Compliance Assurance.  Data obtained during
periodic visits by Agency personnel from records maintained by the
respondents will be tabulated and published for internal EPA use in
enforcement and compliance programs.  A schedule for collection of
information and publication of data is not applicable because reports
are triggered by actions of the respondents.

6.  Estimating the Burden and Cost of the Collection

(a)  Estimating Respondent Burden.

The annual burden estimates for the additional recordkeeping and
reporting requirements in the final rules are shown in Exhibit 3. 
These numbers were derived from estimates based on EPA(s experience with
the cap-and-trade program for electric utilities under the Title IV Acid
Rain program, implementation of existing NSPS, and similar
compliance-related information collection activities.

(b)  Estimating Respondent Costs.

The information collection activities for the final rule are presented
in Exhibit 3.

(i)  Estimating Labor Costs.  Labor rates and associated costs are
based on Bureau of Labor Statistics (BLS) data. Technical, management,
and clerical average hourly total compensation rates for electric
utility industry workers were selected using labor category mean hourly
wages listed in the November 2003 National Industry-Specific
Occupational Employment and Wage Estimates for North American Industry
Classification System(NAICS) industry category 221000 - Utilities
(available at <http://www.bls.gov/oes/current/naics3_221000.htm>) and
adjusted to 2004 costs using the change in the BLS Employment Cost Index
for the private industry sector from the years 2003 to 2004 (3.8
percent).  The labor rates used for the burden estimates are $48.95/hour
for managerial (2003 mean for management occupations category of
$47.15/hr times 1.038), $33.17/hour for technical (2003 mean for
architecture and engineering occupations category of $31.95/hr times
1.038), and $18.96/hour for clerical (2003 mean for office and
administrative support occupations category of $18.26/hr times 1.038). 
An overhead rate of 110 percent was used to account for overhead costs. 
The fully burden rates used to represent respondent labor costs are: 
clerical at $39.82, technical at $69.66, and management at $102.80. 

(ii)  Estimating Capital and Operations and Maintenance (O&M) Costs. 
Estimation of the capital and operations and maintenance (O&M) costs are
largely based on information collected by the EPA(s Clean Air Markets
Division, specifically the technical report, (Cost Analysis of Mercury
Monitoring Techniques(; a second cost analysis performed by MACTEC Inc.;
and additional information obtained by the Agency in the development of
the rule.

Based on available cost information, the EPA estimates that the costs
for Hg emissions testing required for an LME coal-fired Utility Unit
will average about $5,500 per test.  An additional $1,500 in annual
costs are estimated for technical calculations, labor and other
associated expenses.  An LME unit with annual Hg emissions less than 9
lb/yr are required under the rule to perform annual emission testing. 
The LME units with annual Hg emissions greater than 9 lb/yr but less
than 29 lb/yr are required under the rule to perform semiannual emission
testing. 

For Hg CEMS, there are two major cost components to be considered,
capital costs and operational costs.  Based on a survey of 11
manufacturers, it is estimated that an average capital cost of a Hg CEM
is $60,000.  In addition, each source needs to purchase a HOVOCAL or
MERcal unit to generate ionic mercury, which is necessary for CEMS
calibration.  The approximate cost of either instrument is $10,000. 
Based on these costs, the capital cost of a complete Hg CEMS is
estimated to be about $70,000.  The operational costs can also be broken
into two components, i.e., routine maintenance and operation, and
quality assurance/control procedures.  These costs are estimated at
$87,000 per year and are the same basic cost estimates as were used in
the initial ICR.

The Hg sorbent trap method system used for semi-continuous monitoring of
Hg emissions includes a carbon trap with a three-section cartridge:  a
primary capture cartridge, backup for breakthough, and a portion for
spiking for QA/QC.  Two carbon traps would be run in parallel for
one-week runs.  The cost for a trap system is estimated be $8,500. 
Capital cost including the installation of the complete system is
estimated to be about $20,000.  The annual operational costs to use this
monitoring method include routine operational costs, laboratory costs to
analyze Hg in capture cartridges, and costs to perform QA/QC procedures.
 The total for these operational costs is estimated to about $113,000
per year.

(iii)  Capital/Startup vs. O&M Costs.  The estimate of capital/startup
costs versus O&M costs for implementing the Hg monitoring required by
the rule is shown in the following table.  The basis for the nationwide
numbers of coal-fired Utility Units shown in the table using a given Hg
emissions monitoring method is presented in section 6(c) of this
supporting statement.

Capital/Startup vs. O&M Costs

Mercury (Hg)

Emissions

Monitoring

Method	Nationwide

Number of Units

Using 

Method	Per Unit Costs	Nationwide Costs



Capital/

Startup

Cost	Annual

O&M

Cost	Capital

Costs

($1000)	Annual

O&M Costs

($1000)



LME Annual

HG Emission

Testing	

228	

0	

$7,000	

$0	

$1,596



LME Semiannual

HG Emission

Testing	

207	

0	

$12,500	

$0	

$2,588



Hg CEMS	

347	

$70,000	

$87,000	

$24,290	

$30,189



Hg Sorbent Trap	

343	

$20,000	

$113,000	

$6,860	

$38,759

Total	1,125	---	---	$31,150	$73,132



(iv)  Annualizing Capital Costs.  The estimate of capital/startup costs
versus O&M costs for implementing the Hg monitoring required by the rule
is shown in the following table.  Annualized costs are calculated
assuming a 7 percent interest rate and a 3-year depreciation period.

Annualized Costs

Mercury (Hg)

Emissions

Monitoring

Method	Nationwide

Number of Units

Using

Method	Nationwide Annualized Costs



Annualized

Capital

Cost

($1000)	Annual

O&M

Costs

($1000)	Total

Annualized

Cost

($1000)

LME Annual

Hg emissions testing	228	0	$1,596	$1,596

LME Semiannual

Hg emissions testing	207	0	$2,588	$2,588

Hg CEMS	347	$9,256	$30,189	$39,445

Hg Sorbent Trap	343	$2,614	$38,759	$41,373

Total	1,125	$11,870	$73,132	$85,002



(c)  Estimating Agency Burden and Cost.

Because the information collection requirements were developed as an
incidental part of standards development, no costs can be attributed to
the development of the information collection requirements.  Because
reporting and recordkeeping requirements on the part of the respondents
are required under the applicable rule provisions in 40 CFR parts 60 and
75, no operational costs will be incurred by the Federal Government. 
Publication and distribution of the information are part of the
Compliance Data System, with the result that no Federal costs can be
directly attributed to the ICR.  Examination of records to be maintained
by the respondents will occur incidentally as part of the periodic
inspection of sources that is part of the EPA(s overall compliance and
enforcement program, and, therefore, is not attributable to the ICR.

Costs that the Federal government will incur associated with the final
rule are user costs associated the one-time review and approval of the
plans submitted by States and Tribal governments participating in the Hg
cap-and-trade program and with the analysis of the additional Hg
emissions information included in the notifications and reports that
coal-fired Utility Unit owners and operators are already required to
submit under 40 CFR parts 60 and 75.  The Agency tasks that will be
performed include processing, reviewing, and evaluating Hg emissions
data in the reports submitted by owners and operators, and conducting
appropriate audit activities to verify the information provided. 
Exhibit 4 presents an estimate of the Agency burden and costs associated
with emissions reporting.

The Agency labor rates used for estimating the Agency costs are from the
Office of Personnel Management (OPM) 2004 General Schedule which
excludes locality rates of pay.  These rates were obtained from Salary
Table 2004-GS available on the OPM website
(http://http://www.opm.gov/oca/04tables/html/gs.asp).  The government
employee labor rates are $14.34/hour for clerical (GS-7, Step 1), $30.24
for technical (GS-13, Step 1), and $42.04/hr for management (GS-15, Step
1).  An overhead rate of 60 percent was used to account for overhead
costs.  The fully burdened rates used to represent respondent labor
costs are:  clerical at $22.94, technical at $48.38, and management at
$67.26. 

(d)  Estimating the Respondent Universe and Total Burden and Costs.

To estimate the number of respondents, the EPA used data available from
the 1999 Mercury Information Collection Request (ICR).  This ICR
provided mercury emission information on a total of 1,120 existing
Utility Units.  For the purpose of the nationwide burden estimates, each
coal-fired Utility Unit is counted as an industry respondent.  In
actuality, at many power plant sites, there are multiple coal-fired
Utility Units subject to the final rule.  In these cases, some rule
reporting and recordkeeping related activities can be performed by the
facility owner or operator on a plant-wide basis (e.g., planning
activities, developing record system, and training facility personnel)
instead of on a per coal-fired Utility Unit basis as is assumed for the
burden estimates.  Therefore, we believe that our burden estimates are
conservative.

In addition, the EPA estimates that five new coal-fired steam generating
units will be built during the next 5 years and subject to the NSPS
emission limits.

The EPA estimates, based on the ICR data, the nationwide distribution of
coal-fired Utility Units subject to the final rule as follows:

Nationwide Respondent Distribution By

Coal-fired Utility Unit Category

Coal-fired Utility Unit Category	

Nationwide

Number of Units



Existing coal-fired Utility Units with Hg emissions levels < 9 lb/yr	

228*



Existing coal-fired Utility Units with Hg emissions levels >9 and < 29
lb/y	

207*



Existing coal-fired Utility Units with 

Hg emissions levels > 29 lb/yr	

685



New coal-fired Utility Units constructed after January 31, 2004	

5



Total	

1,125

 * Designated LME units under the rule requirements.

For the purpose of estimating burden, it is assumed that all of the
respondents will install and begin operation of monitoring systems in
the first year following promulgation of the final rule.  For those
existing units required to conduct continuous Hg emissions monitoring,
it is assumed that 50 percent will use Hg CEMS and 50 percent will use
Hg sorbent traps.

(e)  Bottom Line Burden Hours and Cost Tables.

(i)  Respondent tally.  The bottom line respondent burden hours and
costs for the first 3 years following promulgation are presented in
Exhibits 3a, 3b, and 3c.  The bottom line respondent burden hours and
labor costs are calculated by adding person-hours per year down each
column in the tables for technical, managerial, and clerical staff, and
by adding down the cost column.

Respondent Bottom Line Burden Hours and Labor Costs

Year	Total Annual Burden Hours	Total Annual Labor Costs

1st year	902,238 hours	$61,805,909

2nd year	615,370 hours	$42,154,650

3rd year	615,370 hours	$42,154,650

Average	710,993 hours	$48,705,070

The annualized cost of capital for Hg monitoring devices is $11,865,949
averaged over the first three years of this ICR. Annualized costs are
calculated assuming a 7 percent interest rate and a 3-year depreciation
period.  Operation and maintenance costs (excluding any labor hours
given in the labor burden estimate) are estimated at $73,131,500 per
year.  The total cost including the average cost of labor over the
3-year period, capital, operation and maintenance, is $121,836,570 per
year.	(ii)  The Agency tally.  The bottom line Agency burden hours and
costs for the first 3 years following promulgation are presented in
Exhibit 4.  The bottom line Agency burden hours and costs are calculated
by adding person-hours per year down each column for technical,
managerial, and clerical staff, and by adding down the cost column.  In
this case, total cost is the sum of this total salary cost and total
travel expenses for government personnel to observe compliance tests at
a selected number of coal-fired Utility Units each year.

Agency Bottom Line Burden Hours and Labor Costs

Year	Total Annual Burden Hours	Total Annual Labor Costs

1st year	47,877 hours	$2,249,860

2nd year	33,249 hours	$1,562,451

3rd year	33,249 hours	$1,562,451

Average	38,125 hours	$1,791,587

The total annual hours over the 3-year period are 38,125.  The total
annual cost over the 3-year period is $1,791,587.

(iii)  Variations in the annual bottom line.  This section does not
apply since no significant variation is anticipated.

(f)  Reasons for Change in Burden.

In the proposed rule, EPA proposed two primary alternative regulatory
options.  One of those regulatory options involved the proposed issuance
of national emission standards for hazardous air pollutants (NESHAP)
under CAA section 112, and the other involved the issuance of standards
of performance under CAA section 111.  Under either regulatory option,
however, the same universe of coal-fired Utility Units would be affected
because both options govern new and existing coal-fired units.  In
addition, under both the CAA section 112 and CAA section 111 regulatory
options, we required similar monitoring (i.e., both regulatory options
required the use of either CEMS or sorbent trap monitoring), reporting,
and recordkeeping requirements, and we solicited comment on those
proposed requirements.

The burden estimates in the initial ICR prepared for the proposed rule
were based on the proposed CAA section 112 regulatory option, which
again covered the same universe of coal-fired Utility Units as the CAA
section 111 regulatory approach and the same general monitoring,
reporting, and recordkeeping requirements.  The initial version of the
ICR also included burden estimates for oil-fired Utility Units because
both the CAA section 112 regulatory option and the CAA section 111
option proposed requiring reductions of nickel from oil-fired units.  We
did not receive any comments from the public or OMB concerning the
burden estimates provided in the initial version of the ICR.

Based on a thorough review of the comments received in response to the
proposal, EPA finalized the CAA section 111 regulatory approach.  The
final CAA section 111 rule sets standards of performance for Hg emitted
from new and existing coal-fired Utility Units and requires certain
monitoring, reporting, and recordkeeping as described generally in this
document and more fully in the preamble to the final rule.  In addition,
the final rule only covers coal-fired Utility Units, not oil-fired
units.  We made this change in the final rule in response to comments
received concerning nickel emissions from oil-fired Utility Units.

We also received several comments in response to the proposed rule
concerning the proposed monitoring and associated requirements for
coal-fired Utility Units.  We made certain changes in the final rule in
light of those comments.  The changes made address commenters( concerns
regarding, for example, allowing any source to use the sorbent trap
option, providing increased compliance flexibility for low emitters;
modifying the procedures for missing data; and revising the Hg-diluent
monitoring system requirements.  As noted below, however, not all
changes made as a result of the public comments received resulted in a
decreased burden estimate.

In addition to modifying the burden estimates in response to the
changes made to the monitoring requirements in the final rule, we made
certain other adjustments to our burden estimates.  Those adjustments
resulted in a burden estimate for the final rule that is higher than the
burden estimate in support of the proposed rule.  The reasons for the
difference in the burden estimates are as follows:

1.  The burden estimate at proposal failed to account for new units,
even though we proposed CAA section 112(d) emission standards for such
units.  This omission was an inadvertent error.  As noted above, we
estimate that five new coal-fired steam generating units will be built
during the next 5 years.

2.  For the burden estimate at proposal, a (respondent( was defined to
be an individual power plant (461 coal-fired plants).  For the final
rule burden estimate, a (respondent( was defined to be an individual
coal-fired Utility Unit (1,125 units).  Overall, the assumption used for
the final rule is more conservative than at proposal because many power
plants have multiple affected coal-fired Utility Units, and, therefore,
the burden activities can be performed on a plant-wide basis instead of
on a per-unit basis as is assumed for the burden calculations (i.e., the
burden associated with reading instructions, training personnel, and
like activities is being shared by the units and, thus, is somewhat
lower that if attributed to each unit).  Thus, although we changed the
definition of the term (respondent,( the initial version of the ICR and
this revision both address the same general universe of coal-fired
Utility Units.  In addition, we believe that a Utility Unit-based burden
calculation better reflects the monitoring requirements for LME units.

3.  For the final burden estimate, it was assumed than all States and
affected Tribal governments would participate in the cap-and-trade
program and that all existing coal-fired Utility Units would implement
the required Hg monitoring during the first year following promulgation.
 For the burden estimate for the proposed rule, it was assumed that Hg
monitoring would be phased in over the 3-year compliance period allowed
for NESHAP rules (i.e., one-third of the power plants installing CEMS
during the first year, another one-third installing CEMS during the
second year, and the final one-third installing CEMS during the third
year).  Assuming compliance in the first year, therefore, resulted in
increased burden estimates.

4.  Allowing use of the sorbent trap method allocates more cost to the
source but provides greater flexibility in monitoring options, which is
what many commenters wanted.  In the burden estimates for the final
rule, it was assumed that 50 percent of affected Utility Units would
choose to use the sorbent trap method.

(g)  Burden Statement

The average annual respondent burden during the first 3-year period
following rule promulgation is estimated at 632 hours per respondent. 
This is based on an estimated total 710,993 hours per year (as averaged
over the rule first 3-year period following promulgation) for a
projected 1,125 respondents.

Burden means the total time, effort, or financial resources expended by
persons to generate, maintain, retain, or disclose or provide
information to or for a Federal agency.  This includes the time needed
to review instructions; develop, acquire, install, and utilize
technology and systems for the purposes of collecting, validating, and
verifying information, processing and maintaining information, and
disclosing and providing information; adjust the existing ways to comply
with any previously applicable instructions and requirements; train
personnel to be able to respond to a collection of information; search
data sources; complete and review the collection of information; and
transmit or otherwise disclose the information.  An agency may not
conduct or sponsor, and a person is not required to respond to, a
collection of information unless it displays a currently valid OMB
control number.  The OMB control numbers for EPA(s regulations are
listed in 40 CFR Part 9 and 48 CFR Chapter 15.

Exhibit 1.

SOURCE DATA AND INFORMATION REQUIREMENTS UNDER

40 CFR PART 60 SUBPART HHHH EMISSION GUIDELINES AND COMPLIANCE TIMES FOR
COAL-FIRED ELECTRIC STEAM GENERATING UNITS

REQUIREMENT	

REGULATION CITATION	

RECORD

RETENTION



Reports	





Notifications	

(75.61	

5 years



Certification applications	

(75.63	

5 years



Quarterly reports	

(75.64	

5 years



QA/QC plan	

Part 75

Appendix B

Section 1	

5 years



Recordkeeping	





General recordkeeping requirements	

(75.57	

5 years



Recordkeeping for special

situations	

(75.58	

5 years



Quality assurance recordkeeping	

(75.59	

5 years



QA/QC recordkeeping	

Part 75

Appendix B

Section 1	

5 years

Exhibit 2.

SOURCE DATA AND INFORMATION REQUIREMENTS UNDER

40 CFR PART 60 SUBPART Da NEW SOURCE PERFORMANCE STANDARDS FOR

 COAL-FIRED ELECTRIC UTILITY STEAM GENERATING UNITS

REQUIREMENT	

REGULATION

CITATION	

RECORD

RETENTION



Reports	

	





Initial notifications as applicable to facility(i.e., date of
construction or reconstruction, dates of anticipated and actual startup,
modifications to existing facility)	

(60.7(a)(1)-(4)	

5 years



Notification of performance tests	

(60.8(d)	

5 years



Notification of CEM performance evaluation	

(60.7(a)(5)	

5 years



Semi-annual compliance report	

(60.51a(i)	

5 years



Recordkeeping	

	





Records of notifications and reports, performance tests, performance
evaluations, monitoring data, performance evaluation test plan	

(60.52a	

5 years



Startup, shutdowns, and malfunctions	

(60.7(b)	

5 years



Records required to demonstrate continuous compliance with emission
limits	

(60.52a	

 

 

 

 

 



 

 

 

 

 

 

  Cost Analysis of Mercury Monitoring Techniques.  Draft report prepared
by Arcadis for Dr. Ruben Deza, U.S. Environmental Protection Agency,
Washington, DC., November 3, 2003.

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