### 4694 Federal Register / Vol. 69, No. 20 / Friday, January 30, 2004 / Proposed Rules

process type in this rule (bituminous coal, subbituminous coal, lignite coal, coal refuse, and IGCC).

The EPA’ s review of the available emission data shows that Hg emissions
from new coal-fired units can be reduced to the following:

Bituminous units: 0.61 lb/TBtu heat input;
Subbituminous units: 2.0 lb/TBtu heat input; Lignite units: 6.3 lb/TBtu heat input;
Waste coal units: 0.11 lb/TBtu heat input;

IGCC units: 2.0 lb/TBtu heat input.

Mercury emissions from new oil- and gas-fired units are not covered by the proposed rule.

Subpart Da Ni emission standards. In selecting a regulatory approach for formulating emission standards to limit
Ni emissions from new oil-fired steam generating units, the performance on Ni of the PM control technologies
discussed above were considered. The technical basis (i.e., BDT) selected for establishing Ni emission limits for new
sources is the use of ESP units or oils
low in Ni content.

The EPA’ s review of the available
emission data shows that Ni emissions
from new oil-fired units can be reduced to 84 lb/TBtu heat input.

5. What Are the Subpart Da Hg and Ni
Emission Standards?

Based on available performance dataanalyses from the 1999 ICR for coalfired Utility Units, the Administrator has concluded that the application of fabric filters or ESP units along with wet or dry FGD is considered to be the most effective Hg control technology for units firing subbituminous, lignite, or waste coals; and that the application of fabric filters or ESP units, wet or dry FGD systems, and SCR is considered to be the most effective Hg control technology for units firing bituminous coals. For IGCC units (regardless of coal rank fired), the Administrator has concluded
that use of a carbon bed is considered to be the most effective Hg control technology. These controls represent the best system of emissions reductions (taking into consideration the cost of achieving such emissions reductions, any non-air quality health and environmental impact, and energy requirements).

Based on available performance data and cost analyses, the Administrator has concluded that the application of ESP units or oils containing a low Ni content
is considered to be the most effective Ni control technology for oil-fired units. These controls represent the best system of emissions reductions (taking into consideration the cost of achieving such emissions reductions, any non-air quality health and environmental impact, and energy requirements).

6. How Did EPA Select the Format for the Proposed Standards?

Based on the analyses and discussion presented earlier, EPA has selected an output-based format for the proposed
new-source rule. The Administrator is proposing today Hg emission limits for new coal-fired Utility Units as follows:

Bituminous units: 0.0060 GWh gross;
Subbituminous units: 0.020 lb/GWh

gross; Lignite units: 0.062 lb/GWh gross;
Waste coal units: 0.0011 lb/GWh gross;

IGCC units: 0.020 lb/GWh gross.

Based on the available performance data, cost analysis, and the above calculation, the Administrator is proposing today Ni emission limits for new oil-fired Utility Units as follows: 0.0008 lb/MWh gross.

7. How Did EPA Determine Testing and Monitoring Requirements for the Proposed Standards?

The CAA requires EPA to develop regulations that ensure initial and continuous compliance. Testing and monitoring requirements allow EPA to
determine whether an affected source is operating in compliance with an applicable emission limitation/standard.
This section discusses how EPA selected the proposed testing and monitoring requirements used to determine compliance with the Hg and Ni emission limits that are specified in the proposed rule.

Mercury testing and monitoring requirements. The proposed rule wouldestablish Hg emission limits for coalfired units. The format selected for these Hg emission limits is a 12-month rolling average Hg emission level expressed in units of lb/TBtu or lb/MWh. Therefore, appropriate testing or monitoring requirements for determining the amount of Hg emitted from an affected unit throughout the compliance averaging period must be included in
the rule.

The most direct means of demonstrating compliance with an emission limit is by the use of a CEMS that measures the pollutant of concern. The EPA considers other testing or monitoring options when acceptable
CEMS are not available for the intended application or when the impacts of including such CEMS requirements in the proposed rule are considered by EPA to be unreasonable. In determining whether to require the use of other testing or monitoring options in lieu of CEMS, it is often necessary for EPA to balance more reasonable costs against the quality or accuracy of the actual
emissions data collected.

There are several approaches to Hg monitoring that EPA has identified for possible use in this rule to determine compliance with the proposed Hg emission limits. One option is to use a
CEMS that combines both automated sampling and analytical functions in a single system to provide continuous, real-time Hg emission data. Mercury CEMS are currently available from several manufacturers. These Hg CEMS are similar to most other types of
instruments used for continuous monitoring of pollutants from combustion processes, in that the combustion gas sample is first extracted
from the stack and then transferred to an analyzer for analysis. In general, the Hg
CEMS now available can be distinguished by the Hg measurement detection principle used ( e.g., atomic adsorption, atomic fluorescence, x-ray fluorescence). Capital costs for a Hg CEMS are currently estimated to range from approximately $95,000 to $135,000, depending on the
manufacturer and model selected. The annual costs to operate and maintain a Hg CEMS are estimated to range from $45,000 to $65,000, again depending on
the manufacturer and model selected.

A second option is to use a long-term sampling method that collects a cumulative Hg sample by continuously passing a low-flow sample stream of the combustion process flue gas through a Hg trapping medium ( e.g., an activated carbon tube). This sampling tube is then periodically removed ( e.g., after a day or up to 1 month) and replaced with a tube filled with fresh trapping medium. The removed sampling tube is then sent to a laboratory where the trapping medium is analyzed for its Hg content. This method, like using a Hg CEMS, is capable of providing data on the Hg emissions from a combustion process on a continuous basis, but unlike a Hg CEMS, the data are not reported on a real-time basis. Using the long-term sampling method, the Hg collected in the sampling tube is integrated over a much longer sampling period (i.e., 1 to 7 days for the AC tube versus less than 15 minutes for the CEMS). The capital cost for a gas metering system and Hg trapping medium is estimated to be approximately $18,000. The annual costs for periodic sampling tube replacement and for the laboratory Hg analysis range from approximately $65,000 to $125,000 depending upon quality assurance and quality control (QA/QC) requirements and frequency of sample tube replacement.