Standards of Performance for Fossil-Fuel-Fired Steam Generators for Which Construction Is Commenced After August 17, 1971; Standards of Performance for Electric Utility Steam Generating Units for Which Construction Is Commenced After September 18, 1978; Standards of Performance for Industrial-Commercial-Institutional Steam Generating Units; and Standards of Performance for Small Industrial-Commercial-Institutional Steam Generating Units; Reconsideration and Amendments

Federal RegisterFeb 9, 2007

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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 60

[EPA-HQ-OAR-2005-0031; FRL-8275-9]

RIN 2060-AN97

Standards of Performance for Fossil-Fuel-Fired Steam Generators for Which Construction Is Commenced After August 17, 1971; Standards of Performance for Electric Utility Steam Generating Units for Which Construction Is Commenced After September 18, 1978; Standards of Performance for Industrial-Commercial-Institutional Steam Generating Units; and Standards of Performance for Small Industrial-Commercial-Institutional Steam Generating Units; Reconsideration and Amendments

AGENCY:

Environmental Protection Agency (EPA).

ACTION:

Proposed rule.

SUMMARY:

EPA is proposing to amend the new source performance standards (NSPS) for electric utility steam generating units and industrial-commercial-institutional steam generating units. On February 27, 2006, EPA promulgated amendments to the NSPS for steam generating units. EPA is proposing to amend specific provisions in the NSPS for steam generating units to resolve issues and questions raised by petitioners for reconsideration of the promulgated amendments, and to correct technical and editorial errors that have been identified since promulgation. In addition, the proposed rule would update the grammatical style of the four NSPS steam generating unit subparts to be consistent across all of the subparts.

DATES:

Comments

. Comments must be received on or before March 12, 2007, unless a public hearing is requested by February 20, 2007. If a timely hearing request is submitted, the public hearing will be held on February 26, 2007 and we must receive written comments on or before March 26, 2007.

ADDRESSES:

Comments

. Submit your comments, identified by Docket ID No. EPA-HQ-OAR-2005-0031, by one of the following methods:

•

http://www.regulations.gov

. Follow the on-line instructions for submitting comments.

•

E-mail: a-and-r-docket@epa.gov

•

By Facsimile:

(202) 566-1741.

•

Mail:

Air and Radiation Docket, U.S. EPA, Mail Code 6102T, 1200 Pennsylvania Ave., NW., Washington, DC 20460. Please include a total of two copies. EPA requests a separate copy also be sent to the contact person identified below (see

FOR FURTHER INFORMATION CONTACT

•

Hand Delivery:

EPA Docket Center, Docket ID Number EPA-HQ-OAR-2005-0031, EPA West Building, 1301 Constitution Ave., NW., Room 3334, Washington, DC, 20004. Such deliveries are accepted only during the Docket's normal hours of operation, and special arrangements should be made for deliveries of boxed information.

Instructions:

Direct your comments to Docket ID No. EPA-HQ-OAR-2005-0031. EPA's policy is that all comments received will be included in the public docket without change and may be made available online at

http://www.regulations.gov

, including any personal information provided, unless the comment includes information claimed to be Confidential Business Information (CBI) or other information whose disclosure is restricted by statute. Do not submit information that you consider to be CBI or otherwise protected through regulations.gov or e-mail. The

www.regulations.gov

Web site is an “anonymous access” systems, which means EPA will not know your identity or contact information unless you provide it in the body of your comment. If you send an e-mail comment directly to EPA without going through

www.regulations.gov

, your e-mail address will be automatically captured and included as part of the comment that is placed in the public docket and made available on the Internet. If you submit an electronic comment, EPA recommends that you include your name and other contact information in the body of your comment and with any disk or CD-ROM you submit. If EPA cannot read your comment due to technical difficulties and cannot contact you for clarification, EPA may not be able to consider your comment. Electronic files should avoid the use of special characters, any form of encryption, and be free of any defects or viruses. For additional information about EPA's public docket visit the EPA Docket Center homepage at

http://www.epa.gov/epahome/dockets.htm

Docket:

All documents in the docket are listed in the

www.regulations.gov

index. Although listed in the index, some information is not publicly available, e.g., CBI or other information whose disclosure is restricted by statute. Certain other material, such as copyrighted material, will be publicly available only in hard copy. Publicly available docket materials are available either electronically in

http://www.regulations.gov

or in hard copy at the Air and Radiation Docket EPA/DC, EPA West, Room 3334, 1301 Constitution Ave., NW., Washington, DC. The Public Reading Room is open from 8:30 a.m. to 4:30 p.m., Monday through Friday, excluding legal holidays. The telephone number for the Public Reading Room is (202) 566-1744, and the telephone number for the Air and Radiation Docket is (202) 566-1742.

FOR FURTHER INFORMATION CONTACT:

Mr. Christian Fellner, Energy Strategies Group, Sector Policies and Programs Division (D243-01), U.S. EPA, Research Triangle Park, NC 27711, telephone number (919) 541-4003, facsimile number (919) 541-5450, electronic mail (e-mail) address:

fellner.christian@epa.gov

SUPPLEMENTARY INFORMATION:

Entities Table

. Entities potentially affected by this proposed action include, but are not limited to, the following:

Category

NAICS code

Examples of potentially regulated entities

Industry

221112

Fossil fuel-fired electric utility steam generating units.

Federal Government

22112

Fossil fuel-fired electric utility steam generating units owned by the Federal Government.

State/local/tribal government

22112

Fossil fuel-fired electric utility steam generating units owned by municipalities.

921150

Fossil fuel-fired electric utility steam generating units located in Indian Country.

Any industrial, commercial, or institutional facility using a steam generating unit as defined in 60.40b or 60.40c

211

Extractors of crude petroleum and natural gas.

321

Manufacturers of lumber and wood products.

322

Pulp and paper mills.

325

Chemical manufacturers.

324

Petroleum refiners and manufacturers of coal products.

316, 326, 339

Manufacturers of rubber and miscellaneous plastic products.

331

Steel works, blast furnaces.

332

Electroplating, plating, polishing, anodizing, and coloring.

336

Manufacturers of motor vehicle parts and accessories.

221

Electric, gas, and sanitary services.

622

Health services.

611

Educational Services.

North American Industry Classification System (NAICS) code.

This table is not intended to be exhaustive, but rather provides a guide for readers regarding entities likely to be regulated by the proposed rule. To determine whether your facility is regulated by the proposed rule, you should examine the applicability criteria in § 60.40a, § 60.40b, or § 60.40c of 40 CFR part 60. If you have any questions regarding the applicability of the proposed rule to a particular entity, contact the person listed in the preceding

FOR FURTHER INFORMATION CONTACT

section.

World Wide Web (WWW)

. Following the Administrator's signature, a copy of the proposed amendments will be posted on the Technology Transfer Network's (TTN) policy and guidance page for newly proposed or promulgated rules at

http://www.epa.gov/ttn/oarpg

. The TTN provides information and technology exchange in various areas of air pollution control.

Public Hearing

. If a public hearing is requested, it will be held at 10 a.m. at the EPA Facility Complex in Research Triangle Park, North Carolina or at an alternate site nearby. Contact Mr. Christian Fellner at 919-541-4003 to request a hearing, to request to speak at a public hearing, to determine if a hearing will be held, or to determine the hearing location.

Outline

. The information presented in this preamble is organized as follows:

I. Background

II. Proposed Amendments

A. Proposed Substantive Amendments to Subpart D

B. Proposed Substantive Amendments to Subpart Da

C. Proposed Substantive Amendments to Subpart Db

D. Proposed Substantive Amendments to Subpart Dc

III. Statutory and Executive Order Reviews

A. Executive Order 12866: Regulatory Planning and Review

B. Paper Reduction Act

C. Regulatory Flexibility Act

D. Unfunded Mandates Reform Act

E. Executive Order 13132: Federalism

F. Executive Order 13175: Consultation and Coordination With Indian Tribal Governments

G. Executive Order 13045: Protection of Children From Environmental Health and Safety Risks

H. Executive Order 13211: Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use

I. National Technology Transfer Advancement Act

Background

EPA promulgated amendments to the new source performance standards for steam generating units on February 27, 2006 (71 FR 9866). The amendments added new emissions limits and compliance requirements applicable to units constructed, modified, or reconstructed after February 28, 2005, for electric utility steam generating units in 40 CFR part 60, subpart Da; industrial-commercial-institutional steam generating units in 40 CFR part 60, subpart Db; and small industrial-commercial-institutional steam generating units in 40 CFR part 60, subpart Dc. In addition, an alternative sulfur dioxide (SO

) emissions limit was added to subparts Db and Dc for steam generating units for which construction, modification, or reconstruction was commenced prior to February 28, 2005.

Petitions for reconsideration of the amendments were filed by the Utility Air Regulatory Group and the Council of Industrial Boiler Owners. The EPA has decided to grant reconsideration to the amendments to the extent specified in the proposed rule. The amendments proposed by this action address issues for which the petitioners requested reconsideration

(see docket entries EPA-HQ-OAR-2005-0031-0224 and EPA-HQ-OAR-2005-0031-0225).

An issue EPA is not granting reconsideration on is UARG's request “EPA should also clarify that PM CEMS data would not be ‘credible evidence’ of a violation of the applicable PM standard for a source during a period for which the source has not otped to use PM CEMS to determine compliance.”

As part of this action, EPA is also proposing to amend other rule language to correct technical omissions, typographical errors, cross-reference errors, grammatical errors, and various other issues that have been identified since promulgation. The proposed amendments would not significantly change EPA's original projections for the rule's compliance costs, environmental benefits, burden on industry, or the number of affected facilities.

Finally, as part of the February 28, 2005, proposal to the steam generating unit NSPS, EPA proposed several amendments designed to minimize the continuous emission monitoring systems (CEMS) burden for sources subject to both the NSPS under 40 CFR part 60 and the acid rain regulations under 40 CFR part 75 (70 FR 9720). The intent of these proposed amendments is to address the inconsistent and duplicative CEM requirements in the two rules while still maintaining the integrity of the separate NSPS and acid rain programs. EPA received five comment letters on these proposed amendments. The comments were generally supportive of the amendments, but due to the need for additional internal EPA review, EPA did not include the CEM protocol amendments with the other steam generating unit NSPS amendments that were promulgated on February 27, 2006. EPA intends to include the final CEM requirement amendments with the final action of this reconsideration. A detailed description of the proposed amendments to the CEM requirements is available in the docket.

II. Proposed Amendments

EPA is proposing to amend 40 CFR part 60, subparts D, Da, Db, and Dc to clarify the intent for applying and implementing specific rule requirements and to correct unintentional technical omissions and editorial errors. A summary of the proposed substantive amendments to the NSPS for steam generating units and the rationale for these amendments are presented below.

In addition, EPA is proposing to republish 40 CFR 60.17 (Incorporations by reference) and subparts D, Da, Db, and Dc in their entirety. The proposed amendments include updating 40 CFR 60.17 to be consistent with the recent formatting style used in subpart KKKK of 40 CFR part 60 and revising the wording and writing style to be more consistent across all the NSPS subparts applicable to steam generating units. EPA does not intend for these editorial revisions to substantively change any of

the technical or administrative requirements of the subparts and has concluded that these do not do so. The various subparts were promulgated at different times and, therefore, vary somewhat in style. EPA has concluded that it is appropriate at this time to reconcile these various styles in order to provide consistency across the subparts. To the extent that the editorial revisions do effect any unintended substantive changes, EPA will correct the problem in taking final action on the proposed rule. The docket for this rulemaking (Docket ID No. EPA-HQ-OAR-2005-0031) contains complete redline/strike-out versions of each subpart, which allows direct comparison of all of the proposed amended rule text with the existing rule text.

A. Proposed Substantive Amendments to Subpart D

1. Alternative Emissions Standards

Subpart D of 40 CFR part 60 establishes nitrogen oxides (NO

), SO

, and PM emission standards for steam generating units that began construction between August 17, 1971 and September 18, 1978. Continuous compliance with these emissions standards is determined by comparison of the applicable emissions limit to the actual NO

and SO

emissions measured by CEMS and averaged over three contiguous 1-hour periods.

When subpart D was originally developed, the NO

standards were achievable with the use of available combustion controls, and the SO

standards were achievable by burning low-sulfur fuels. EPA has concluded some of the electric utility steam generating units presently subject to subpart D will install additional post-combustion controls because they are subject to NO

and SO

emissions standards implemented by other air programs after subpart D was promulgated. In many cases, compliance with these other NO

and SO

standards is based on 30-day or longer rolling averages instead of the 3-hour averaging period used for the subpart D standards. For example, a coal-fired electric utility steam generating unit subject to both the subpart D NSPS and the Regional Haze Regulations must meet: (1) A 3-hour average SO

emission of 1.2 pounds per million Btu of heat input (lb/MMBtu) and (2) the Best Available Retrofit Technology (BART) presumptive 30-day rolling average SO

emissions limit of 0.15 lb/MMBtu or 95 percent reduction in potential emissions. This requires the owners and operators of the units subject to both subpart D and BART to collect and record data and perform compliance determinations for two different averaging periods.

EPA is proposing to allow owners and operators of steam generating units subject to subpart D to elect to comply with the NO

and SO

standards for modified units under subpart Da. These standards are based on 30-day rolling averages and would be an alternative to meeting the existing applicable 3-hour average NO

and SO

standards in subpart D. Adding these alternative 30-day average NO

and SO

standards to subpart D would simplify the compliance requirements and add fuel choice flexibility.

Since averaging time is an important consideration when selecting the numerical level for an emissions standard, the limits EPA is proposing as an alternative to the existing 3-hour average based standards are significantly lower and represent emissions levels achieved by electric utility steam generating units retrofitted with post-combustion controls. As an alternative to the existing 3-hour average subpart D SO

standard of 0.8 or 1.2 lb/MMBtu (depending on fuel type burned), EPA is proposing to allow a SO

fuel neutral emissions limit of 1.4 pounds per megawatts hour of output (lb/MWh), 0.15 lb/MMBtu, or 90 percent reduction of potential SO

emissions based on a 30-day rolling average. This emissions limit could be applied to any electric utility steam generating unit subject to subpart D regardless of the type of fuel burned. For the NO

emissions limit, EPA is proposing a fuel neutral 30-day rolling average emissions limit of 1.4 lb/MWh or 0.15 lb/MMBtu as an alternative to the existing subpart D 3-hour NO

emissions limits of 0.2 to 0.8 lb/MMBtu (depending on the type of fuel burned).

To use the alternative standards, an owner or operator would request permission from the EPA Administrator for the affected source to begin complying with the alternative 30-day average NO

and SO

standards. After demonstrating initial compliance with the 30-day average standards, the 30-day average standards would apply to the source for the remainder of the operating life of the unit. The decision to comply with the alternative 30-day average NO

and SO

emissions standards would be a one-time and irreversible decision, i.e., an owner or operator would not be allowed to switch between complying with the 3-hour average standards and the 30-day rolling average standards. For owners and operators who decide to continue to demonstrate compliance based on the 3-hour rolling average standards, demonstrating that a unit achieved the 30-day average standards does not remove the obligation to demonstrate continuous compliance with the 3-hour average based standards.

2. Alternative PM CEMS Monitoring

The amendments to subpart Da in 40 CFR part 60, promulgated on February 27, 2006, allow affected owners and operators of electric utility steam generating units subject to subpart Da to install and operate a CEMS that measures PM as an alternative to continuously monitoring opacity. EPA is proposing that the same alternative monitoring provisions be added to subpart D. EPA has concluded that since PM CEMS measure the pollutant of primary interest they provide adequate assurance of PM control device performance, and continuous opacity monitoring is an unnecessary burden to affected sources using PM CEMS.

3. Alternate Carbon Monoxide Monitoring for Oil-Fired Steam Generating Units

Under subpart D, all affected electric utility steam generating units (including those that only burn natural gas) are subject to PM and visible emissions limit standards. Steam generating units burning gaseous fuels do not require a continuous opacity monitoring system (COMS), but all other affected facilities burning liquid or solid fuels are required to continuously monitor opacity. Opacity readings from the COMS are not only used to determine compliance with the opacity standard, but also serve as a continuous indicator of PM emission levels. Elevated opacity levels are often indications of operating problems with the PM control device and/or poor combustion.

In general, the level of filterable PM emissions from oil-fired steam generating units is a function of the completeness of fuel combustion as well as the ash content in the oil. Distillate oil contains negligible ash content, so the filterable PM emissions from distillate oil-fired steam generating units are primarily comprised of carbon particles resulting from incomplete combustion of the oil. Residual oil contains larger amounts of ash (as much as 0.2 percent) and additional PM results from the formation of coke, black smoke (soot), and sulfates. Coke is comprised of larger particles and results from poor atomization of the fuel; soot results from incomplete fuel combustion. The larger coke particles comprise the majority of the mass of PM emissions, but are not highly visible. Smaller black smoke particles are comprised of fine particulate carbon and

have relatively little mass, but have maximum visibility (opacity) impacts. Therefore, opacity for oil-fired steam generating units is not always a reliable indicator of the total mass of PM emissions.

Carbon monoxide (CO) emissions from oil-fired steam generating units depend on the combustion efficiency of the fuel. The presence of CO in the exhaust gases from an oil-fired steam generating unit results principally from incomplete fuel combustion, and is an indicator of the levels of both PM and organic compound emissions, and that a unit is being operated improperly or not being well maintained. Furthermore, the PM emissions from oil-fired steam generating units are related to the sulfur content of the oil. Naturally low sulfur crude oil and desulfurized oils are higher quality fuels and exhibit lower viscosity and reduced asphaltene, ash, and sulfur content, which results in better atomization and improved overall combustion properties.

To provide additional flexibility and decrease the compliance burden on affected facilities, EPA is requesting comments on whether oil-fired steam generating units should be permitted to continuously monitoring CO as an alternative to continuously monitoring opacity. Many oil-fired steam generating units subject to subpart D are able to achieve the PM emissions limit without the use of post-combustion PM controls (

e.g.

, electrostatic precipitator (ESP) or fabric filter). For these units, opacity levels are primarily determined by the combustion efficiency of the steam generating units. Since CO emissions are also a direct function of the combustion efficiency, EPA has concluded that either opacity or CO emissions can be used as reliable indicators of PM emissions levels from oil-fired steam generating units not using PM or CO post-combustion controls. Additionally, in situations where an oil-fired steam generating unit is using a wet scrubber and opacity monitoring using COMS is not feasible due to the water vapor in the gas stream exiting the control device, continuous CO monitoring provides an alternative means for monitoring PM emissions. The alternative would not apply to oil-fired steam generating units using an ESP or fabric filter for PM control or a CO catalyst to reduce CO emissions. Opacity can be used by operators to identify problems with the PM control equipment, and post-combustion PM and CO controls alter the relationship between CO and PM emissions.

If this alternative is added to subpart D, owners and operators of affected oil-fired steam generating units without post-combustion technologies to reduce PM, SO

, or CO (except a wet scrubber) would be able to elect to install and operate a CO CEMS in place of a COMS. The owner or operator would be required to periodically review the CO emissions measurements from the CEMS. If the CO emissions level exceeds a specified threshold or action level, the owner or operator would need to initiate investigation of the relevant combustion controls or equipment upon first discovery of the elevated CO emissions incident and, if necessary, take corrective action to adjust or repair the combustion controls or equipment to return the steam generating unit operation to CO emissions levels below the action level.

To select a CO value for the action value, EPA reviewed CO emissions data and CO emissions limits established by State air permits and for existing oil-fired steam generating units. Based on this review, EPA concluded that daily average CO emissions levels below 0.15 lb/MMBtu are representative of the levels of CO emissions achievable by properly operated and maintained oil-fired steam generating units. Thus, for this alternative EPA proposes to use a daily average CO emissions level of 0.15 lb/MMBtu as the action level above which corrective action would be required. EPA is requesting comment on whether this is an appropriate level or whether a different level and/or averaging time should be used.

The fuel characteristics of distillate oil and low sulfur oils result in inherently lower PM emissions. EPA is proposing the CO monitoring alternative be restricted to only those steam generating units burning distillate oil and residual oil that contains no more than 0.30 percent sulfur. As another option, since distillate oil containing no more than 0.05 weight percent sulfur (500 parts per million (ppm) S) has relatively low emissions, should steam generating units burning 500 ppm S distillate oil exclusively or in combination with gaseous fuels be exempt from the COMS requirement, while all other oil-fired facilities would still be required to install COMS?

Finally, should the CO level of 0.15 lb/MMBtu be established as a CO emissions limit or as a deviation that triggers corrective action? If exceeding the CO level is a deviation requiring the owner or operator to take corrective action, what percent of the time should an affected source be allowed to exceed the CO action level before it is considered a potential violation? As an alternative, since monitoring CO provides equivalent or superior protection to the environment as monitoring opacity, would it be appropriate to exempt oil-fired steam generating units monitoring CO emissions from the opacity standard completely? If oil-fired steam generating units were exempt from the opacity standard, the CO level would be established as a CO emissions limit and any exceedance above the level during operation would be a potential violation. Draft language EPA is considering is available in the docket.

B. Proposed Substantive Amendments to Subpart Da

1. Applicability

EPA is proposing language to clarify the applicability of subpart Da to electric utility steam generating units to clearly state the intent of the amendments published on February 27, 2006. EPA is revising 40 CFR 60.40Da to clarify that integrated gasification combined cycle (IGCC) facilities are subject to subpart Da, and not the stationary combustion turbine NSPS, subpart KKKK, 40 CFR part 60.

2. Compliance Procedures

Compliance with the PM emissions limits in subpart Da is determined by conducting performance tests, unless the owner or operator elects to demonstrate compliance using PM CEMS. During the performance test, the owner or operator also establishes opacity and appropriate control device operating parameter limits based on the actual values measured during the test. Following the performance test, the owner or operator continuously monitors opacity and the selected operating parameters with respect to the established limits. An owner or operator of an affected steam generating unit using an ESP must monitor voltage and secondary current; while affected sources using a fabric filter must install and monitor bag leak detectors. If the threshold values are exceeded, the owner or operator is required to perform a new performance test to demonstrate that the affected source is still in compliance with the applicable emissions limit.

The PM not collected by an ESP and emitted in the ESP exhaust gas stream has a relatively constant size distribution, which does not change significantly as the ESP performance changes. Consequently, ESP opacity variations from the baseline established during the performance test reflect changes in PM mass emissions. For fabric filters, the opacity and PM relationship is not as constant. An increase in PM emissions from a fabric filter can occur from holes developing

in the bags. This results in a size distribution change of the particles being emitted in the fabric filter exhaust gas stream. Since the particles going through the holes are the same size distribution as the inlet particles (not just the fine diameter particles that escape capture and pass through the bag filter material) PM mass emissions from a fabric filter can increase substantially with little impact on opacity. For fabric filters, bag leak detectors are more sensitive to increases in PM emissions than opacity.

EPA is soliciting comment on whether opacity, in conjunction with either monitoring ESP parameters or using fabric filter bag leak detectors, are adequate and the appropriate monitoring parameters for demonstrating continuous proper operation of the PM control device. If not, what parameters should be monitored, and what percent deviation from the baseline is appropriate? EPA is specifically asking if the 110 percent of the baseline opacity value measured during the performance test is an appropriate indicator of the need for a new performance test. Would it be appropriate to add a 5 percent allowable deviation (on a 30-day rolling average) above the baseline opacity or set a lower indicator limit of 5 percent per clock hour regardless of the opacity value measured during the PM performance test? Since facilities using fabric filters generally have low opacity emissions, an hourly opacity limit of 5 percent would apply for them. In contrast, facilities using ESP to control PM emissions tend to have higher opacity emissions, and would still be able to establish a baseline opacity.

To monitor the performance of an ESP, are voltage and secondary current appropriate additional parameters to monitor, and is the 10 percent deviation from the baseline an appropriate amount of variation to trigger a new performance test? As an alternative to establishing a baseline voltage and secondary current, should daily use of an ESP predictive performance computer model be required? One advantage of using a predictive ESP model is that ESP performance is impacted by the properties of the ash. Without using a model that accounts for both the ash characteristics (amount and resistivity) and the ESP operating parameters, voltage and secondary current cannot be directly correlated to PM emissions. If use of a predictive ESP model was added, an affected facility would be required to establish the model parameters during each performance test and then use daily average ash characteristics and ESP parameters to determine if a new performance test has been triggered. Also, since ash characteristics vary significantly even within the same coal type, EPA is considering requiring that the baseline be re-determined (or model parameters adjusted) each time the affected facility changes the ratio of fuels used or takes delivery from a new coal mine or supplier. In addition, to monitor the performance of a fabric filter, is a 5 percent bag leak detector alarm rate on a 30-day rolling basis an appropriate trigger for a performance test?

EPA is also proposing to shorten the time period required to conduct the “triggered” performance test from 60 days to 45 operating days. Should the period be further shortened to 30 operating days from the day of the initial exceedance, or is 60 operating days appropriate?

3. Alternate Carbon Monoxide Monitoring for Oil-Fired Steam Generating Units

One technical error EPA is correcting is the continuous opacity monitoring requirements for oil-fired steam generating units subject to subparts Da, Db, and Dc. Affected industrial, commercial, and institutional steam generating units burning only low sulfur oil have relatively low filterable particulate matter (PM) emissions and are exempt from the PM standard, but still must continuously monitor opacity. For these units, opacity serves both as an emissions limit on visible emissions and as an indicator that the steam generating unit and associated air pollution controls are being properly maintained and operated. The intent of the amendments was to maintain the PM exemption for affected facilities burning low sulfur oil and therefore not require an initial PM performance test. It was not the intent of the amendments to eliminate continuous opacity monitoring for these facilities without first requesting public comment.

Subpart Da requires all affected existing oil-fired steam generating units to demonstrate compliance with the PM standard through a performance test and installation of a COMS to monitor visible emissions. Similar to subpart D, EPA is requesting comment on whether affected steam generating units burning distillate oil containing less than 0.05 weight percent sulfur (500 ppm S) should be exempt from the COMS requirement. As an alternative, should EPA permit low sulfur oil-fired subpart Da affected facilities without PM, SO

, or CO post-combustion controls (except a wet scrubber) to be allowed to use the same CO monitoring alternative for steam generating units subject to subpart D as discussed in Section A.3 of this notice instead of using a COMS? If EPA adopts this provision, the affected source using a CO CEMS in place of a COMS would be subject to the same daily CO action level of 0.15 lb/MMBtu as would be applied to affected sources subject to subpart D. Similar to units with PM CEMS, the 20 percent opacity standard would still apply to the source, but opacity would not be required to be continuously monitored. Since residual oil-fired steam generating units generally require post-combustion controls to achieve the PM standard in subpart Da, in practice EPA would expect that only owners and operators of distillate oil-fired units and residual oil-fired units using wet scrubbers would elect to use this alternative.

4. Alternative PM CEMS Monitoring

For owners and operators of affected electric utility steam generating units electing to use PM CEMS to demonstrate continuous compliance with the applicable PM emissions limit, EPA is proposing a phased data availability requirement. Initially, PM CEMS hourly averages would be required to be obtained for a minimum of 75 percent of all operating hours on a 30-day rolling average basis. Beginning on January 1, 2012, valid PM CEMS hourly averages would be required for a minimum of 90 percent of all operating hours on a 30-day rolling average basis; this value is consistent with the recently amended 90 percent data availability requirement in subpart Da for NO

and SO

CEMS.

EPA is also requesting comments on the proper emissions averaging time for units electing to use PM CEMS. EPA is proposing to maintain that PM emissions be averaged over each operating day, but is requesting comments on whether, alternatively, this average should be on an 8-hour, 24-hour, 30-day, or other appropriate rolling average period. Longer averaging times allow for more stable emission rates and tend toward a lower standard. Shorter averaging times introduce more variability in emission rates and tend toward higher standards. EPA requests that each commenter provide an appropriate emission standard for use with any suggested alternate averaging time.

C. Proposed Substantive Amendments to Subpart Db

1. Emissions Standards

EPA is proposing that steam generating units subject to subpart Db that burn natural gas or coke oven gas

(COG) be exempt from the PM emissions standard. Both natural gas and COG-fired steam generating units do not use post-combustion PM controls, and have inherently low PM emissions. As a result, the PM performance test results in limited environmental benefit.

EPA is also proposing to revise the procedure used to grant site-specific NO

limits under 40 CFR 60.44b. Only a limited number of site-specific limits have been granted under this provision in the past 20 years. Currently, EPA amends subpart Db by a formal notice and comment rulemaking when granting a site-specific limit. To simplify the procedure and reduce administrative burden, EPA is proposing to grant site-specific NO

limits by sending a letter to the facility owner or operator detailing the site-specific limit and publishing that letter in EPA's applicability determination index.

2. Units Burning Coke Oven Gas

Because of the specific characteristics of the steel industry, EPA is proposing to allow a 30-day exceedance per year from the SO

emission limit for steam generating units burning COG exclusively or in combination with other gaseous fuels or distillate oil. COG desulfurization facilities require periodic maintenance, but the coking process continues during this time, and it is cost prohibitive to store the COG. Coke-making facilities would either have to install a second desulfurization unit or flare the COG and burn natural gas during the maintenance period. Of these two options, the least cost option would be to flare the COG and use natural gas during the annual maintenance. This would result in both increased cost to the steel industry and NO

emissions without achieving any reductions in SO

. State permitting authorities have recognized this and have included similar exemptions in their permits.

3. Compliance Procedures

EPA is proposing to amend 40 CFR 60.49b(r) to add a detailed procedure for affected facilities complying with the fuel based limit.

4. Alternate Opacity Monitoring

Since COG-fired steam generating units have filterable PM emissions similar to natural gas, EPA is proposing to exempt industrial-commercial-institutional steam generating units burning COG from the COM requirement.

Under subpart Db, 40 CFR part 60, affected facilities burning coal (except COG), wood, and oil (other than very low sulfur oil) are subject to the PM standard. All coal (except COG), wood, and oil-fired affected facilities are subject to the opacity standard, and are required to install a COMS. Consistent with the CO monitoring alternative for steam generating units subject to subparts D or Da as discussed in Section A.3 of this notice, EPA is proposing to exempt affected industrial-commercial-institutional steam generating units not using post-combustion technology to reduce SO

or PM emissions and burning only distillate oil containing no greater than 0.05 weight percent (500 ppm) sulfur and low sulfur gasified fuels (desulfurized gasified coal and gasified wood) from the COMS requirements in subpart Db. The filterable PM emissions from sources burning low sulfur distillate are inherently low (less than 0.02 lb/MMBtu), and this change would provide flexibility for natural gas-fired steam generating units to burn distillate oil as a backup fuel without having to install and operate a COMS. As an alternative, should EPA permit low sulfur (less than 0.30 weight percent sulfur) affected oil-fired units not using post-combustion technology (except a wet scrubber) to reduce emissions of SO

, PM, or CO to install a CO CEMS in place of a COMS? EPA is considering using the same daily CO action level of 0.15 lb/MMBtu as would be applied to affected sources subject to subpart D or Da. The industrial boiler MACT requires new oil-fired units to monitor CO; allowing this alternate monitoring would reduce the burden on the regulated community while still providing adequate environmental protection.

D. Proposed Substantive Amendments to Subpart Dc

1. Emissions Standards

EPA is proposing that industrial-commercial-institutional steam generating units subject to subpart Dc that burn natural gas or low-sulfur oil be exempt from the PM emissions standard. This amendment reflects EPA's intent for applying the PM emissions limits to industrial-commercial-institutional steam generating units subject to subpart Dc, and would be consistent with the exemption from the PM emissions limits allowed for units subject to Dc that were constructed before February 28, 2005.

2. Compliance Procedures

EPA is proposing to clarify the fuel recordkeeping requirements in 40 CFR 60.48c(g). Owners or operators of steam generating units combusting only natural gas, wood, and distillate oil containing less than 0.5 weight percent sulfur may elect to record fuel usage amounts on a monthly instead of daily basis. In addition, owners or operators of steam generating units with maximum heat input capacities of less than 30 MMBtu/hr and combusting coal and residual oil may elect to record the amounts of fuels combusted each calendar month. EPA has concluded that allowing monthly fuel usage monitoring for these steam generating units provides adequate assurance of compliance, as well as minimizing the burden to affected facilities.

EPA is considering and requesting comments on whether owners or operators of multiple steam generating units located on a contiguous property facility where the only fuels combusted in any steam generating unit located on that property are natural gas, wood, and distillate oil containing no more than 0.50 weight percent sulfur should have the option to elect to only record the total amounts of fuels delivered to the property each calendar month instead of the amount combusted at each affected facility. Draft language EPA is requesting comment on for a potential 40 CFR 60.48c(g)(3) is as follows:

“(3) As an alternative to meeting the requirements of paragraph (g)(1) of this section, the owner or operator of an affected facility or multiple affected facilities located on a contiguous property unit where the only fuels combusted in any steam generating unit (including steam generating units not subject to this subpart) at that property are natural gas, wood, distillate oil meeting the most current requirements in § 60.42c to use fuel certification to demonstrate compliance with the SO

standard, and/or fuels, excluding coal and residual oil, not subject to an emissions standard (excluding opacity) may elect to record and maintain records of the total amount of each steam generating unit fuel delivered to that property during each calendar month.”

This alternative would be restricted to properties where no coal or residual oil is combusted in any steam generating unit located at that property. In addition, the alternative would require that all distillate oil-fired steam generating units located on the property (including those not subject to subpart Dc) only combust distillate oil containing no more than 0.50 weight percent sulfur. If subpart Dc is amended in the future to require the use of lower sulfur distillate oil, all steam generating units located at that property would have to switch to the lower sulfur distillate oil for the owner or operator to elect to use this alternative.

3. Alternate Opacity Monitoring

Under subpart Dc, 40 CFR part 60, affected steam generating units burning coal, wood, and oil containing more than 0.5 weight percent sulfur are subject to the PM standard. All coal, wood, and oil-fired affected facilities are subject to the opacity standard, but affected facilities burning distillate oil containing less than 0.5 weight percent sulfur are exempt from the COM requirement. EPA is proposing that owners and operators of affected steam generating units burning desulfurized gasified coal and gasified wood and not using post-combustion PM or SO

controls be exempt from continuously monitoring opacity. Should the exemption be limited to fuels with potential SO

emissions less than 26 nanograms per Joule heat input (0.06 lb/MMBtu), or should a different potential sulfur limit be required? Sources supporting this exemption should provide emissions data demonstrating that uncontrolled PM emissions are consistently below 0.030 lb/MMBtu. These facilities would still be subject to the PM emission limit and opacity standard, but exempt from the COMS requirement.

Finally, should affected steam generating units burning residual oil containing less than 0.5 weight percent sulfur and/or desulfurized gasified coal and gasified wood have the option of monitoring CO emissions in place of opacity consistent with the CO monitoring alternative for steam generating units subject to subpart D as discussed in Section A.3 of this notice? EPA is requesting comment on whether residual oil-fired steam generating units subject to subpart Dc should be able to elect to install a CO CEMS and maintain daily average CO emission below a level of 0.15 lb/MMBtu in place of the COMS requirement. This would reduce the compliance burden for sources already monitoring CO emissions (due to the boiler MACT or other regulation) and still provide adequate environmental protection.

III. Statutory and Executive Order Reviews

A. Executive Order 12866: Regulatory Planning and Review

This action is not a “significant regulatory action” under the terms of Executive Order (EO) 12866 (58 FR 51735, October 4, 1993) and is, therefore, not subject to review under the EO. EPA has concluded that the amendments EPA is requesting additional comments on will not change the costs or benefits of the rule.

B. Paperwork Reduction Act

This action does not impose any new information collection burden under the provisions of the Paperwork Reduction Act, 44 U.S.C. 3501

et seq.

The proposed amendments result in no changes to the information collection requirements of the existing standards of performance and would have no impact on the information collection estimate of projected cost and hour burden made and approved by the Office of Management and Budget (OMB) during the development of the existing standards of performance. Therefore, the information collection requests have not been amended. OMB has previously approved the information collection requirements contained in the existing standards of performance (40 CFR part 60, subparts Da, Db, and Dc) under the provisions of the Paperwork Reduction Act, 44 U.S.C. 3501

et seq.

, at the time the standards were promulgated on June 11, 1979 (40 CFR part 60, subpart Da, 44 FR 33580), November 25, 1986 (40 CFR part 60, subpart Db, 51 FR 42768), and September 12, 1990 (40 CFR part 60, subpart Dc, 55 FR 37674). OMB assigned OMB control numbers 2060-0023 (ICR 1053.07) for 40 CFR part 60, subpart Da, 2060-0072 (ICR 1088.10) for 40 CFR part 60, subpart Db, 2060-0202 (ICR 1564.06) for 40 CFR part 60, subpart Dc. Copies of the information collection request document(s) may be obtained from Susan Auby by mail at U.S. EPA, Office of Environmental Information, Collection.

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. OMB control numbers for EPA's regulations in 40 CFR are listed in 40 CFR part 9.

C. Regulatory Flexibility Act

The Regulatory Flexibility Act generally requires an agency to prepare a regulatory flexibility analysis of any rule subject to notice and comment rulemaking requirements under the Administrative Procedure Act or any other statute unless the agency certifies that the rule will not have a significant economic impact on a substantial number of small entities. Small entities include small businesses, small organizations, and small governmental jurisdictions.

For purposes of assessing the impacts of the proposed amendments on small entities, small entity is defined as: (1) A small business as defined by the Small Business Administration's regulations at 13 CFR 121.201; (2) a small governmental jurisdiction that is a government of a city, county, town, school district or special district with a population of less than 50,000; and (3) a small organization that is any not-for-profit enterprise which is independently owned and operated and is not dominant in its field.

After considering the economic impacts of this proposed rule on small entities, I certify that this action will not have a significant economic impact on a substantial number of small entities.

Although this proposed rule will not have a significant economic impact on a substantial number of small entities, EPA nonetheless has tried to reduce the impact of this rule on small entities. EPA is proposing to reduce the fuel usage recordkeeping requirement for subpart Dc facilities. In addition, EPA is taking comment on minimizing the continuous opacity monitoring requirements for oil-fired facilities. EPA has, therefore, concluded that this proposed rule will relieve regulatory burden for all affected small entities. EPA continues to be interested in the potential impacts of the proposed rule on small entities and welcome comments on issues related to such impacts.

D. Unfunded Mandates Reform Act

Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), Public Law 104-4, establishes requirements for Federal agencies to assess the effects of their regulatory actions on State, local, and tribal governments and the private sector. Under section 202 of the UMRA, EPA generally must prepare a written statement, including a cost-benefit analysis, for proposed and final rules with “Federal mandates” that may result in expenditures to State, local, and tribal governments, in the aggregate, or to the private sector, of $100 million

or more in any one year. Before promulgating an EPA rule for which a written statement is needed, section 205 of the UMRA generally requires EPA to identify and consider a reasonable number of regulatory alternatives and adopt the least costly, most cost-effective or least burdensome alternative that achieves the objectives of the rule. The provisions of section 205 do not apply when they are inconsistent with applicable law. Moreover, section 205 allows EPA to adopt an alternative other than the least costly, most cost-effective or least burdensome alternative if the Administrator publishes with the final rule an explanation why that alternative was not adopted. Before EPA establishes any regulatory requirements that may significantly or uniquely affect small governments, including tribal governments, it must have developed under section 203 of the UMRA a small government agency plan. The plan must provide for notifying potentially affected small governments, enabling officials of affected small governments to have meaningful and timely input in the development of EPA regulatory proposals with significant Federal intergovernmental mandates, and informing, educating, and advising small governments on compliance with the regulatory requirements.

EPA has determined that the proposed amendments will contain no Federal mandates that may result in expenditures of $100 million or more for State, local, and tribal governments, in the aggregate, or the private sector in any 1 year. Thus, the proposed amendments are not subject to the requirements of section 202 and 205 of the UMRA. In addition, EPA determined that the proposed amendments contain no regulatory requirements that might significantly or uniquely affect small governments because the burden is small and the regulation does not unfairly apply to small governments. Therefore, the proposed amendments are not subject to the requirements of section 203 of the UMRA.

E. Executive Order 13132: Federalism

Executive Order 13132, entitled “Federalism” (64 FR 43255, August 10, 1999), requires EPA to develop an accountable process to ensure “meaningful and timely input by State and local officials in the development of regulatory policies that have federalism implications.” “Policies that have federalism implications” is defined in the Executive Order to include regulations that have “substantial direct effects on the States, on the relationship between the national government and the States, or on the distribution of power and responsibilities among the various levels of government.”

The proposed amendments do not have federalism implications. They will not have substantial direct effects on the States, on the relationship between the national government and the States, or on the distribution of power and responsibilities among the various levels of government, as specified in Executive Order 13132. The proposed amendments will not impose substantial direct compliance costs on State or local governments; it will not preempt State law. Thus, Executive Order 13132 does not apply to the proposed amendments.

F. Executive Order 13175: Consultation and Coordination With Indian Tribal Governments

Executive Order 13175, entitled “Consultation and Coordination with Indian Tribal Governments” (65 FR 67249, November 9, 2000), requires EPA to develop an accountable process to ensure “meaningful and timely input by tribal officials in the development of regulatory policies that have tribal implications.” The proposed amendments do not have tribal implications, as specified in Executive Order 13175. The proposed amendments will not have substantial direct effects on tribal governments, on the relationship between the Federal Government and Indian tribes, or on the distribution of power and responsibilities between the Federal government and Indian tribes. Thus, Executive Order 13175 does not apply to the proposed amendments.

G. Executive Order 13045: Protection of Children From Environmental Health and Safety Risks

Executive Order 13045 (62 FR 19885, April 23, 1997) applies to any rule that: (1) Is determined to be “economically significant” as defined under Executive Order 12866, and (2) concerns an environmental health or safety risk that EPA has reason to believe may have a disproportionate effect on children. If the regulatory action meets both criteria, the Agency must evaluate the environmental health or safety effects of the planned rule on children, and explain why the planned regulation is preferable to other potentially effective and reasonably feasible alternatives considered by the Agency.

This proposed action is not subject to the Executive Order because it is not economically significant as defined under Executive Order 12866, and because EPA interprets Executive Order 13045 as applying only to those regulatory actions that are based on health or safety risks, such that the analysis required under section 5-501 of the Order has the potential to influence the regulation. The proposed amendments are based on technology performance and not on health or safety risks and, therefore, are not subject to Executive Order 13045.

H. Executive Order 13211: Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use

This proposed action is not subject to Executive Order 13211, “Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use” (66 FR 28355, May 22, 2001) because it is not a significant regulatory action under Executive Order 12866.

I. National Technology Transfer Advancement Act

Section 12(d) of the National Technology Transfer and Advancement Act of 1995 (NTTAA), Public Law 104-113, Section 12(d) (15 U.S.C. 272 note) directs us to use voluntary consensus standards in our regulatory activities unless to do so would be inconsistent with applicable law or otherwise impractical. Voluntary consensus standards are technical standards (e.g., material specifications, test methods, sampling procedures, business practices) developed or adopted by one or more voluntary consensus bodies. The NTTAA directs us to provide Congress, through OMB, explanations when EPA decides not use available and applicable voluntary consensus standards.

This action does not involve any new technical standards or the incorporation by reference of existing technical standards. Therefore, the consideration of voluntary consensus standards is not relevant to this action.

List of Subjects in 40 CFR Part 60

Environmental protection, Administrative practice and procedure, Air pollution control, Intergovernmental relations, Reporting and recordkeeping requirements.

Dated: January 31, 2007.

Stephen L. Johnson,

Administrator.

For the reasons stated in the preamble, title 40, chapter I, part 60, of the Code of the Federal Regulations is proposed to be amended as follows:

PART 60—[AMENDED]

1. The authority citation for part 60 continues to read as follows:

Authority:

42 U.S.C. 7401,

et seq.

Subpart A—[Amended]

2. Section 60.17 is amended by revising paragraph (a) to read as follows:

§ 60.17

Incorporation by Reference

(a) The following materials are available for purchase from at least one of the following addresses: American Society for Testing and Materials (ASTM), 100 Barr Harbor Drive, Post Office Box C700, West Conshohocken, PA 19428-2959; or ProQuest, 300 North Zeeb Road, Ann Arbor, MI 48106.

(1) ASTM A99-76, 82 (Reapproved 1987), Standard Specification for Ferromanganese, incorporation by reference (IBR) approved for § 60.261.

(2) ASTM A100-69, 74, 93, Standard Specification for Ferrosilicon, IBR approved for § 60.261.

(3) ASTM A101-73, 93, Standard Specification for Ferrochromium, IBR approved for § 60.261.

(4) ASTM A482-76, 93, Standard Specification for Ferrochromesilicon, IBR approved for § 60.261.

(5) ASTM A483-64, 74 (Reapproved 1988), Standard Specification for Silicomanganese, IBR approved for § 60.261.

(6) ASTM A495-76, 94, Standard Specification for Calcium-Silicon and Calcium Manganese-Silicon, IBR approved for § 60.261.

(7) ASTM D86-78, 82, 90, 93, 95, 96, Distillation of Petroleum Products, IBR approved for §§ 60.562-2(d), 60.593(d), and 60.633(h).

(8) ASTM D129-64, 78, 95, 00, Standard Test Method for Sulfur in Petroleum Products (General Bomb Method), IBR approved for §§ 60.106(j)(2), 60.335(b)(10)(i), and Appendix A: Method 19, 12.5.2.2.3.

(9) ASTM D129-00 (Reapproved 2005), Standard Test Method for Sulfur in Petroleum Products (General Bomb Method), IBR approved for § 60.4415(a)(1)(i).

(10) ASTM D240-92, Standard Test Method for Heat of Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter, IBR approved for § 60.46(c).

(11) ASTM D240-76, 92, Standard Test Method for Heat of Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter, IBR approved for § 60.296(b) and Appendix A: Method 19, Section 12.5.2.2.3.

(12) ASTM D270-65, 75, Standard Method of Sampling Petroleum and Petroleum Products, IBR approved for Appendix A: Method 19, Section 12.5.2.2.1.

(13) ASTM D323-82, 94, Test Method for Vapor Pressure of Petroleum Products (Reid Method), IBR approved for §§ 60.111(l), 60.111a(g), 60.111b(g), and 60.116b(f)(2)(ii).

(14) ASTM D388-99 (Reapproved 2004) ε

, Standard Specification for Classification of Coals by Rank, IBR approved for §§ 60.41(g) of subpart D of this part, 60.45(f)(4)(i), 60.45(f)(4)(ii), 60.45(f)(4)(vi), 60.41Da of subpart Da of this part, and 60.41b of subpart Db of this part, 60.41c of subpart Dc of this part.

(15) ASTM D388-77, 90, 91, 95, 98a, Standard Specification for Classification of Coals by Rank, IBR approved for 60.251(b) and (c) of subpart Y of this part.

(16) ASTM D388-77, 90, 91, 95, 98a, 99 (Reapproved 2004) ε

, Standard Specification for Classification of Coals by Rank, IBR approved for §§ 60.24(h)(8), and 60.4102.

(17) ASTM D396-98, Standard Specification for Fuel Oils, IBR approved for §§ 60.41b of subpart Db of this part and 60.41c of subpart Dc of this part.

(18) ASTM D396-78, 89, 90, 92, 96, 98, Standard Specification for Fuel Oils, IBR approved for 60.111(b) of subpart K of this part and 60.111a(b) of subpart Ka of this part.

(19) ASTM D975-78, 96, 98a, Standard Specification for Diesel Fuel Oils, IBR approved for §§ 60.111(b) of subpart K of this part and 60.111a(b) of subpart Ka of this part.

(20) ASTM D1072-80, 90 (Reapproved 1994), Standard Test Method for Total Sulfur in Fuel Gases, IBR approved for § 60.335(b)(10)(ii).

(21) ASTM D1072-90 (Reapproved 1999), Standard Test Method for Total Sulfur in Fuel Gases, IBR approved for § 60.4415(a)(1)(ii).

(22) ASTM D1137-75, Standard Method for Analysis of Natural Gases and Related Types of Gaseous Mixtures by the Mass Spectrometer, IBR approved for § 60.45(f)(5)(i).

(23) ASTM D1193-77, 91, Standard Specification for Reagent Water, IBR approved for Appendix A: Method 5, Section 7.1.3; Method 5E, Section 7.2.1; Method 5F, Section 7.2.1; Method 6, Section 7.1.1; Method 7, Section 7.1.1; Method 7C, Section 7.1.1; Method 7D, Section 7.1.1; Method 10A, Section 7.1.1; Method 11, Section 7.1.3; Method 12, Section 7.1.3; Method 13A, Section 7.1.2; Method 26, Section 7.1.2; Method 26A, Section 7.1.2; and Method 29, Section 7.2.2.

(24) ASTM D1266-87, 91, 98, Standard Test Method for Sulfur in Petroleum Products (Lamp Method), IBR approved for §§ 60.106(j)(2) and 60.335(b)(10)(i).

(25) ASTM D1266-98 (Reapproved 2003) ε

, Standard Test Method for Sulfur in Petroleum Products (Lamp Method), IBR approved for § 60.4415(a)(1)(i).

(26) ASTM D1475-60 (Reapproved 1980), 90, Standard Test Method for Density of Paint, Varnish Lacquer, and Related Products, IBR approved for § 60.435(d)(1), Appendix A: Method 24, Section 6.1; and Method 24A, Sections 6.5 and 7.1.

(27) ASTM D1552-83, 95, 01, Standard Test Method for Sulfur in Petroleum Products (High-Temperature Method), IBR approved for §§ 60.106(j)(2), 60.335(b)(10)(i), and Appendix A: Method 19, Section 12.5.2.2.3.

(28) ASTM D1552-03, Standard Test Method for Sulfur in Petroleum Products (High-Temperature Method), IBR approved for § 60.4415(a)(1)(i).

(29) ASTM D1826-94, Standard Test Method for Calorific Value of Gases in Natural Gas Range by Continuous Recording Calorimeter, IBR approved for §§ 60.45(f)(5)(ii) and 60.46(c)(2).

(30) ASTM D1826-77, 94, Standard Test Method for Calorific Value of Gases in Natural Gas Range by Continuous Recording Calorimeter, IBR approved for § 60.296(b)(3) and Appendix A: Method 19, Section 12.3.2.4.

(31) ASTM D1835-03a, Standard Specification for Liquefied Petroleum (LP) Gases, IBR approved for § 60.41Da of subpart Da of this part, 60.41b of subpart Db of this part, and 60.41c of subpart Dc of this part.

(32) ASTM D1945-96, Standard Method for Analysis of Natural Gas by Gas Chromatography, IBR approved for § 60.45(f)(5)(i).

(33) ASTM D1946-77, 90 (Reapproved 1994), Standard Method for Analysis of Reformed Gas by Gas Chromatography, IBR approved for §§ 60.18(f)(3), 60.564(f)(1), 60.614(e)(2)(ii), 60.614(e)(4), 60.664(e)(2)(ii), 60.664(e)(4), 60.704(d)(2)(ii), and 60.704(d)(4).

(34) ASTM D1946-90 (Reapproved 1994), Standard Method for Analysis of Reformed Gas by Gas Chromatography, IBR approved for § 60.45(f)(5)(i).

(35) ASTM D2013-72, 86, Standard Method of Preparing Coal Samples for Analysis, IBR approved for Appendix A: Method 19, Section 12.5.2.1.3.

(36) ASTM D2015-96, Standard Test Method for Gross Calorific Value of Solid Fuel by the Adiabatic Bomb Calorimeter, IBR approved for §§ 60.45(f)(5)(ii) and 60.46(c)(2).

(37) ASTM D2015-77 (Reapproved 1978), 96, Standard Test Method for Gross Calorific Value of Solid Fuel by the Adiabatic Bomb Calorimeter, IBR

approved for Appendix A: Method 19, Section 12.5.2.1.3.

(38) ASTM D2016-74, 83, Standard Test Methods for Moisture Content of Wood, IBR approved for Appendix A: Method 28, Section 16.1.1.

(39) ASTM D2234-76, 96, 97b, 98, Standard Methods for Collection of a Gross Sample of Coal, IBR approved for Appendix A: Method 19, Section 12.5.2.1.1.

(40) ASTM D2369-81, 87, 90, 92, 93, 95, Standard Test Method for Volatile Content of Coatings, IBR approved for Appendix A: Method 24, Section 6.2.

(41) ASTM D2382-76, 88, Heat of Combustion of Hydrocarbon Fuels by Bomb Calorimeter (High-Precision Method), IBR approved for §§ 60.18(f)(3), 60.485(g)(6), 60.564(f)(3), 60.614(e)(4), 60.664(e)(4), and 60.704(d)(4).

(42) ASTM D2504-67, 77, 88 (Reapproved 1993), Noncondensable Gases in C3 and Lighter Hydrocarbon Products by Gas Chromatography, IBR approved for § 60.485(g)(5).

(43) ASTM D2584-68 (Reapproved 1985), 94, Standard Test Method for Ignition Loss of Cured Reinforced Resins, IBR approved for § 60.685(c)(3)(i).

(44) ASTM D2597-94 (Reapproved 1999), Standard Test Method for Analysis of Demethanized Hydrocarbon Liquid Mixtures Containing Nitrogen and Carbon Dioxide by Gas Chromatography, IBR approved for § 60.335(b)(9)(i).

(45) ASTM D2622-87, 94, 98, Standard Test Method for Sulfur in Petroleum Products by Wavelength Dispersive X-Ray Fluorescence Spectrometry,” IBR approved for §§ 60.106(j)(2) and 60.335(b)(10)(i).

(46) ASTM D2622-05, Standard Test Method for Sulfur in Petroleum Products by Wavelength Dispersive X-Ray Fluorescence Spectrometry,” IBR approved for § 60.4415(a)(1)(i).

(47) ASTM D2879-83, 96, 97, Test Method for Vapor Pressure-Temperature Relationship and Initial Decomposition Temperature of Liquids by Isoteniscope, IBR approved for §§ 60.111b(f)(3), 60.116b(e)(3)(ii), 60.116b(f)(2)(i), and 60.485(e)(1).

(48) ASTM D2880-78, 96, Standard Specification for Gas Turbine Fuel Oils, IBR approved for §§ 60.111(b), 60.111a(b), and 60.335(d).

(49) ASTM D2908-74, 91, Standard Practice for Measuring Volatile Organic Matter in Water by Aqueous-Injection Gas Chromatography, IBR approved for § 60.564(j).

(50) ASTM D2986-71, 78, 95a, Standard Method for Evaluation of Air, Assay Media by the Monodisperse DOP (Dioctyl Phthalate) Smoke Test, IBR approved for Appendix A: Method 5, Section 7.1.1; Method 12, Section 7.1.1; and Method 13A, Section 7.1.1.2.

(51) ASTM D3173-73, 87, Standard Test Method for Moisture in the Analysis Sample of Coal and Coke, IBR approved for Appendix A: Method 19, Section 12.5.2.1.3.

(52) ASTM D3176-89, Standard Method for Ultimate Analysis of Coal and Coke, IBR approved for § 60.45(f)(5)(i).

(53) ASTM D3176-74, 89, Standard Method for Ultimate Analysis of Coal and Coke, IBR approved for Appendix A: Method 19, Section 12.3.2.3.

(54) ASTM D3177-75, 89, Standard Test Method for Total Sulfur in the Analysis Sample of Coal and Coke, IBR approved for Appendix A: Method 19, Section 12.5.2.1.3.

(55) ASTM D3178-89, Standard Test Methods for Carbon and Hydrogen in the Analysis Sample of Coal and Coke, IBR approved for § 60.45(f)(5)(i).

(56) ASTM D3246-81, 92, 96, Standard Test Method for Sulfur in Petroleum Gas by Oxidative Microcoulometry, IBR approved for § 60.335(b)(10)(ii).

(57) ASTM D3246-05, Standard Test Method for Sulfur in Petroleum Gas by Oxidative Microcoulometry, IBR approved for § 60.4415(a)(1)(ii).

(58) ASTM D3270-73T, 80, 91, 95, Standard Test Methods for Analysis for Fluoride Content of the Atmosphere and Plant Tissues (Semiautomated Method), IBR approved for Appendix A: Method 13A, Section 16.1.

(59) ASTM D3286-85, 96, Standard Test Method for Gross Calorific Value of Coal and Coke by the Isoperibol Bomb Calorimeter, IBR approved for Appendix A: Method 19, Section 12.5.2.1.3.

(60) ASTM D3370-76, 95a, Standard Practices for Sampling Water, IBR approved for § 60.564(j).

(61) ASTM D3792-79, 91, Standard Test Method for Water Content of Water-Reducible Paints by Direct Injection into a Gas Chromatograph, IBR approved for Appendix A: Method 24, Section 6.3.

(62) ASTM D4017-81, 90, 96a, Standard Test Method for Water in Paints and Paint Materials by the Karl Fischer Titration Method, IBR approved for Appendix A: Method 24, Section 6.4.

(63) ASTM D4057-81, 95, Standard Practice for Manual Sampling of Petroleum and Petroleum Products, IBR approved for Appendix A: Method 19, Section 12.5.2.2.3.

(64) ASTM D4057-95 (Reapproved 2000), Standard Practice for Manual Sampling of Petroleum and Petroleum Products, IBR approved for § 60.4415(a)(1).

(65) ASTM D4084-82, 94, Standard Test Method for Analysis of Hydrogen Sulfide in Gaseous Fuels (Lead Acetate Reaction Rate Method), IBR approved for § 60.334(h)(1).

(66) ASTM D4084-05, Standard Test Method for Analysis of Hydrogen Sulfide in Gaseous Fuels (Lead Acetate Reaction Rate Method), IBR approved for §§ 60.4360 and 60.4415(a)(1)(ii).

(67) ASTM D4177-95, Standard Practice for Automatic Sampling of Petroleum and Petroleum Products, IBR approved for Appendix A: Method 19, Section 12.5.2.2.1.

(68) ASTM D4177-95 (Reapproved 2000), Standard Practice for Automatic Sampling of Petroleum and Petroleum Products, IBR approved for § 60.4415(a)(1).

(69) ASTM D4239-85, 94, 97, Standard Test Methods for Sulfur in the Analysis Sample of Coal and Coke Using High Temperature Tube Furnace Combustion Methods, IBR approved for Appendix A: Method 19, Section 12.5.2.1.3.

(70) ASTM D4294-02, Standard Test Method for Sulfur in Petroleum and Petroleum Products by Energy-Dispersive X-Ray Fluorescence Spectrometry, IBR approved for § 60.335(b)(10)(i).

(71) ASTM D4294-03, Standard Test Method for Sulfur in Petroleum and Petroleum Products by Energy-Dispersive X-Ray Fluorescence Spectrometry, IBR approved for § 60.4415(a)(1)(i).

(72) ASTM D4442-84, 92, Standard Test Methods for Direct Moisture Content Measurement in Wood and Wood-base Materials, IBR approved for Appendix A: Method 28, Section 16.1.1.

(73) ASTM D4444-92, Standard Test Methods for Use and Calibration of Hand-Held Moisture Meters, IBR approved for Appendix A: Method 28, Section 16.1.1.

(74) ASTM D4457-85 (Reapproved 1991), Test Method for Determination of Dichloromethane and 1, 1, 1-Trichloroethane in Paints and Coatings by Direct Injection into a Gas Chromatograph, IBR approved for Appendix A: Method 24, Section 6.5.

(75) ASTM D4468-85 (Reapproved 2000), Standard Test Method for Total Sulfur in Gaseous Fuels by Hydrogenolysis and Rateometric Colorimetry, IBR approved for §§ 60.335(b)(10)(ii) and 60.4415(a)(1)(ii).

(76) ASTM D4629-02, Standard Test Method for Trace Nitrogen in Liquid Petroleum Hydrocarbons by Syringe/Inlet Oxidative Combustion and Chemiluminescence Detection, IBR

approved for §§ 60.49b(e) and 60.335(b)(9)(i).

(77) ASTM D4809-95, Standard Test Method for Heat of Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter (Precision Method), IBR approved for §§ 60.18(f)(3), 60.485(g)(6), 60.564(f)(3), 60.614(d)(4), 60.664(e)(4), and 60.704(d)(4).

(78) ASTM D4810-88 (Reapproved 1999), Standard Test Method for Hydrogen Sulfide in Natural Gas Using Length of Stain Detector Tubes, IBR approved for §§ 60.4360 and 60.4415(a)(1)(ii).

(79) ASTM D5287-97 (Reapproved 2002), Standard Practice for Automatic Sampling of Gaseous Fuels, IBR approved for § 60.4415(a)(1).

(80) ASTM D5403-93, Standard Test Methods for Volatile Content of Radiation Curable Materials, IBR approved for Appendix A: Method 24, Section 6.6.

(81) ASTM D5453-00, Standard Test Method for Determination of Total Sulfur in Light Hydrocarbons, Motor Fuels and Oils by Ultraviolet Fluorescence, IBR approved for § 60.335(b)(10)(i).

(82) ASTM D5453-05, Standard Test Method for Determination of Total Sulfur in Light Hydrocarbons, Motor Fuels and Oils by Ultraviolet Fluorescence, IBR approved for § 60.4415(a)(1)(i).

(83) ASTM D5504-01, Standard Test Method for Determination of Sulfur Compounds in Natural Gas and Gaseous Fuels by Gas Chromatography and Chemiluminescence, IBR approved for §§ 60.334(h)(1) and 60.4360.

(84) ASTM D5762-02, Standard Test Method for Nitrogen in Petroleum and Petroleum Products by Boat-Inlet Chemiluminescence, IBR approved for § 60.335(b)(9)(i).

(85) ASTM D5865-98, Standard Test Method for Gross Calorific Value of Coal and Coke, IBR approved for § 60.45(f)(5)(ii), 60.46(c)(2), and Appendix A: Method 19, Section 12.5.2.1.3.

(86) ASTM D6216-98, Standard Practice for Opacity Monitor Manufacturers to Certify Conformance with Design and Performance Specifications, IBR approved for Appendix B, Performance Specification 1.

(87) ASTM D6228-98, Standard Test Method for Determination of Sulfur Compounds in Natural Gas and Gaseous Fuels by Gas Chromatography and Flame Photometric Detection, IBR approved for § 60.334(h)(1).

(88) ASTM D6228-98 (Reapproved 2003), Standard Test Method for Determination of Sulfur Compounds in Natural Gas and Gaseous Fuels by Gas Chromatography and Flame Photometric Detection, IBR approved for §§ 60.4360 and 60.4415.

(89) ASTM D6348-03, Standard Test Method for Determination of Gaseous Compounds by Extractive Direct Interface Fourier Transform Infrared (FTIR) Spectroscopy, IBR approved for table 7 of Subpart IIII of this part.

(90) ASTM D6366-99, Standard Test Method for Total Trace Nitrogen and Its Derivatives in Liquid Aromatic Hydrocarbons by Oxidative Combustion and Electrochemical Detection, IBR approved for § 60.335(b)(9)(i).

(91) ASTM D6522-00, Standard Test Method for Determination of Nitrogen Oxides, Carbon Monoxide, and Oxygen Concentrations in Emissions from Natural Gas-Fired Reciprocating Engines, Combustion Turbines, Boilers, and Process Heaters Using Portable Analyzers, IBR approved for § 60.335(a).

(92) ASTM D6667-01, Standard Test Method for Determination of Total Volatile Sulfur in Gaseous Hydrocarbons and Liquefied Petroleum Gases by Ultraviolet Fluorescence, IBR approved for § 60.335(b)(10)(ii).

(93) ASTM D6667-04, Standard Test Method for Determination of Total Volatile Sulfur in Gaseous Hydrocarbons and Liquefied Petroleum Gases by Ultraviolet Fluorescence, IBR approved for § 60.4415(a)(1)(ii).

(94) ASTM D6784-02, Standard Test Method for Elemental, Oxidized, Particle-Bound and Total Mercury in Flue Gas Generated from Coal-Fired Stationary Sources (Ontario Hydro Method), IBR approved for Appendix B to part 60, Performance Specification 12A, Section 8.6.2.

(95) ASTM E168-67, 77, 92, General Techniques of Infrared Quantitative Analysis, IBR approved for §§ 60.593(b)(2) and 60.632(f).

(96) ASTM E169-63, 77, 93, General Techniques of Ultraviolet Quantitative Analysis, IBR approved for §§ 60.593(b)(2) and 60.632(f).

(97) ASTM E260-73, 91, 96, General Gas Chromatography Procedures, IBR approved for §§ 60.593(b)(2) and 60.632(f).

Subpart D—[Amended]

3. Part 60 is amended by revising subpart D to read as follows:

Subpart D—Standards of Performance for Fossil-Fuel-Fired Steam Generators for Which Construction is Commenced After August 17, 1971

Sec.

60.40

Applicability and designation of affected facility.

60.41

Definitions.

60.42

Standard for particulate matter (PM).

60.43

Standard for sulfur dioxide (SO

60.44

Standard for nitrogen oxides (NO

60.45

Emission and fuel monitoring.

60.46

Test methods and procedures.

Subpart D—Standards of Performance for Fossil-Fuel-Fired Steam Generators for Which Construction Is Commenced After August 17, 1971

§ 60.40

Applicability and designation of affected facility.

(a) The affected facilities to which the provisions of this subpart apply are:

(1) Each fossil-fuel-fired steam generating unit of more than 73 megawatts (MW) heat input rate (250 million British thermal units per hour (MMBtu/hr)).

(2) Each fossil-fuel and wood-residue-fired steam generating unit capable of firing fossil fuel at a heat input rate of more than 73 MW (250 MMBtu/hr).

(b) Any change to an existing fossil-fuel-fired steam generating unit to accommodate the use of combustible materials, other than fossil fuels as defined in this subpart, shall not bring that unit under the applicability of this subpart.

(c) Except as provided in paragraph (d) of this section, any facility under paragraph (a) of this section that commenced construction or modification after August 17, 1971, is subject to the requirements of this subpart.

(d) The requirements of §§ 60.44 (a)(4), (a)(5), (b) and (d), and 60.45(f)(4)(vi) are applicable to lignite-fired steam generating units that commenced construction or modification after December 22, 1976.

(e) Any facility covered under subpart Da is not covered under this subpart.

§ 60.41

Definitions.

As used in this subpart, all terms not defined herein shall have the meaning given them in the Act, and in subpart A of this part.

Boiler operating day

means a 24-hour period between 12 midnight and the following midnight during which any fuel is combusted at any time in the steam-generating unit. It is not necessary for fuel to be combusted the entire 24-hour period.

Fossil-fuel fired steam generating unit

means a furnace or boiler used in the process of burning fossil fuel for the purpose of producing steam by heat transfer.

Fossil fuel

means natural gas, petroleum, coal, and any form of solid, liquid, or gaseous fuel derived from such materials for the purpose of creating useful heat.

Coal refuse

means waste-products of coal mining, cleaning, and coal preparation operations (e.g. culm, gob, etc.) containing coal, matrix material, clay, and other organic and inorganic material.

Fossil fuel and wood residue-fired steam generating unit

means a furnace or boiler used in the process of burning fossil fuel and wood residue for the purpose of producing steam by heat transfer.

Wood residue

means bark, sawdust, slabs, chips, shavings, mill trim, and other wood products derived from wood processing and forest management operations.

Coal

means all solid fuels classified as anthracite, bituminous, subbituminous, or lignite by ASTM D388 (incorporated by reference, see § 60.17).

§ 60.42

Standard for particulate matter (PM).

(a) On and after the date on which the performance test required to be conducted by § 60.8 is completed, no owner or operator subject to the provisions of this subpart shall cause to be discharged into the atmosphere from any affected facility any gases that:

(1) Contain PM in excess of 43 nanograms per joule (ng/J) heat input (0.10 lb/MMBtu) derived from fossil fuel or fossil fuel and wood residue.

(2) Exhibit greater than 20 percent opacity except for one six-minute period per hour of not more than 27 percent opacity.

(b)(1) On or after December 28, 1979, no owner or operator shall cause to be discharged into the atmosphere from the Southwestern Public Service Company's Harrington Station #1, in Amarillo, TX, any gases which exhibit greater than 35 percent opacity, except that a maximum of 42 percent opacity shall be permitted for not more than 6 minutes in any hour.

(2) Interstate Power Company shall not cause to be discharged into the atmosphere from its Lansing Station Unit No. 4 in Lansing, IA, any gases which exhibit greater than 32 percent opacity, except that a maximum of 39 percent opacity shall be permitted for not more than six minutes in any hour.

§ 60.43

Standard for sulfur dioxide (SO

in excess of:

(1) 340 ng/J heat input (0.80 lb/MMBtu) derived from liquid fossil fuel or liquid fossil fuel and wood residue.

(2) 520 ng/J heat input (1.2 lb/MMBtu) derived from solid fossil fuel or solid fossil fuel and wood residue, except as provided in paragraph (e) of this section.

(b) When different fossil fuels are burned simultaneously in any combination, the applicable standard (in ng/J) shall be determined by proration using the following formula:

EP09FE07.000

Where:

= Prorated standard for SO

when burning different fuels simultaneously, in ng/J heat input derived from all fossil fuels;

y = Percentage of total heat input derived from liquid fossil; and

z = Percentage of total heat input derived from solid fossil fuel.

(d) As an alternate to reporting excess emissions every 3 contiguous one hour periods as required under paragraphs (a) and (b) of this section, an owner or operator can petition the Administrator (in writing) to comply with § 60.43Da(i)(3) of subpart Da of this part. If the Administrator grants the petition, the source will from then on (unless the unit is modified or reconstructed in the future) have to comply with the requirements in § 60.43Da(i)(3) of subpart Da of this part.

(e) Units 1 and 2 (as defined in appendix G of this part) at the Newton Power Station owned or operated by the Central Illinois Public Service Company will be in compliance with paragraph (a)(2) of this section if Unit 1 and Unit 2 individually comply with paragraph (a)(2) of this section or if the combined emission rate from Units 1 and 2 does not exceed 470 ng/J (1.1 lb/MMBtu) combined heat input to Units 1 and 2.

§ 60.44

Standard for nitrogen oxides (NO

, expressed as NO

in excess of:

(1) 86 ng/J heat input (0.20 lb/MMBtu) derived from gaseous fossil fuel.

(2) 129 ng/J heat input (0.30 lb/MMBtu) derived from liquid fossil fuel, liquid fossil fuel and wood residue, or gaseous fossil fuel and wood residue.

(3) 300 ng/J heat input (0.70 lb/MMBtu) derived from solid fossil fuel or solid fossil fuel and wood residue (except lignite or a solid fossil fuel containing 25 percent, by weight, or more of coal refuse).

(4) 260 ng/J heat input (0.60 lb MMBtu) derived from lignite or lignite and wood residue (except as provided under paragraph (a)(5) of this section).

(5) 340 ng/J heat input (0.80 lb MMBtu) derived from lignite which is mined in North Dakota, South Dakota, or Montana and which is burned in a cyclone-fired unit.

(b) Except as provided under paragraphs (c) and (d) of this section, when different fossil fuels are burned simultaneously in any combination, the applicable standard (in ng/J) is determined by proration using the following formula:

EP09FE07.001

Where:

= Prorated standard for NO

when burning different fuels simultaneously, in ng/J heat input derived from all fossil fuels fired or from all fossil fuels and wood residue fired;

w = Percentage of total heat input derived from lignite;

x = Percentage of total heat input derived from gaseous fossil fuel;

y = Percentage of total heat input derived from liquid fossil fuel; and

z = Percentage of total heat input derived from solid fossil fuel (except lignite).

(c) When a fossil fuel containing at least 25 percent, by weight, of coal refuse is burned in combination with gaseous, liquid, or other solid fossil fuel or wood residue, the standard for NO

does not apply.

(d) Cyclone-fired units which burn fuels containing at least 25 percent of lignite that is mined in North Dakota, South Dakota, or Montana remain

subject to paragraph (a)(5) of this section regardless of the types of fuel combusted in combination with that lignite.

(e) As an alternate to reporting excess emissions every 3 contiguous one hour periods as required under paragraphs (a) and (b) of this section, an owner or operator can petition the Administrator (in writing) to comply with § 60.44Da(e)(3) of subpart Da of this part. If the Administrator grants the petition, the source will from then on (unless the unit is modified or reconstructed in the future) have to comply with the requirements in § 60.44Da(e)(3) of subpart Da of this part.

§ 60.45

Emission and fuel monitoring.

(a) Each owner or operator shall install, calibrate, maintain, and operate continuous emissions monitoring systems (CEMS) for measuring the opacity of emissions, SO

emissions, NO

emissions, and either oxygen (O

) or carbon dioxide (CO

) except as provided in paragraph (b) of this section.

(b) Certain of the CEMS requirements under paragraph (a) of this section do not apply to owners or operators under the following conditions:

(1) For a fossil fuel-fired steam generator that burns only gaseous fossil fuel and that does not use post combustion technology to reduce emissions of SO

or PM, CEMS for measuring the opacity of emissions and SO

emissions are not required.

(2) For a fossil fuel-fired steam generator that does not use a flue gas desulfurization device, a CEMS for measuring SO

emissions is not required if the owner or operator monitors SO

emissions by fuel sampling and analysis.

(3) Notwithstanding § 60.13(b), installation of a CEMS for NO

may be delayed until after the initial performance tests under § 60.8 have been conducted. If the owner or operator demonstrates during the performance test that emissions of NO

are less than 70 percent of the applicable standards in § 60.44, a CEMS for measuring NO

emissions is not required. If the initial performance test results show that NO

emissions are greater than 70 percent of the applicable standard, the owner or operator shall install a CEMS for NO

within one year after the date of the initial performance tests under § 60.8 and comply with all other applicable monitoring requirements under this part.

(4) If an owner or operator does not install any CEMS for sulfur oxides and NO

, as provided under paragraphs (b)(1) and (b)(3) or paragraphs (b)(2) and (b)(3) of this section a CEMS for measuring either O

or CO

is not required.

(5) An owner or operator may petition the Administrator (in writing) to install a PM CEMS as an alternative to the CEMS for monitoring opacity emissions.

(c) For performance evaluations under § 60.13(c) and calibration checks under § 60.13(d), the following procedures shall be used:

(1) Methods 6, 7, and 3B of appendix A of this part, as applicable, shall be used for the performance evaluations of SO

and NO

continuous monitoring systems. Acceptable alternative methods for Methods 6, 7, and 3B of appendix A of this part are given in § 60.46(d).

(2) Sulfur dioxide or nitric oxide, as applicable, shall be used for preparing calibration gas mixtures under Performance Specification 2 of appendix B to this part.

(3) For affected facilities burning fossil fuel(s), the span value for a continuous monitoring system measuring the opacity of emissions shall be 80, 90, or 100 percent and for a continuous monitoring system measuring sulfur oxides or NO

the span value shall be determined as follows:

[In parts per million]

Fossil fuel

Span value for SO

Span value for NO

Gas

(

)

500

Liquid

1,000

500

Solid

1,500

1,000

Combinations

1,000y + 1,000z

500 (x + y) + 1,000z

Not applicable.

Where:

x = Fraction of total heat input derived from gaseous fossil fuel;

y = Fraction of total heat input derived from liquid fossil fuel; and

z = Fraction of total heat input derived from solid fossil fuel.

(4) All span values computed under paragraph (c)(3) of this section for burning combinations of fossil fuels shall be rounded to the nearest 500 ppm.

(5) For a fossil fuel-fired steam generator that simultaneously burns fossil fuel and nonfossil fuel, the span value of all CEMS shall be subject to the Administrator's approval.

(d) [Reserved]

(e) For any CEMS installed under paragraph (a) of this section, the following conversion procedures shall be used to convert the continuous monitoring data into units of the applicable standards (ng/J, lb/MMBtu):

(1) When a CEMS for measuring O

is selected, the measurement of the pollutant concentration and O

concentration shall each be on a consistent basis (wet or dry). Alternative procedures approved by the Administrator shall be used when measurements are on a wet basis. When measurements are on a dry basis, the following conversion procedure shall be used:

EP09FE07.002

Where E, C, F, and %O

are determined under paragraph (f) of this section.

(2) When a CEMS for measuring CO

is selected, the measurement of the pollutant concentration and CO

concentration shall each be on a consistent basis (wet or dry) and the following conversion procedure shall be used:

EP09FE07.003

Where E, C, F

and %CO

are determined under paragraph (f) of this section.

(f) The values used in the equations under paragraphs (e) (1) and (2) of this section are derived as follows:

(1) E = pollutant emissions, ng/J (lb/MMBtu).

(2) C = pollutant concentration, ng/dscm (lb/dscf), determined by multiplying the average concentration (ppm) for each one-hour period by 4.15 × 10

M ng/dscm per ppm (2.59 × 10

−9

M lb/dscf per ppm) where M = pollutant

molecular weight, g/g-mole (lb/lb-mole). M = 64.07 for SO

and 46.01 for NO

(3) %O

, %CO

= O

or CO

volume (expressed as percent), determined with equipment specified under paragraph (a) of this section.

(4) F, F

= a factor representing a ratio of the volume of dry flue gases generated to the calorific value of the fuel combusted (F), and a factor representing a ratio of the volume of CO

generated to the calorific value of the fuel combusted (F

), respectively. Values of F and F

are given as follows:

(i) For anthracite coal as classified according to ASTM D388 (incorporated by reference, see § 60.17), F = 2,723 × 10

−17

dscm/J (10,140 dscf/MMBtu and F

= 0.532 × 10

−17

scm CO

/J (1,980 scf CO

/MMBtu).

(ii) For subbituminous and bituminous coal as classified according to ASTM D388 (incorporated by reference, see § 60.17), F = 2.637 × 10

−7

dscm/J (9,820 dscf/MMBtu) and F

= 0.486 × 10

−7

scm CO

/J (1,810 scf CO

/MMBtu).

(iii) For liquid fossil fuels including crude, residual, and distillate oils, F = 2.476 × 10

−7

dscm/J (9,220 dscf/MMBtu) and F

= 0.384 × 10

−7

scm CO

/J (1,430 scf CO

/MMBtu).

(iv) For gaseous fossil fuels, F = 2.347 × 10

−7

dscm/J (8,740 dscf/MMBtu). For natural gas, propane, and butane fuels, F

= 0.279 × 10

−7

scm CO

/J (1,040 scf CO

/MMBtu) for natural gas, 0.322 × 10

−7

scm CO

/J (1,200 scf CO

/MMBtu) for propane, and 0.338 × M 10

−7

scm CO

/J (1,260 scf CO

/MMBtu) for butane.

(v) For bark F = 2.589 × 10

−7

dscm/J (9,640 dscf/MMBtu) and F

= 0.500 × 10

−7

scm CO

/J (1,840 scf CO

/MMBtu). For wood residue other than bark F = 2.492 × 10

−7

dscm/J (9,280 dscf/MMBtu) and F

= 0.494 × 10

−7

scm CO

/J (1,860 scf CO

/MMBtu).

(vi) For lignite coal as classified according to ASTM D388 (incorporated by reference, see § 60.17), F = 2.659 × 10

−7

dscm/J (9,900 dscf/MMBtu) and F

= 0.516× 10

−7

scm CO

/J (1,920 scf CO

/MMBtu).

(5) The owner or operator may use the following equation to determine an F factor (dscm/J or dscf/MMBtu) on a dry basis (if it is desired to calculate F on a wet basis, consult the Administrator) or F

factor (scm CO

/J, or scf CO

/MMBtu) on either basis in lieu of the F or F

factors specified in paragraph (f)(4) of this section:

EP09FE07.004

EP09FE07.005

EP09FE07.006

EP09FE07.007

EP09FE07.008

(i) %H, %C, %S, %N, and %O are content by weight of hydrogen, carbon, sulfur, nitrogen, and O

(expressed as percent), respectively, as determined on the same basis as GCV by ultimate analysis of the fuel fired, using ASTM D3178 or D3176 (solid fuels), or computed from results using ASTM D1137, D1945, or D1946 (gaseous fuels) as applicable. (These five methods are incorporated by reference, see § 60.17.)

(ii) GVC is the gross calorific value (kJ/kg, Btu/lb) of the fuel combusted determined by the ASTM test methods D2015 or D5865 for solid fuels and D1826 for gaseous fuels as applicable. (These two methods are incorporated by reference, see § 60.17.)

(iii) For affected facilities which fire both fossil fuels and nonfossil fuels, the F or F

value shall be subject to the Administrator's approval.

(6) For affected facilities firing combinations of fossil fuels or fossil fuels and wood residue, the F or Fc factors determined by paragraphs (f)(4) or (f)(5) of this section shall be prorated in accordance with the applicable formula as follows:

EP09FE07.009

Where:

= Fraction of total heat input derived from each type of fuel (e.g. natural gas, bituminous coal, wood residue, etc.);

or(F

)

= Applicable F or F

factor for each fuel type determined in accordance with paragraphs (f)(4) and (f)(5) of this section; and

n = Number of fuels being burned in combination.

(g) Excess emission and monitoring system performance reports shall be submitted to the Administrator semiannually for each six-month period in the calendar year. All semiannual reports shall be postmarked by the 30th day following the end of each six-month period. Each excess emission and MSP report shall include the information required in § 60.7(c). Periods of excess emissions and monitoring systems (MS) downtime that shall be reported are defined as follows:

(1)

Opacity.

Excess emissions are defined as any six-minute period during which the average opacity of emissions exceeds 20 percent opacity, except that one six-minute average per hour of up to 27 percent opacity need not be reported.

(i) For sources subject to the opacity standard of § 60.42(b)(1), excess emissions are defined as any six-minute period during which the average opacity of emissions exceeds 35 percent opacity, except that one six-minute average per hour of up to 42 percent opacity need not be reported.

(ii) For sources subject to the opacity standard of § 60.42(b)(2), excess emissions are defined as any six-minute period during which the average opacity of emissions exceeds 32 percent opacity, except that one six-minute average per hour of up to 39 percent opacity need not be reported.

(2)

Sulfur dioxide.

Excess emissions for affected facilities are defined as:

(i) Any three-hour period during which the average emissions (arithmetic average of three contiguous one-hour periods) of SO

as measured by a CEMS exceed the applicable standard under § 60.43, or

(ii) Any 30 operating day period during which the average emissions (arithmetic average of all one-hour periods during the 30 operating days) of SO

as measured by a CEMS exceed the applicable standard under § 60.43. Facilities complying with the 30-day SO

standard shall use the most current associated SO

compliance and monitoring requirements in §§ 60.48Da and 60.49Da of subpart Da of this part.

(3)

Nitrogen oxides.

Excess emissions for affected facilities using a CEMS for measuring NO

are defined as:

(i) Any three-hour period during which the average emissions (arithmetic average of three contiguous one-hour periods) exceed the applicable standards under § 60.44, or

(ii) Any 30 operating day period during which the average emissions (arithmetic average of all one-hour periods during the 30 operating days) of NO

as measured by a CEMS exceed the applicable standard under § 60.43. Facilities complying with the 30-day NO

standard shall use the most current associated NO

compliance and monitoring requirements in §§ 60.48Da and 60.49Da of subpart Da of this part.

(4)

Particulate matter.

Excess emissions for affected facilities using a CEMS for measuring PM are defined as any boiler operating day period during which the average emissions (arithmetic average of all operating one-hour periods) exceed the applicable standards under § 60.43. Affected facilities using PM CEMS in lieu of a CEMS for monitoring opacity emissions must follow the most current applicable compliance and monitoring provisions in §§ 60.48Da and 60.49Da of subpart Da of this part.

§ 60.46

Test methods and procedures.

(a) In conducting the performance tests required in § 60.8, and subsequent performance tests as requested by the EPA Administrator, the owner or operator shall use as reference methods and procedures the test methods in appendix A of this part or other methods and procedures as specified in this section, except as provided in § 60.8(b). Acceptable alternative methods and procedures are given in paragraph (d) of this section.

(b) The owner or operator shall determine compliance with the PM, SO

, and NO

standards in §§ 60.42, 60.43, and 60.44 as follows:

(1) The emission rate (E) of PM, SO

, or NO

shall be computed for each run using the following equation:

EP09FE07.010

E = Emission rate of pollutant, ng/J (lb/million Btu);

C = Concentration of pollutant, ng/dscm (lb/dscf);

= O

concentration, percent dry basis; and

= Factor as determined from Method 19 of appendix A of this part.

(2) Method 5 of appendix A of this part shall be used to determine the PM concentration (C) at affected facilities without wet flue-gas-desulfurization (FGD) systems and Method 5B of appendix A of this part shall be used to determine the PM concentration (C) after FGD systems.

(i) The sampling time and sample volume for each run shall be at least 60 minutes and 0.85 dscm (30 dscf). The probe and filter holder heating systems in the sampling train shall be set to provide an average gas temperature of 160 ± 14 °C (320 ± 25 °F).

(ii) The emission rate correction factor, integrated or grab sampling and analysis procedure of Method 3B of appendix A of this part shall be used to determine the O

concentration (%O

). The O

sample shall be obtained simultaneously with, and at the same traverse points as, the particulate sample. If the grab sampling procedure is used, the O

concentration for the run shall be the arithmetic mean of the sample O

concentrations at all traverse points.

(iii) If the particulate run has more than 12 traverse points, the O

traverse points may be reduced to 12 provided that Method 1 of appendix A of this part is used to locate the 12 O

traverse points.

(3) Method 9 of appendix A of this part and the procedures in § 60.11 shall be used to determine opacity.

(4) Method 6 of appendix A of this part shall be used to determine the SO

concentration.

(i) The sampling site shall be the same as that selected for the particulate sample. The sampling location in the duct shall be at the centroid of the cross section or at a point no closer to the walls than 1 m (3.28 ft). The sampling time and sample volume for each sample run shall be at least 20 minutes and 0.020 dscm (0.71 dscf). Two samples shall be taken during a 1-hour period, with each sample taken within a 30-minute interval.

(ii) The emission rate correction factor, integrated sampling and analysis procedure of Method 3B of appendix A of this part shall be used to determine the O

concentration (%O

). The O

sample shall be taken simultaneously with, and at the same point as, the SO

sample. The SO

emission rate shall be computed for each pair of SO

and O

samples. The SO

emission rate (E) for each run shall be the arithmetic mean of the results of the two pairs of samples.

(5) Method 7 of appendix A of this part shall be used to determine the NO

concentration.

(i) The sampling site and location shall be the same as for the SO

sample. Each run shall consist of four grab samples, with each sample taken at about 15-minute intervals.

(ii) For each NO

sample, the emission rate correction factor, grab sampling and analysis procedure of Method 3B of appendix A of this part shall be used to determine the O

concentration (%O

). The sample shall be taken simultaneously with, and at the same point as, the NO

sample.

(iii) The NO

emission rate shall be computed for each pair of NO

and O

samples. The NO

emission rate (E) for each run shall be the arithmetic mean of the results of the four pairs of samples.

(c) When combinations of fossil fuels or fossil fuel and wood residue are fired, the owner or operator (in order to compute the prorated standard as shown in §§ 60.43(b) and 60.44(b)) shall determine the percentage (w, x, y, or z) of the total heat input derived from each type of fuel as follows:

(1) The heat input rate of each fuel shall be determined by multiplying the gross calorific value of each fuel fired by the rate of each fuel burned.

(2) ASTM Methods D2015, or D5865 (solid fuels), D240 (liquid fuels), or D1826 (gaseous fuels) (all of these methods are incorporated by reference, see § 60.17) shall be used to determine the gross calorific values of the fuels. The method used to determine the calorific value of wood residue must be approved by the Administrator.

(3) Suitable methods shall be used to determine the rate of each fuel burned during each test period, and a material balance over the steam generating system shall be used to confirm the rate.

(d) The owner or operator may use the following as alternatives to the reference methods and procedures in this section or in other sections as specified:

(1) The emission rate (E) of PM, SO

and NO

may be determined by using the F

factor, provided that the following procedure is used:

(i) The emission rate (E) shall be computed using the following equation:

EP09FE07.011

Where:

E = Emission rate of pollutant, ng/J (lb/MMBtu);

C = Concentration of pollutant, ng/dscm (lb/dscf);

%CO

= CO

concentration, percent dry basis; and

= Factor as determined in appropriate sections of Method 19 of appendix A of this part.

(ii) If and only if the average F

factor in Method 19 of appendix A of this part is used to calculate E and either E is from 0.97 to 1.00 of the emission standard or the relative accuracy of a continuous emission monitoring system is from 17 to 20 percent, then three runs of Method 3B of appendix A of this part shall be used to determine the O

and CO

concentration according to the procedures in paragraph (b) (2)(ii), (4)(ii), or (5)(ii) of this section. Then if F

(average of three runs), as calculated from the equation in Method 3B of appendix A of this part, is more than ±3 percent than the average F

value, as determined from the average values of F

and F

in Method 19 of appendix A of this part, i.e., F

= 0.209 (F

/ F

), then the following procedure shall be followed:

(A) When F

is less than 0.97 F

, then E shall be increased by that proportion under 0.97 F

, e.g., if F

is 0.95 F

, E shall be increased by 2 percent. This recalculated value shall be used to determine compliance with the emission standard.

(B) When F

is less than 0.97 F

and when the average difference (d) between the continuous monitor minus the reference methods is negative, then E shall be increased by that proportion under 0.97 F

, e.g., if F

is 0.95 F

, E shall be increased by 2 percent. This recalculated value shall be used to determine compliance with the relative accuracy specification.

is greater than 1.03 F

and when the average difference d is positive, then E shall be decreased by that proportion over 1.03 F

, e.g., if F

is 1.05 F

, E shall be decreased by 2 percent. This recalculated value shall be used to determine compliance with the relative accuracy specification.

(2) For Method 5 or 5B of appendix A of this part, Method 17 of appendix A of this part may be used at facilities with or without wet FGD systems if the stack gas temperature at the sampling location does not exceed an average temperature of 160 °C (320 °F). The procedures of sections 2.1 and 2.3 of Method 5B of appendix A of this part may be used with Method 17 of appendix A of this part only if it is used after wet FGD systems. Method 17 of appendix A of this part shall not be used after wet FGD systems if the effluent gas is saturated or laden with water droplets.

(3) Particulate matter and SO

may be determined simultaneously with the Method 5 of appendix A of this part train provided that the following changes are made:

(i) The filter and impinger apparatus in sections 2.1.5 and 2.1.6 of Method 8 of appendix A of this part is used in place of the condenser (section 2.1.7) of Method 5 of appendix A of this part.

(ii) All applicable procedures in Method 8 of appendix A of this part for the determination of SO

(including moisture) are used:

(4) For Method 6 of appendix A of this part, Method 6C of appendix A of this part may be used. Method 6A of appendix A of this part may also be used whenever Methods 6 and 3B of appendix A of this part data are specified to determine the SO

emission rate, under the conditions in paragraph (d)(1) of this section.

(5) For Method 7 of appendix A of this part, Method 7A, 7C, 7D, or 7E of appendix A of this part may be used. If Method 7C, 7D, or 7E of appendix A of this part is used, the sampling time for each run shall be at least 1 hour and the integrated sampling approach shall be used to determine the O

concentration (%O

) for the emission rate correction factor.

(6) For Method 3 of appendix A of this part, Method 3A or 3B of appendix A of this part may be used.

(7) For Method 3B of appendix A of this part, Method 3A of appendix A of this part may be used.

Subpart Da—[Amended]

4. Subpart Da is revised as follows:

Subpart Da—Standards of Performance for Electric Utility Steam Generating Units for Which Construction Is Commenced After September 18, 1978

Sec.

60.40Da

Applicability and designation of affected facility.

60.41Da

Definitions.

60.42Da

Standard for particulate matter (PM).

60.43Da

Standard for sulfur dioxide (SO

60.44Da

Standard for nitrogen oxides (NO

60.45Da

Standard for mercury (Hg).

60.46Da

[Reserved]

60.47Da

Commercial demonstration permit.

60.48Da

Compliance provisions.

60.49Da

Emission monitoring.

60.50Da

Compliance determination procedures and methods.

60.51Da

Reporting requirements.

60.52Da

Recordkeeping requirements.

Subpart Da—Standards of Performance for Electric Utility Steam Generating Units for Which Construction Is Commenced After September 18, 1978

§ 60.40Da

Applicability and designation of affected facility.

(a) The affected facility to which this subpart applies is each electric utility steam-generating unit:

(1) That is capable of combusting more than 73 megawatts (MW) (250 million British thermal units per hour (MMBtu/hr)) heat input of fossil fuel (either alone or in combination with any other fuel); and

(2) For which construction, modification, or reconstruction is commenced after September 18, 1978.

(b) Combined cycle gas turbines (both the stationary combustion turbine and any associated duct burners) are subject to this part and not subject to subpart GG or KKKK of this part if:

(1) The combined cycle gas turbine is capable of combusting more than 73 MW (250 MMBtu/hr) heat input of fossil fuel (either alone or in combination with any other fuel); and

(2) The combined cycle gas turbine is designed and intended to burn fuels containing 50 percent (by heat input) or more solid-derived fuel not meeting the definition of natural gas on a 12-month rolling average basis; and

(3) The combined cycle gas turbine commenced construction, modification, or reconstruction after February 28, 2005.

(4) This subpart will continue to apply to all other electric utility combined cycle gas turbines that are capable of combusting more than 73 MW (250 MMBtu/hr) heat input of fossil fuel in the heat recovery steam generator. If the heat recovery steam generator is subject to this subpart and the stationary combustion turbine is subject to either subpart GG or KKKK of this part, only emissions resulting from combustion of fuels in the steam-generating unit are subject to this subpart. (The stationary combustion turbine emissions are subject to subpart GG or KKKK, as applicable, of this part).

(c) Any change to an existing fossil-fuel-fired steam generating unit to accommodate the use of combustible materials, other than fossil fuels, shall not bring that unit under the applicability of this subpart.

(d) Any change to an existing steam generating unit originally designed to fire gaseous or liquid fossil fuels, to accommodate the use of any other fuel

(fossil or nonfossil) shall not bring that unit under the applicability of this subpart.

§ 60.41Da

Definitions.

As used in this subpart, all terms not defined herein shall have the meaning given them in the Act and in subpart A of this part.

Anthracite

means coal that is classified as anthracite according to the American Society of Testing and Materials in ASTM D388 (incorporated by reference, see § 60.17).

Available purchase power

means the lesser of the following:

(a) The sum of available system capacity in all neighboring companies.

(b) The sum of the rated capacities of the power interconnection devices between the principal company and all neighboring companies, minus the sum of the electric power load on these interconnections.

(c) The rated capacity of the power transmission lines between the power interconnection devices and the electric generating units (the unit in the principal company that has the malfunctioning flue gas desulfurization system and the unit(s) in the neighboring company supplying replacement electrical power) less the electric power load on these transmission lines.

Available system capacity

means the capacity determined by subtracting the system load and the system emergency reserves from the net system capacity.

Biomass

means plant materials and animal waste.

Bituminous coal

means coal that is classified as bituminous according to the American Society of Testing and Materials in ASTM D388 (incorporated by reference, see § 60.17).

Boiler operating day

for units constructed, reconstructed, or modified on or before February 28, 2005, means a 24-hour period during which fossil fuel is combusted in a steam-generating unit for the entire 24 hours. For units constructed, reconstructed, or modified after February 28, 2005,

boiler operating day

Coal

means all solid fuels classified as anthracite, bituminous, subbituminous, or lignite by the American Society of Testing and Materials in ASTM D388 (incorporated by reference, see § 60.17) and coal refuse. Synthetic fuels derived from coal for the purpose of creating useful heat, including but not limited to solvent-refined coal, gasified coal, coal-oil mixtures, and coal-water mixtures are included in this definition for the purposes of this subpart.

Coal-fired electric utility steam generating unit

means 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 fuels in any amount.

Coal refuse

means waste products of coal mining, physical coal cleaning, and coal preparation operations (e.g. culm, gob, etc.) containing coal, matrix material, clay, and other organic and inorganic material.

Cogeneration, also known as “combined heat and power,”

means a steam-generating unit that simultaneously produces both electric (or mechanical) and useful thermal energy from the same primary energy source.

Combined cycle gas turbine

means a stationary turbine combustion system where heat from the turbine exhaust gases is recovered by a steam generating unit.

Dry flue gas desulfurization technology

dry FGD

means a sulfur dioxide control system that is located downstream of the steam generating unit and removes sulfur oxides (SO

) from the combustion gases of the steam generating unit by contacting the combustion gases with an alkaline slurry or solution and forming a dry powder material. This definition includes devices where the dry powder material is subsequently converted to another form. Alkaline slurries or solutions used in dry FGD technology include, but are not limited to, lime and sodium.

Duct burner

means a device that combusts fuel and that is placed in the exhaust duct from another source, such as a stationary gas turbine, internal combustion engine, kiln, etc., to allow the firing of additional fuel to heat the exhaust gases before the exhaust gases enter a heat recovery steam generating unit.

Electric utility combined cycle gas turbine

means any combined cycle gas turbine used for electric generation that is constructed for the purpose of supplying more than one-third of its potential electric output capacity and more than 219,000 megawatt hour (MWh) net electrical output to any utility power distribution system for sale. Any steam distribution system that is constructed for the purpose of providing steam to a steam electric generator that would produce electrical power for sale is also considered in determining the electrical energy output capacity of the affected facility.

Electric utility company

means the largest interconnected organization, business, or governmental entity that generates electric power for sale (e.g., a holding company with operating subsidiary companies).

Electric utility steam-generating unit

means any steam electric generating unit that is constructed for the purpose of supplying more than one-third of its potential electric output capacity and more than 219,000 MWh net-electrical output to any utility power distribution system for sale. Also, any steam supplied to a steam distribution system for the purpose of providing steam to a steam-electric generator that would produce electrical energy for sale is considered in determining the electrical energy output capacity of the affected facility.

Electrostatic precipitator

ESP

means an add-on air pollution control device used to capture particulate matter (PM) by charging the particles using an electrostatic field, collecting the particles using a grounded collecting surface, and transporting the particles into a hopper.

Emergency condition

means that period of time when:

(1) The electric generation output of an affected facility with a malfunctioning flue gas desulfurization system cannot be reduced or electrical output must be increased because:

(i) All available system capacity in the principal company interconnected with the affected facility is being operated, and

(ii) All available purchase power interconnected with the affected facility is being obtained, or

(2) The electric generation demand is being shifted as quickly as possible from an affected facility with a malfunctioning flue gas desulfurization system to one or more electrical generating units held in reserve by the principal company or by a neighboring company, or

(3) An affected facility with a malfunctioning flue gas desulfurization system becomes the only available unit to maintain a part or all of the principal company's system emergency reserves and the unit is operated in spinning reserve at the lowest practical electric generation load consistent with not causing significant physical damage to the unit. If the unit is operated at a higher load to meet load demand, an emergency condition would not exist unless the conditions under paragraph (1) of this definition apply.

Emission limitation

means any emissions limit or operating limit.

Emission rate period

means any calendar month included in a 12-month rolling average period.

Federally enforceable

means all limitations and conditions that are enforceable by the Administrator, including the requirements of 40 CFR parts 60 and 61, requirements within any applicable State implementation plan, and any permit requirements established under 40 CFR 52.21 or under 40 CFR 51.18 and 51.24.

Fossil fuel

means natural gas, petroleum, coal, and any form of solid, liquid, or gaseous fuel derived from such material for the purpose of creating useful heat.

Gaseous fuel

means any fuel derived from coal or petroleum that is present as a gas at standard conditions and includes, but is not limited to, refinery fuel gas, process gas, coke-oven gas, synthetic gas, and gasified coal.

Gross output

means the gross useful work performed by the steam generated. For units generating only electricity, the gross useful work performed is the gross electrical output from the turbine/generator set. For cogeneration units, the gross useful work performed is the gross electrical or mechanical output plus 75 percent of the useful thermal output measured relative to ISO conditions that is not used to generate additional electrical or mechanical output (i.e., steam delivered to an industrial process).

24-hour period

means the period of time between 12:01 a.m. and 12 midnight.

Integrated gasification combined cycle electric utility steam generating unit

IGCC

means a coal-fired electric utility steam generating unit that burns a synthetic gas derived from coal in a combined-cycle gas turbine. No coal is directly burned in the unit during operation.

Interconnected

means that two or more electric generating units are electrically tied together by a network of power transmission lines, and other power transmission equipment.

ISO conditions

means a temperature of 288 Kelvin, a relative humidity of 60 percent, and a pressure of 101.3 kilopascals.

Lignite

means coal that is classified as lignite A or B according to the American Society of Testing and Materials in ASTM D388 (incorporated by reference, see § 60.17).

Natural gas

means:

(1) A naturally occurring mixture of hydrocarbon and nonhydrocarbon gases found in geologic formations beneath the earth's surface, of which the principal constituent is methane; or

(2) Liquid petroleum gas, as defined by the American Society of Testing and Materials in ASTM D1835 (incorporated by reference, see § 60.17); or

(3) A mixture of hydrocarbons that maintains a gaseous state at ISO conditions. Additionally, natural gas must either be composed of at least 70 percent methane by volume or have a gross calorific value between 34 and 43 megajoules (MJ) per standard cubic meter (910 and 1,150 Btu per standard cubic foot).

Neighboring company

means any one of those electric utility companies with one or more electric power interconnections to the principal company and which have geographically adjoining service areas.

Net-electric output

means the gross electric sales to the utility power distribution system minus purchased power on a calendar year basis.

Net system capacity

means the sum of the net electric generating capability (not necessarily equal to rated capacity) of all electric generating equipment owned by an electric utility company (including steam generating units, internal combustion engines, gas turbines, nuclear units, hydroelectric units, and all other electric generating equipment) plus firm contractual purchases that are interconnected to the affected facility that has the malfunctioning flue gas desulfurization system. The electric generating capability of equipment under multiple ownership is prorated based on ownership unless the proportional entitlement to electric output is otherwise established by contractual arrangement.

Noncontinental area

means the State of Hawaii, the Virgin Islands, Guam, American Samoa, the Commonwealth of Puerto Rico, or the Northern Mariana Islands.

Petroleum

means crude oil or petroleum or a fuel derived from crude oil or petroleum, including, but not limited to, distillate oil, residual oil, and petroleum coke.

Potential combustion concentration

means the theoretical emissions (nanograms per joule (ng/J), lb/MMBtu heat input) that would result from combustion of a fuel in an uncleaned state without emission control systems) and:

(1) For particulate matter (PM) is:

(i) 3,000 ng/J (7.0 lb/MMBtu) heat input for solid fuel; and

(ii) 73 ng/J (0.17 lb/MMBtu) heat input for liquid fuels.

(2) For sulfur dioxide (SO

) is determined under § 60.50Da(c).

(3) For nitrogen oxides (NO

) is:

(i) 290 ng/J (0.67 lb/MMBtu) heat input for gaseous fuels;

(ii) 310 ng/J (0.72 lb/MMBtu) heat input for liquid fuels; and

(iii) 990 ng/J (2.30 lb/MMBtu) heat input for solid fuels.

Potential electrical output capacity

means 33 percent of the maximum design heat input capacity of the steam generating unit, divided by 3,413 Btu/KWh, divided by 1,000 kWh/MWh, and multiplied by 8,760 hr/yr (e.g., a steam generating unit with a 100 MW (340 MMBtu/hr) fossil-fuel heat input capacity would have a 289,080 MWh 12 month potential electrical output capacity). For electric utility combined cycle gas turbines the potential electrical output capacity is determined on the basis of the fossil-fuel firing capacity of the steam generator exclusive of the heat input and electrical power contribution by the gas turbine.

Principal company

means the electric utility company or companies which own the affected facility.

Resource recovery unit

means a facility that combusts more than 75 percent non-fossil fuel on a quarterly (calendar) heat input basis.

Responsible official

means responsible official as defined in 40 CFR 70.2.

Solid-derived fuel

means any solid, liquid, or gaseous fuel derived from solid fuel for the purpose of creating useful heat and includes, but is not limited to, solvent refined coal, liquified coal, synthetic gas, gasified coal, gasified petroleum coke, gasified biomass, and gasified tire derived fuel.

Spare flue gas desulfurization system module

means a separate system of SO

emission control equipment capable of treating an amount of flue gas equal to the total amount of flue gas generated by an affected facility when operated at maximum capacity divided by the total number of nonspare flue gas desulfurization modules in the system.

Spinning reserve

means the sum of the unutilized net generating capability of all units of the electric utility company that are synchronized to the power distribution system and that are capable of immediately accepting additional load. The electric generating capability of equipment under multiple ownership is prorated based on ownership unless the proportional entitlement to electric output is otherwise established by contractual arrangement.

Steam generating unit

means any furnace, boiler, or other device used for combusting fuel for the purpose of producing steam (including fossil-fuel-fired steam generators associated with

combined cycle gas turbines; nuclear steam generators are not included).

Subbituminous coal

means coal that is classified as subbituminous A, B, or C according to the American Society of Testing and Materials in ASTM D388 (incorporated by reference, see § 60.17).

System emergency reserves

means an amount of electric generating capacity equivalent to the rated capacity of the single largest electric generating unit in the electric utility company (including steam generating units, internal combustion engines, gas turbines, nuclear units, hydroelectric units, and all other electric generating equipment) which is interconnected with the affected facility that has the malfunctioning flue gas desulfurization system. The electric generating capability of equipment under multiple ownership is prorated based on ownership unless the proportional entitlement to electric output is otherwise established by contractual arrangement.

System load

means the entire electric demand of an electric utility company's service area interconnected with the affected facility that has the malfunctioning flue gas desulfurization system plus firm contractual sales to other electric utility companies. Sales to other electric utility companies (e.g., emergency power) not on a firm contractual basis may also be included in the system load when no available system capacity exists in the electric utility company to which the power is supplied for sale.

Wet flue gas desulfurization technology

wet FGD

means a SO

control system that is located downstream of the steam generating unit and removes sulfur oxides from the combustion gases of the steam generating unit by contacting the combustion gases with an alkaline slurry or solution and forming a liquid material. This definition applies to devices where the aqueous liquid material product of this contact is subsequently converted to other forms. Alkaline reagents used in wet FGD technology include, but are not limited to, lime, limestone, and sodium.

§ 60.42Da

Standard for particulate matter (PM).

(a) On and after the date on which the initial performance test is completed or required to be completed under § 60.8, whichever date comes first, no owner or operator subject to the provisions of this subpart shall cause to be discharged into the atmosphere from any affected facility for which construction, reconstruction, or modification commenced before or on February 28, 2005, any gases that contain PM in excess of:

(1) 13 ng/J (0.03 lb/MMBtu) heat input derived from the combustion of solid, liquid, or gaseous fuel;

(2) 1 percent of the potential combustion concentration (99 percent reduction) when combusting solid fuel; and

(3) 30 percent of potential combustion concentration (70 percent reduction) when combusting liquid fuel.

(b) On and after the date the initial PM performance test is completed or required to be completed under § 60.8, whichever date comes first, no owner or operator subject to the provisions of this subpart shall cause to be discharged into the atmosphere from any affected facility any gases which exhibit greater than 20 percent opacity (6-minute average), except for one 6-minute period per hour of not more than 27 percent opacity.

(c) Except as provided in paragraph (d) of this section, on and after the date on which the initial performance test is completed or required to be completed under § 60.8, whichever date comes first, no owner or operator of an affected facility that commenced construction, reconstruction, or modification after February 28, 2005 shall cause to be discharged into the atmosphere from that affected facility any gases that contain PM in excess of either:

(1) 18 ng/J (0.14 lb/MWh) gross energy output; or

(2) 6.4 ng/J (0.015 lb/MMBtu) heat input derived from the combustion of solid, liquid, or gaseous fuel.

(d) As an alternative to meeting the requirements of paragraph (c) of this section, the owner or operator of an affected facility for which construction, reconstruction, or modification commenced after February 28, 2005, may elect to meet the requirements of this paragraph. On and after the date on which the initial performance test is completed or required to be completed under § 60.8, whichever date comes first, no owner or operator of an affected facility shall cause to be discharged into the atmosphere from that affected facility for which construction, reconstruction, or modification commenced after February 28, 2005, any gases that contain PM in excess of:

(1) 13 ng/J (0.03 lb/MMBtu) heat input derived from the combustion of solid, liquid, or gaseous fuel, and

(2) 0.1 percent of the combustion concentration determined according to the procedure in § 60.48Da(o)(5) (99.9 percent reduction) for an affected facility for which construction or reconstruction commenced after February 28, 2005 when combusting solid, liquid, or gaseous fuel, or

(3) 0.2 percent of the combustion concentration determined according to the procedure in § 60.48Da(o)(5) (99.8 percent reduction) for an affected facility for which modification commenced after February 28, 2005 when combusting solid, liquid, or gaseous fuel.

§ 60.43Da

Standard for sulfur dioxide (SO

(a) On and after the date on which the initial performance test is completed or required to be completed under § 60.8, whichever date comes first, no owner or operator subject to the provisions of this subpart shall cause to be discharged into the atmosphere from any affected facility which combusts solid fuel or solid-derived fuel and for which construction, reconstruction, or modification commenced before or on February 28, 2005, except as provided under paragraphs (c), (d), (f) or (h) of this section, any gases that contain SO

in excess of:

(1) 520 ng/J (1.20 lb/MMBtu) heat input and 10 percent of the potential combustion concentration (90 percent reduction); or

(2) 30 percent of the potential combustion concentration (70 percent reduction), when emissions are less than 260 ng/J (0.60 lb/MMBtu) heat input.

(b) On and after the date on which the initial performance test is completed or required to be completed under § 60.8, whichever date comes first, no owner or operator subject to the provisions of this subpart shall cause to be discharged into the atmosphere from any affected facility which combusts liquid or gaseous fuels (except for liquid or gaseous fuels derived from solid fuels and as provided under paragraphs (e) or (h) of this section) and for which construction, reconstruction, or modification commenced before or on February 28, 2005, any gases that contain SO

in excess of:

(1) 340 ng/J (0.80 lb/MMBtu) heat input and 10 percent of the potential combustion concentration (90 percent reduction); or

(2) 100 percent of the potential combustion concentration (zero percent reduction) when emissions are less than 86 ng/J (0.20 lb/MMBtu) heat input.

(c) On and after the date on which the initial performance test is completed or required to be completed under § 60.8, whichever date comes first, no owner or operator subject to the provisions of this subpart shall cause to be discharged into the atmosphere from any affected facility which combusts solid solvent

refined coal (SRC-I) any gases that contain SO

in excess of 520 ng/J (1.20 lb/MMBtu) heat input and 15 percent of the potential combustion concentration (85 percent reduction) except as provided under paragraph (f) of this section; compliance with the emission limitation is determined on a 30-day rolling average basis and compliance with the percent reduction requirement is determined on a 24-hour basis.

(d) Sulfur dioxide emissions are limited to 520 ng/J (1.20 lb/MMBtu) heat input from any affected facility which:

(1) Combusts 100 percent anthracite;

(2) Is classified as a resource recovery unit; or

(3) Is located in a noncontinental area and combusts solid fuel or solid-derived fuel.

(e) Sulfur dioxide emissions are limited to 340 ng/J (0.80 lb/MMBtu) heat input from any affected facility which is located in a noncontinental area and combusts liquid or gaseous fuels (excluding solid-derived fuels).

(f) The emission reduction requirements under this section do not apply to any affected facility that is operated under an SO

commercial demonstration permit issued by the Administrator in accordance with the provisions of § 60.47Da.

(g) Compliance with the emission limitation and percent reduction requirements under this section are both determined on a 30-day rolling average basis except as provided under paragraph (c) of this section.

(h) When different fuels are combusted simultaneously, the applicable standard is determined by proration using the following formula:

(1) If emissions of SO

to the atmosphere are greater than 260 ng/J (0.60 lb/MMBtu) heat input.

EP09FE07.012

(2) If emissions of SO

to the atmosphere are equal to or less than 260 ng/J (0.60 lb/MMBtu) heat input:

EP09FE07.013

Where:

= Prorated SO

emission limit (ng/J heat input);

= Percentage of potential SO

emission allowed;

x = Percentage of total heat input derived from the combustion of liquid or gaseous fuels (excluding solid-derived fuels); and

y = Percentage of total heat input derived from the combustion of solid fuel (including solid-derived fuels).

(i) Except as provided in paragraphs (j) and (k) of this section, on and after the date on which the initial performance test is completed or required to be completed under § 60.8, whichever date comes first, no owner or operator of an affected facility that commenced construction, reconstruction, or modification commenced after February 28, 2005 shall cause to be discharged into the atmosphere from that affected facility, any gases that contain SO

in excess of the applicable emission limitation specified in paragraphs (i)(1) through (3) of this section.

(1) For an affected facility for which construction commenced after February 28, 2005, any gases that contain SO

in excess of either:

(i) 180 ng/J (1.4 lb/MWh) gross energy output on a 30-day rolling average basis; or

(ii) 5 percent of the potential combustion concentration (95 percent reduction) on a 30-day rolling average basis.

(2) For an affected facility for which reconstruction commenced after February 28, 2005, any gases that contain SO

in excess of either:

(i) 180 ng/J (1.4 lb/MWh) gross energy output on a 30-day rolling average basis;

(ii) 65 ng/J (0.15 lb/MMBtu) heat input on a 30-day rolling average basis; or

(iii) 5 percent of the potential combustion concentration (95 percent reduction) on a 30-day rolling average basis.

(3) For an affected facility for which modification commenced after February 28, 2005, any gases that contain SO

in excess of either:

(i) 180 ng/J (1.4 lb/MWh) gross energy output on a 30-day rolling average basis;

(ii) 65 ng/J (0.15 lb/MMBtu) heat input on a 30-day rolling average basis; or

(iii) 10 percent of the potential combustion concentration (90 percent reduction) on a 30-day rolling average basis.

(j) On and after the date on which the initial performance test is completed or required to be completed under § 60.8, whichever date comes first, no owner or operator of an affected facility that commenced construction, reconstruction, or modification commenced after February 28, 2005, and that burns 75 percent or more (by heat input) coal refuse on a 12-month rolling average basis, shall caused to be discharged into the atmosphere from that affected facility any gases that contain SO

in excess of the applicable emission limitation specified in paragraphs (j)(1) through (3) of this section.

(1) For an affected facility for which construction commenced after February 28, 2005, any gases that contain SO

in excess of either:

(i) 180 ng/J (1.4 lb/MWh) gross energy output on a 30-day rolling average basis; or

(ii) 6 percent of the potential combustion concentration (94 percent reduction) on a 30-day rolling average basis.

(2) For an affected facility for which reconstruction commenced after February 28, 2005, any gases that contain SO

in excess of either:

(i) 180 ng/J (1.4 lb/MWh) gross energy output on a 30-day rolling average basis;

(ii) 65 ng/J (0.15 lb/MMBtu) heat input on a 30-day rolling average basis; or

(iii) 6 percent of the potential combustion concentration (94 percent reduction) on a 30-day rolling average basis.

(3) For an affected facility for which modification commenced after February 28, 2005, any gases that contain SO

in excess of either:

(i) 180 ng/J (1.4 lb/MWh) gross energy output on a 30-day rolling average basis;

(ii) 65 ng/J (0.15 lb/MMBtu) heat input on a 30-day rolling average basis; or

(iii) 10 percent of the potential combustion concentration (90 percent reduction) on a 30-day rolling average basis.

(k) On and after the date on which the initial performance test is completed or required to be completed under § 60.8, whichever date comes first, no owner or operator of an affected facility located in a noncontinental area that commenced construction, reconstruction, or modification commenced after February 28, 2005, shall cause to be discharged into the atmosphere from that affected facility any gases that contain SO

in excess of the applicable emission limitation specified in paragraphs (k)(1) and (2) of this section.

(1) For an affected facility that burns solid or solid-derived fuel, the owner or operator shall not cause to be discharged into the atmosphere any gases that contain SO

in excess of 520 ng/J (1.2 lb/MMBtu) heat input on a 30-day rolling average basis.

(2) For an affected facility that burns other than solid or solid-derived fuel, the owner or operator shall not cause to be discharged into the atmosphere any

gases that contain SO

in excess of if the affected facility or 230 ng/J (0.54 lb/MMBtu) heat input on a 30-day rolling average basis.

§ 60.44Da

Standard for nitrogen oxides (NO

(a) On and after the date on which the initial performance test is completed or required to be completed under § 60.8, whichever date comes first, no owner or operator subject to the provisions of this subpart shall cause to be discharged into the atmosphere from any affected facility, except as provided under paragraphs (b), (d), (e), and (f) of this section, any gases that contain NO

(expressed as NO

) in excess of the following emission limits, based on a 30-day rolling average basis, except as provided under § 60.48Da(j)(1):

(1) NO

emission limits.

Fuel type

Emission limit for heat input

ng/J

lb/MMBtu

Gaseous fuels:

Coal-derived fuels

210

0.50

All other fuels

0.20

Liquid fuels:

Coal-derived fuels

210

0.50

Shale oil

210

0.50

All other fuels

130

0.30

Solid fuels:

Coal-derived fuels

210

0.50

Any fuel containing more than 25%, by weight, coal refuse

Any fuel containing more than 25%, by weight, lignite if the lignite is mined in North Dakota, South Dakota, or Montana, and is combusted in a slag tap furnace

340

0.80

Any fuel containing more than 25%, by weight, lignite not subject to the 340 ng/J heat input emission limit

260

0.60

Subbituminous coal

210

0.50

Bituminous coal

260

0.60

Anthracite coal

260

0.60

All other fuels

260

0.60

Exempt from NO

standards and NO

monitoring requirements.

Any fuel containing less than 25%, by weight, lignite is not prorated but its percentage is added to the percentage of the predominant fuel.

(2)

reduction requirement.

Fuel type

Percent reduction of potential combustion

concentration

Gaseous fuels

Liquid fuels

Solid fuels

(b) The emission limitations under paragraph (a) of this section do not apply to any affected facility which is combusting coal-derived liquid fuel and is operating under a commercial demonstration permit issued by the Administrator in accordance with the provisions of § 60.47Da.

(c) Except as provided under paragraphs (d), (e), and (f) of this section, when two or more fuels are combusted simultaneously, the applicable standard is determined by proration using the following formula:

EP09FE07.014

Where:

= Applicable standard for NO

when multiple fuels are combusted simultaneously (ng/J heat input);

w = Percentage of total heat input derived from the combustion of fuels subject to the 86 ng/J heat input standard;

x = Percentage of total heat input derived from the combustion of fuels subject to the 130 ng/J heat input standard;

y = Percentage of total heat input derived from the combustion of fuels subject to the 210 ng/J heat input standard;

z = Percentage of total heat input derived from the combustion of fuels subject to the 260 ng/J heat input standard; and

v = Percentage of total heat input delivered from the combustion of fuels subject to the 340 ng/J heat input standard.

(d)(1) On and after the date on which the initial performance test is completed or required to be completed under § 60.8, whichever date comes first, no owner or operator of an affected facility that commenced construction after July 9, 1997, but before or on February 28, 2005 shall cause to the atmosphere any gases that contain NO

(expressed as NO

) in excess of 200 ng/J (1.6 lb/MWh) gross energy output, based on a 30-day rolling average basis, except as provided under § 60.48Da(k).

(2) On and after the date on which the initial performance test is completed or required to be completed under § 60.8, whichever date comes first, no owner or operator of affected facility for which reconstruction commenced after July 9, 1997, but before or on February 28, 2005 shall cause to be discharged into the atmosphere any gases that contain NO

(expressed as NO

) in excess of 65 ng/J (0.15 lb/MMBtu) heat input, based on a 30-day rolling average basis.

(e) Except for an IGCC meeting the requirements of paragraph (f) of this section, on and after the date on which the initial performance test is completed or required to be completed under § 60.8, whichever date comes first, no owner or operator of an affected facility that commenced construction, reconstruction, or modification after February 28, 2005 shall cause to be discharged into the atmosphere from that affected facility any gases that contain NO

(expressed as NO

) in excess of the applicable emission limitation specified in paragraphs (e)(1) through (3) of this section.

(1) For an affected facility for which construction commenced after February 28, 2005, the owner or operator shall not cause to be discharged into the atmosphere any gases that contain NO

(expressed as NO

) in excess of 130 ng/J (1.0 lb/MWh) gross energy output on a 30-day rolling average basis, except as provided under § 60.48Da(k).

(2) For an affected facility for which reconstruction commenced after February 28, 2005, the owner or operator shall not cause to be discharged into the atmosphere any gases that contain NO

(expressed as NO

) in excess of either:

(i) 130 ng/J (1.0 lb/MWh) gross energy output on a 30-day rolling average basis; or

(ii) 47 ng/J (0.11 lb/MMBtu) heat input on a 30-day rolling average basis.

(3) For an affected facility for which modification commenced after February 28, 2005, the owner or operator shall not cause to be discharged into the atmosphere any gases that contain NO

(expressed as NO

) in excess of either:

(i) 180 ng/J (1.4 lb/MWh) gross energy output on a 30-day rolling average basis; or

(ii) 65 ng/J (0.15 lb/MMBtu) heat input on a 30-day rolling average basis.

(f) On and after the date on which the initial performance test is completed or required to be completed under § 60.8, whichever date comes first, no owner or operator of an IGCC subject to the provisions of this subpart that burns liquid fuel as a supplemental fuel and for which construction, reconstruction, or modification commenced after February 28, 2005, shall meet the requirements specified in paragraphs (f)(1) through (3) of this section.

(1) The owner or operator shall not cause to be discharged into the atmosphere any gases that contain NO

(expressed as NO

) in excess of 130 ng/J (1.0 lb/MWh) gross energy output on a 30-day rolling average basis, except as provided for in paragraphs (f)(2) and (3) of this section.

(2) When burning liquid fuel exclusively or in combination with solid-derived fuel such that the liquid fuel contributes 50 percent or more of the total heat input to the combined cycle combustion turbine, the owner or operator shall not cause to be discharged into the atmosphere any gases that contain NO

(expressed as NO

) in excess of 190 ng/J (1.5 lb/MWh) gross energy output on a 30-day rolling average basis.

(3) In cases when during a 30-day rolling average compliance period liquid fuel is burned in such a manner to meet the conditions in paragraph (f)(2) of this section for only a portion of the clock hours in the 30-day period, the owner or operator shall not cause to be discharged into the atmosphere any gases that contain NO

(expressed as NO

) in excess of the computed weighted-average emissions limit based on the proportion of gross energy output (in MWh) generated during the compliance period for each of emissions limits in paragraphs (f)(1) and (2) of this section.

§ 60.45Da

Standard for mercury (Hg).

(a) For each coal-fired electric utility steam generating unit other than an IGCC electric utility steam generating unit, on and after the date on which the initial performance test is completed or required to be completed under § 60.8, whichever date comes first, no owner or operator subject to the provisions of this subpart shall cause to be discharged into the atmosphere from any affected facility for which construction, modification, or reconstruction commenced after January 30, 2004, any gases that contain mercury (Hg) emissions in excess of each Hg emissions limit in paragraphs (a)(1) through (5) of this section that applies to you. The Hg emissions limits in paragraphs (a)(1) through (5) of this section are based on a 12-month rolling average basis using the procedures in § 60.50Da(h).

(1) For each coal-fired electric utility steam generating unit that burns only bituminous coal, you must not discharge into the atmosphere any gases from a new affected source that contain Hg in excess of 20 × 10

−6

pound per megawatt hour (lb/MWh) or 0.020 lb/gigawatt-hour (GWh) on an output basis. The International System of Units (SI) equivalent is 0.0025 ng/J.

(2) For each coal-fired electric utility steam generating unit that burns only subbituminous coal:

(i) If your unit is located in a county-level geographical area receiving greater than 25 inches per year (in/yr) mean annual precipitation, based on the most recent publicly available U.S. Department of Agriculture 30-year data, you must not discharge into the atmosphere any gases from a new affected source that contain Hg in excess of 66 × 10

−6

lb/MWh or 0.066 lb/GWh on an output basis. The SI equivalent is 0.0083 ng/J.

(ii) If your unit is located in a county-level geographical area receiving less than or equal to 25 in/yr mean annual precipitation, based on the most recent publicly available U.S. Department of Agriculture 30-year data, you must not discharge into the atmosphere any gases from a new affected source that contain Hg in excess of 97 × 10

−6

lb/MWh or 0.097 lb/GWh on an output basis. The SI equivalent is 0.0122 ng/J.

(3) For each coal-fired electric utility steam generating unit that burns only lignite, you must not discharge into the atmosphere any gases from a new affected source that contain Hg in excess of 175 × 10

−6

lb/MWh or 0.175 lb/GWh on an output basis. The SI equivalent is 0.0221 ng/J.

(4) For each coal-burning electric utility steam generating unit that burns only coal refuse, you must not discharge into the atmosphere any gases from a new affected source that contain Hg in excess of 16 × 10

−6

lb/MWh or 0.016 lb/GWh on an output basis. The SI equivalent is 0.0020 ng/J.

(5) For each coal-fired electric utility steam generating unit that burns a blend of coals from different coal ranks (i.e., bituminous coal, subbituminous coal, lignite) or a blend of coal and coal refuse, you must not discharge into the atmosphere any gases from a new affected source that contain Hg in excess of the unit-specific Hg emissions limit established according to paragraph (a)(5)(i) or (ii) of this section, as applicable to the affected unit.

(i) If you operate a coal-fired electric utility steam generating unit that burns a blend of coals from different coal ranks or a blend of coal and coal refuse, you must not discharge into the atmosphere any gases from a new affected source that contain Hg in excess of the computed weighted Hg emissions limit based on the Btu, MWh, or MJ contributed by each coal rank burned during the compliance period and its applicable Hg emissions limit in paragraphs (a)(1) through (4) of this section as determined using Equation 1 in this section. For each affected source, you must comply with the weighted Hg emissions limit calculated using Equation 1 in this section based on the total Hg emissions from the unit and the total Btu, MWh, or MJ contributed by all fuels burned during the compliance period.

EP09FE07.015

Where:

= Total allowable Hg in lb/MWh that can be emitted to the atmosphere from any affected source being averaged according to this paragraph.

= Hg emissions limit for the subcategory i (coal rank) that applies to affected source, lb/MWh;

= For each affected source, the Btu, MWh, or MJ contributed by the corresponding subcategory i (coal rank) burned during the compliance period; and

n = Number of subcategories (coal ranks) being averaged for an affected source.

(ii) If you operate a coal-fired electric utility steam generating unit that burns a blend of coals from different coal ranks or a blend of coal and coal refuse together with one or more non-regulated, supplementary fuels, you must not discharge into the atmosphere any gases from a new affected source that contain Hg in excess of the computed weighted Hg emission limit based on the Btu, MWh, or MJ

contributed by each coal rank burned during the compliance period and its applicable Hg emissions limit in paragraphs (a)(1) through (4) of this section as determined using Equation 1 in this section. For each affected source, you must comply with the weighted Hg emissions limit calculated using Equation 1 in this section based on the total Hg emissions from the unit contributed by both regulated and nonregulated fuels burned during the compliance period and the total Btu, MWh, or MJ contributed by both regulated and nonregulated fuels burned during the compliance period.

(b) For each IGCC electric utility steam generating unit, on and after the date on which the initial performance test required to be conducted under § 60.8 is completed, no owner or operator subject to the provisions of this subpart shall cause to be discharged into the atmosphere from any affected facility for which construction, modification, or reconstruction commenced after January 30, 2004, any gases that contain Hg emissions in excess of 20 × 10

−6

lb/MWh or 0.020 lb/GWh on an output basis. The SI equivalent is 0.0025 ng/J. This Hg emissions limit is based on a 12-month rolling average basis using the procedures in § 60.50Da(h).

§ 60.46Da

[Reserved]

§ 60.47Da

Commercial demonstration permit.

(a) An owner or operator of an affected facility proposing to demonstrate an emerging technology may apply to the Administrator for a commercial demonstration permit. The Administrator will issue a commercial demonstration permit in accordance with paragraph (e) of this section. Commercial demonstration permits may be issued only by the Administrator, and this authority will not be delegated.

(b) An owner or operator of an affected facility that combusts solid solvent refined coal (SRC-I) and who is issued a commercial demonstration permit by the Administrator is not subject to the SO

emission reduction requirements under § 60.43Da(c) but must, as a minimum, reduce SO

emissions to 20 percent of the potential combustion concentration (80 percent reduction) for each 24-hour period of steam generator operation and to less than 520 ng/J (1.20 lb/MMBtu) heat input on a 30-day rolling average basis.

(c) An owner or operator of a fluidized bed combustion electric utility steam generator (atmospheric or pressurized) who is issued a commercial demonstration permit by the Administrator is not subject to the SO

emission reduction requirements under § 60.43Da(a) but must, as a minimum, reduce SO

emissions to 15 percent of the potential combustion concentration (85 percent reduction) on a 30-day rolling average basis and to less than 520 ng/J (1.20 lb/MMBtu) heat input on a 30-day rolling average basis.

(d) The owner or operator of an affected facility that combusts coal-derived liquid fuel and who is issued a commercial demonstration permit by the Administrator is not subject to the applicable NO

emission limitation and percent reduction under § 60.44Da(a) but must, as a minimum, reduce emissions to less than 300 ng/J (0.70 lb/MMBtu) heat input on a 30-day rolling average basis.

(e) Commercial demonstration permits may not exceed the following equivalent MW electrical generation capacity for any one technology category, and the total equivalent MW electrical generation capacity for all commercial demonstration plants may not exceed 15,000 MW.

Technology

Pollutant

Equivalent Electrical Capacity (MW electrical output)

Solid solvent refined coal (SCR I)

6,000-10,000

Fluidized bed combustion (atmospheric)

400-3,000

Fluidized bed combustion (pressurized)

400-1,200

Coal liquification

750-10,000

Total allowable for all technologies

15,000

§ 60.48Da

Compliance provisions.

(a) Compliance with the PM emission limitation under § 60.42Da(a)(1) constitutes compliance with the percent reduction requirements for PM under § 60.42Da(a)(2) and (3).

(b) Compliance with the NO

emission limitation under § 60.44Da(a)(1) constitutes compliance with the percent reduction requirements under § 60.44Da(a)(2).

emission standards under § 60.44Da, and the Hg emission standards under § 60.45Da apply at all times except during periods of startup, shutdown, or malfunction.

(d) During emergency conditions in the principal company, an affected facility with a malfunctioning flue gas desulfurization system may be operated if SO

emissions are minimized by:

(1) Operating all operable flue gas desulfurization system modules, and bringing back into operation any malfunctioned module as soon as repairs are completed,

(2) Bypassing flue gases around only those flue gas desulfurization system modules that have been taken out of operation because they were incapable of any SO

emission reduction or which would have suffered significant physical damage if they had remained in operation, and

(3) Designing, constructing, and operating a spare flue gas desulfurization system module for an affected facility larger than 365 MW (1,250 MMBtu/hr) heat input (approximately 125 MW electrical output capacity). The Administrator may at his discretion require the owner or operator within 60 days of notification to demonstrate spare module capability. To demonstrate this capability, the owner or operator must demonstrate compliance with the appropriate requirements under paragraph under § 60.43Da(a), (b), (d), (e), and (h) for any period of operation lasting from 24 hours to 30 days when:

(i) Any one flue gas desulfurization module is not operated,

(ii) The affected facility is operating at the maximum heat input rate,

(iii) The fuel fired during the 24-hour to 30-day period is representative of the type and average sulfur content of fuel used over a typical 30-day period, and

(iv) The owner or operator has given the Administrator at least 30 days notice of the date and period of time over which the demonstration will be performed.

(e) After the initial performance test required under § 60.8, compliance with

the SO

emission limitations and percentage reduction requirements under § 60.43Da and the NO

emission limitations under § 60.44Da is based on the average emission rate for 30 successive boiler operating days. A separate performance test is completed at the end of each boiler operating day after the initial performance test, and a new 30 day average emission rate for both SO

and NO

and a new percent reduction for SO

are calculated to show compliance with the standards.

(f) For the initial performance test required under § 60.8, compliance with the SO

emission limitations and percent reduction requirements under § 60.43Da and the NO

emission limitation under § 60.44Da is based on the average emission rates for SO

, NO

, and percent reduction for SO

for the first 30 successive boiler operating days. The initial performance test is the only test in which at least 30 days prior notice is required unless otherwise specified by the Administrator. The initial performance test is to be scheduled so that the first boiler operating day of the 30 successive boiler operating days is completed within 60 days after achieving the maximum production rate at which the affected facility will be operated, but not later than 180 days after initial startup of the facility.

(g) The owner or operator of an affected facility subject to emission limitations in this subpart shall determine compliance as follows:

(1) Compliance with applicable 30-day rolling average SO

and NO

emission limitations is determined by calculating the arithmetic average of all hourly emission rates for SO

and NO

for the 30 successive boiler operating days, except for data obtained during startup, shutdown, malfunction (NO

only), or emergency conditions (SO

only).

(2) Compliance with applicable SO

percentage reduction requirements is determined based on the average inlet and outlet SO

emission rates for the 30 successive boiler operating days.

(3) Compliance with applicable daily average PM emission limitations is determined by calculating the arithmetic average of all hourly emission rates for PM each boiler operating day, except for data obtained during startup, shutdown, and malfunction. Averages are not calculated for boiler operating days with less than 18 hours of valid data. Instead, the valid hourly emission rates are averaged with the immediately following boiler operating day emission rates to determine compliance.

(h) If an owner or operator has not obtained the minimum quantity of emission data as required under § 60.49Da of this subpart, compliance of the affected facility with the emission requirements under §§ 60.43Da and 60.44Da of this subpart for the day on which the 30-day period ends may be determined by the Administrator by following the applicable procedures in section 7 of Method 19 of appendix A of this part.

(i)

Compliance provisions for sources subject to § 60.44Da(d)(1), (e)(1), (e)(2)(i), (e)(3)(i), or (f).

The owner or operator of an affected facility subject to § 60.44D

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