CO emissions from major electric generating facilities.
Purpose:
To promulgate regulations targeting reductions in emissions of CO from major electric generating facilities.
Text of final rule:
(Existing Sections 200.1 through 200.8 remain unchanged.)
Existing Section 200.9, Table 1 is amended to add the following:
Regulation
CFR Cite
Availability
251.5(a)
40 CFR part 75 (July 1, 2008)
*
40 CFR part 60 (July 1, 2007)
*
251.5(b)(1)
40 CFR part 60 Appendix B Performance
*
Specification 3(July 1, 2007), pages 646-647
40 CFR 75.13(July 1, 2008), page 220
*
40 CFR 75.71(July 1, 2008), pages 326-328
*
40 CFR 75.72(July 1, 2008), pages 328-331
*
appendix G of 40 CFR part 75(July 1, 2008),
*
pages 455-457
251.5(b)(2)
40 CFR part 60 (July 1, 2007)
*
40 CFR part 75(July 1, 2008)
*
251.5(c)
40 CFR part 60 Appendix B Performance
*
Specification 3(July 1, 2007), pages 646-647
appendix D of 40 CFR part 75(July 1, 2008),
*
pages 409-438
appendix E of 40 CFR part 75(July 1, 2008),
*
pages 438-443
251.5(d)(1)
40 CFR part 60 (July 1, 2007)
*
40 CFR part 75(July 1, 2008)
*
40 CFR part 60 Appendix B Performance
*
Specification 3(July 1, 2007), pages 646-647
subpart D of 40 CFR part 75(July 1, 2008),
*
pages 262-279
appendix D of 40 CFR part 75(July 1, 2008),
*
pages 409-438
appendix E of 40 CFR part 75(July 1, 2008),
*
pages 438-443
251.5(d)(2)
40 CFR part 60 (July 1, 2007)
*
40 CFR part 75(July 1, 2008)
*
251.6(a)
40 CFR part 60 (July 1, 2007)
*
40 CFR 75.73(July 1, 2008),
*
pages 331-335
*
251.6(b)
40 CFR part 60 (July 1, 2007)
*
40 CFR 75.62(July 1, 2008),
*
page 317
*
251.6(c)
40 CFR part 60 (July 1, 2007)
*
40 CFR 75.63(July 1, 2008), pages 317-318
*
40 CFR 75.73(c) (July 1, 2008), page 332
*
40 CFR 75.73(e) (July 1, 2008), page 333
*
251.6(e)(2)
40 CFR part 60 (July 1, 2007)
*
subpart H of 40 CFR part 75(July 1, 2008),
*
pages 323-344
40 CFR 75.64(July 1, 2008), pages 318-320
*
subpart G of 40 CFR part 75(July 1, 2008),
*
pages 313-323
251.6(f)
40 CFR part 60 (July 1, 2007)
*
40 CFR part 75(July 1, 2008)
*
(Existing Section 200.10 through Section 200.16 remains unchanged.)
6 NYCRR Part 251, CO Performance Standards for Major Electric Generating Facilities
Section 251.1 Definitions.
(a) For the purpose of this Part, the general definitions of Parts 200 and 201 of this Title apply.
(b) For the purposes of this Part, the following definitions also apply:
(1) 'Electric generating facility'. A facility which sells its power to the electrical grid and that utilizes boilers, combustion turbines, waste to energy sources, and/or stationary internal combustion engines to produce electricity.
(2) 'Gasifier'. An emission source that converts a hydrocarbon feedstock into a fuel.
(3) 'Major electric generating facility'. An electric generating facility with a generating capacity of at least 25 megawatts (MW).
Section 251.2 Applicability.
(a) 'New Sources'. The provisions of this Part apply to owners or operators of new major electric generating facilities that commence construction after the effective date of this Part.
(b) 'Existing Sources'. The provisions of this Part apply to owners or operators of existing electric generating facilities that commence construction for an increase in capacity of at least 25 MW at the facility after the effective date of this Part. Only those emission source(s) involved in the increase in capacity at the electric generating facility shall be subject to the emission limits established in Section 251.3 of this Part.
Section 251.3 Emission limits. Facilities subject to this Part must comply with the applicable carbon dioxide (CO) emission limit established in this Section. These emission limits are measured on a 12-month rolling average basis, calculated by dividing the annual total of CO emissions over the relevant 12-month period by either the annual total (gross) MW generated (output-based limit) or the annual Btu input (input-based limit) over the same 12-month period.
(a) Owners or operators of a source of one of the following types, except for those emission sources directly attached to a gasifier, are required to meet an emission rate of 925 pounds of CO per MW hour gross electrical output (output-based limit) or 120 pounds of CO per million Btu of input (input-based limit):
(1) boilers that are permitted to fire greater than 70 percent fossil fuel;
(2) combined cycle combustion turbines; or
(3) stationary internal combustion engines that fire only gaseous fuel.
(b) Owners or operators of a source of one of the following types, except for those emission sources directly attached to a gasifier, are required to meet an emission rate of 1450 pounds of CO per MW hour gross electrical output (output-based limit) or 160 pounds of CO per million Btu of input (input-based limit):
(1) simple cycle combustion turbines; or
(2) stationary internal combustion engines that fire either liquid fuel or liquid and gaseous fuel simultaneously.
(c) Owners or operators of any other emission source that is not subject to a specific CO emission limit in Subdivision (a) or (b) of this Section are required to propose and meet a case-specific emission limit for CO. This proposal must be based on an analysis of existing control technologies and operating efficiencies of existing sources, and other appropriate considerations relevant to the source's CO emission profile. The proposed emission limit must achieve the maximum degree of CO emission reduction for new sources, and shall not be less stringent than the CO emission control or operating efficiency that is achieved in practice by the best controlled similar source(s). The proposal must be submitted to the department for review and approval. In no case will the department approve a proposal in which greater than 50 percent of the heat input is derived from solid fossil fuel or oil, unless the CO emission rate associated with that input meets the CO emission limit in Subdivision (a) of this Section. For purposes of this Subdivision, emission sources that are directly attached to a gasifier must include the CO emissions from the gasifier in the case-specific CO emission limit.
Section 251.4 Permit requirements. An owner or operator of a facility subject to this Part must submit an application for a permit or permit modification, as appropriate, pursuant to Part 201 of the Title. As part of the application, an owner or operator of a facility subject to a specific CO emission limit in Subdivision 251.3(a) or (b) of this Part must specify which form of CO emission limit the owner or operator will comply with in the permit, either the output-based limit or the input-based limit.
Section 251.5 Monitoring.
(a) 'General requirements'. The owner or operator of an emission source subject to this Part shall comply with the requirements of this Section. The owner or operator of an emission source subject to this Part shall also comply with any applicable monitoring, recordkeeping, and reporting requirements as provided in all applicable sections of 40 CFR part 75, unless the emission source is not otherwise required to meet the monitoring, recordkeeping, and reporting requirements of 40 CFR part 75 by any other applicable State or federal regulation, in which case the owner or operator may instead comply with any applicable monitoring, recordkeeping, and reporting requirements as provided in all applicable sections of 40 CFR part 60.
(b) 'Initial installation and certification procedures'. The owner or operator of each emission source subject to this Part must meet the following requirements.
(1) Install all CEMS required under this Part for monitoring CO mass emissions and heat input. This includes all CEMS required to monitor CO concentration, stack gas flow rate, O2 concentration, heat input, and fuel flow rate, as applicable, in accordance with either 40 CFR part 60 Appendix B Performance Specification 3 or 40 CFR 75.13, 75.71, and 75.72, and all portions of appendix G of 40 CFR part 75, except for equation G-1 in 40 CFR part 75.
(2) Successfully complete all certification tests required under subdivision (c) of this section and meet all other requirements of this Part and either 40 CFR part 60 or 40 CFR part 75 as applicable to the CEMS under Paragraph(1) of this Subdivision.
(3) Record, report and quality-assure the data from the CEMS under Paragraph (1) of this Subdivision.
(c) 'Initial certification and recertification procedures'. The owner or operator of an emission source subject to this Part shall comply with the initial certification and recertification procedures for a CEMS and an alternative monitoring system under either 40 CFR part 60 Appendix B Performance Specification 3 or appendices D and E of 40 CFR part 75.
(d) 'Out-of-control periods'.
(1) Whenever any CEMS fails to meet the quality assurance and quality control requirements or data validation requirements of either 40 CFR part 60 or 40 CFR part 75, data shall be substituted using the applicable procedures in either 40 CFR part 60 Appendix B Performance Specification 3 or subpart D, appendix D, or appendix E of 40 CFR part 75.
(2) Whenever both an audit of a CEMS and a review of the initial certification or recertification application reveal that any CEMS should not have been certified or recertified because it did not meet a particular performance specification or other requirement under Subdivision (c) of this Section or the applicable provisions of either 40 CFR part 60 or 40 CFR part 75, both at the time of the initial certification or recertification application submission and at the time of the audit, the Department will issue a notice of disapproval of the certification status of such CEMS. For the purposes of this paragraph, an audit shall be either a field audit or an audit of any information submitted to the Department or the administrator. By issuing the notice of disapproval, the Department revokes prospectively the certification status of the CEMS. The data measured and recorded by the CEMS shall not be considered valid quality-assured data from the date of issuance of the notification of the revoked certification status until the date and time that the owner or operator completes subsequently approved initial certification or recertification for the CEMS. The owner or operator shall follow the initial certification or recertification procedures in Subdivision (c) of this Section for each disapproved CEMS.
Section 251.6 Recordkeeping and reporting.
(a) 'General provisions'. The owner or operator shall comply with all recordkeeping and reporting requirements in this Section. The owner or operator shall also comply with applicable record keeping and reporting requirements under 40 CFR 75.73, unless the emission source is not otherwise required to meet the recordkeeping and reporting requirements of 40 CFR part 75 by any other applicable State or federal regulation, in which case the owner or operator may instead comply with applicable recordkeeping and reporting requirements under 40 CFR part 60. Each submission required under this Part shall be submitted, signed, and certified by the responsible official. Each such submission shall include the following certification statement by the responsible official: "I am authorized to make this submission on behalf of the owners and operators of the emission source or emission sources for which the submission is made. I certify under penalty of law that I have personally examined, and am familiar with the statements and information submitted in this document and all its attachments. Based on my inquiry of those individuals with primary responsibility for obtaining the information, I certify that the statements and information are to the best of my knowledge and belief true, accurate, and complete. I am aware that there are significant penalties for submitting false statements and information or omitting required statements and information, including the possibility of fine or imprisonment."
(b) 'Monitoring plans'. The owner or operator of an emission source subject to this Part shall comply with requirements of either 40 CFR part 60 or 40 CFR 75.62.
(c) 'Certification reports'. The owner or operator shall submit certification reports to the Department within 45 days after completing all initial certification or recertification tests required under Subdivision 251.5(c) of this Part including the information required under either 40 CFR part 60 or 40 CFR 75.63 and 40 CFR 75.73 (c) and (e).
(d) 'Vendor certified fuel receipts'. The owner or operator that utilizes vendor certified fuel receipts to monitor the Btu content of a fuel must maintain these receipts in a bound log book.
(e) 'Semi-annual reports'. The owner or operator shall submit Semi-annual reports, as follows:
(1) The owner or operator shall report the CO mass emissions data and heat input data in a format appropriate for comparison to the emission limitation applicable to the emission source, unless otherwise prescribed by the Department for each calendar quarter beginning with the calendar quarter corresponding to, the earlier of the date of provisional certification or the applicable deadline for initial certification under Section 251.5 of this Part.
(2) The owner or operator shall submit each quarterly report to the Department within 30 days following the end of the calendar quarter covered by the report. Quarterly reports shall be submitted in the manner specified in either 40 CFR part 60 or subpart H of 40 CFR part 75 and 40 CFR 75.64. Quarterly reports shall include all of the data and information required in either 40 CFR part 60 or subpart H of 40 CFR part 75 for each emission source (or group of emission sources using a common stack) as well as information required in subpart G of 40 CFR part 75, except for opacity and SO provisions.
(f) 'Compliance certification'. The owner or operator shall submit to the Department a compliance certification in support of each quarterly report based on reasonable inquiry of those persons with primary responsibility for ensuring that all of the emission source's emissions are correctly and fully monitored. The certification shall state that the monitoring data submitted were recorded in accordance with the applicable requirements of this Part and either 40 CFR part 60 or 40 CFR part 75, including the quality assurance procedures and specifications.
(g) 'Data retention'. The owner or operator of a source subject to this Part must maintain copies of all records, either on-site at the facility that contains the subject source or at another location acceptable to the Department, for a minimum of five years.
Section 251.7 Severability. Each provision of this Part shall be deemed severable, and in the event that any provision of this Part is held to be invalid, the remainder of this Part shall continue in full force and effect.
Final rule as compared with last published rule:
Nonsubstantive changes were made in sections 200.9, 251.5 and 251.6.
Text of rule and any required statements and analyses may be obtained from:
Michael Jennings, NYSDEC, Division of Air Resources, 625 Broadway, Albany, NY 12233-3254, (518) 402-8403, email: airregs@gw.dec.state.ny.us
Additional matter required by statute:
Pursuant to Article 8 of the State Environmental Quality Review Act, a Short Environmental Assessment Form, a Negative Declaration and a Coastal Assessment Form have been prepared and are on file.
Revised Regulatory Impact Statement, Regulatory Flexibility Analysis, Rural Area Flexibility Analysis and Job Impact Statement
No changes were made to previously published RIS, RFA, RAFA and JIS.
Assessment of Public Comment
The New York State Department of Environmental Conservation (Department) is adopting 6 NYCRR Part 251, CO Performance Standards for Major Electric Generating Facilities, and revisions to 6 NYCRR Part 200, General Provisions (collectively "Part 251"). The Department proposed Part 251 on January 18, 2012. Public hearings were held in Albany on March 5, 2012, in New York City on March 6, 2012, and in Buffalo on March 8, 2012. The public comment period closed at 5:00 P.M. on March 15, 2012. The Department received written and oral comments from 17 commenters, all of which have been reviewed, summarized, and responded to by the Department.
Overall, comments received by the Department expressed support for the Department's proposal, or else commented on specific provisions of Part 251. Two commenters specifically objected to the Department's proposed adoption of Part 251, largely on the basis of the argument that Part 251 could actually increase net greenhouse gas (GHG) emissions or reduce fuel diversity and system reliability and therefore would be counter to the stated objectives of the regulation.
The most common comments focused on the level of the standard under subdivision 251.3(a). Some commenters, particularly those representing environmental advocacy organizations, suggested that the Department should include a lower carbon dioxide (CO) emission standard, such as an 800 lbs/MWhr output-based standard, rather than 925 lbs/MWhr. These commenters suggested that the most efficient new natural gas-fired combined cycle plants may be able to achieve a CO emission rate of 774 lbs/MWhr. This was based largely on recent best available control technology (BACT) determinations.
In recommending a lower CO emission rate under subdivision 251.3(a), commenters also suggested that the Department not provide for the possibility of backup oil burn, particularly in locations that may not have minimum oil burn requirements. These commenters suggested that allowing facilities the ability to utilize oil as a backup fuel for up to 45 days is unnecessary, at least in certain locations within the State. Some comments suggested, as an alternative, different standards for different locations within the States, based on whether or not such locations are subject to minimum oil burn requirements.
The Department responded to these comments by explaining that the CO emission limit under 251.3(a) was set at a level to provide for appropriate technical, operational, and reliability-based flexibility for regulated entities. This includes not only any minimum oil burn requirements, but also other factors such as potentially frequent periods of start-up and shutdown operations. Moreover, the Department responded that Part 251 will establish a Statewide standard, rather than a "regionalized" standard that is different based on the location of the facility within the State. Finally, while new natural gas-fired combined cycle plants may be able to meet a 774 lbs/MWhr CO in certain locations and under certain configurations, because Part 251 is a performance standard that establishes a threshold emission limit that every subject facility must meet, the Department does not believe it is appropriate to set the standard at a level that does not provide for appropriate flexibility.
Other commenters, including those representing electric generation companies that would be subject to Part 251, suggested a higher standard such as a 960 lbs/MWhr output-based standard for those sources subject under subdivision 251.3(a). These commenters recommended a higher standard in order to preserve fuel diversity and the reliability driven ability to operate on oil and to account for some degradation of the systems over time. Moreover, comments suggested that Part 251 should include a higher standard in order to account for potentially frequent cycling modes of operation and frequent periods of startup and shut-down that may lead to increased emissions and make it difficult for facilities to meet the
In responding to these comments that the Department should raise the CO emission limit under subdivision 251.3(a), the Department noted that the 925 lbs/MWhr output-based standard already takes into account appropriate technical, operational, and reliability-based considerations. This includes the ability to fire oil as a backup fuel for up to 45 days. Moreover, additional provisions of Part 251 provide additional flexibility for regulated entities to be able to meet the relevant emission limit. Such provisions include the use of a 12 month rolling average to measure compliance with the relevant emission limit, which the Department believes helps to address issues that may arise from frequent periods of cycling or startup and shut-down, and the ability to choose between compliance based on an input-based or output-based standard.
Some comments addressed the level of the CO emission limit under subdivision 251.3(b), which establishes an output-based limit of 1450 lbs/MWhr for simple cycle combustion turbines. One commenter noted that the most efficient new natural gas-fired simple cycle combustion turbines may meet CO emission rates of 1,075 lbs/MWhr, and commenters suggested lowering the standard under subdivision 251.3(b) to 1,100 or 1,200 lbs/MWhr.
The Department responded that the emission rates cited by the commenter are focused on natural gas-fired simple cycle combustion turbines, while simple cycle combustion turbines in New York may be located in areas with limited or no natural gas availability. Therefore, the Department set the standard applicable to simple cycle combustion turbines at a level to allow for oil burning 85 to 100 percent of the time.
Several commenters suggested that waste-to-energy (WTE) plants should be exempt from regulation under Part 251. These commenters focused on the WTE's supposed ability to mitigate GHG emissions on a lifecycle basis. As an alternative, these commenters suggested that WTE plants should be subject to a separate case-specific CO emission standard.
In response, the Department reiterated that, pursuant to the statutory language under Environmental Conservation Law (ECL) Section 19-0312, the Department does not have the ability to specifically exempt WTE facilities from regulation. Part 251 is consistent with the statutory requirements of ECL Section 19-0312, the Power NY Act, and Article 10 of the Public Service Law (Article 10). The Department recognizes, however, that WTE facilities are different from traditional fossil fuel-fired power plants. Therefore, the Department included subdivision 251.3(c), which provides that other facilities that are not subject to a specific CO emission limit under subdivisions 251.3(a) or (b) are instead subject to a case-specific CO emission limit to be approved by the Department. This includes applicable WTE facilities, which will be subject to the case-specific standard under subdivision 251.3(c).
Likewise, many commenters made the same suggestion for sustainably-sourced biomass facilities. These commenters felt that such facilities should not be subject to Part 251, for the same reasons that these commenters felt WTE facilities should be exempt from Part 251.
The Department responded that, just like WTE facilities, the Department does not have the ability to exempt sustainably-sourced biomass facilities from Part 251 under the statutory language. However, just like WTE facilities, biomass-fired facilities not subject to a specific CO emission limit under subdivision 251.3(a) or (b) are subject to a case-specific CO emission standard under subdivision 251.3(c).
Many commenters focused on specific aspects of the case-by-case consideration under subdivision 251.3(c). For example, commenters suggested that the case-specific analysis should include consideration of lifecycle assessments of the relevant feedstock(s), including potential avoided emissions. Commenters also suggested that the case-specific analysis should consider factors such as efficiency.
In response, the Department stated that it will review all factors involved in a project. In approving the case-by-case emission limit, the Department may consider other appropriate factors relevant to determining the overall carbon intensity of the proposed facility. These factors may include, but are not limited to, lifecycle analyses, avoided emissions, efficiencies, and any other factor specific to a proposed project.
Many commenters also stressed that the Department should not assume that biomass is carbon neutral, and that different types of biomass may have different carbon intensities.
The Department responded that it does not assume that all biomass is carbon neutral, and that it agrees that different types of biomass may have difference carbon intensities. These considerations may be a part of any case-specific determination under subdivision 251.3(c).
Other commenters requested that, in the context of establishing a case-specific emission limit under subdivision 251.3(c), the Department should include provisions in Part 251 providing for public notice and comment.
The Department responded that permitting requirements for any facility subject to Part 251, including provisions providing for public notice and comment, are found in existing provisions of 6 NYCRR Parts 201 and 621. Also, facilities that are subject to Part 251 are subject to the requirements of Article 10, including implementing regulations under Article 10. Public notice and participation is already required by all of these regulations.
One commenter suggested that existing provisions are insufficient to deal with significant emergencies such as a catastrophic loss of natural gas to New York. This commenter noted that the use of natural gas as a fuel for electricity generation in New York is growing. The commenter therefore suggested that protocols and compliance options be developed, in order to allow such units to understand in advance that, should such a significant emergency situation occur, they could continue to operate without fear of penalty for violating Part 251.
The Department responded that the Department appreciates the importance of fuel diversity and ensuring continued reliability. The emission standard in subdivision 251.3(a) takes into account reliability considerations, including by providing for up to 45 days of backup oil firing at dual fuel units. Part 251 also provides for a separate standard under subdivision 251.3(b) that allows for a simple cycle combustion turbine to operate 85 to 100 percent of its operating time on oil. The Department also responded that it recognizes that an emergency situation may arise within the meaning of 6 NYCRR 201-2.1(b)(12), which could provide for an affirmative defense under Part 201 when dealing with significant emergencies like the catastrophic loss of natural gas throughout New York State. Finally, although the Department believes that Part 251 and other existing provisions are sufficient to address emergencies, the Department appreciates the opportunity to work further to address these issues, and will continue to interact with stakeholders to research other potential compliance options.
Some commenters suggested that the Department should provide for periodic revisions and updates to the CO performance standards. These commenters noted that technologies change over time and that the standards should reflect technological advances that may be made in the future.
In response, the Department stated that no regulations are required in order to provide the Department with the ability to update the standards in the future based on technological advancements. The Department already has the ability to revise, at any time, the CO emission standards in Part 251, pursuant to a subsequent rulemaking process under the State Administrative Procedure Act (SAPA). The Department may consider periodically updating the requirements of Part 251 through such subsequent rulemakings.
Some comments questioned the applicability and stringency of Part 251, as compared to the applicability of federal regulations. For example, comments noted that the Part 251 applicability thresholds are different than those set forth by the U.S. Environmental Protection Agency (EPA) under the Prevention of Significant Deterioration (PSD) Greenhouse Gas Tailoring Rule. Moreover, comments noted that Part 251 is more stringent than existing federal standards.
The Department responded that the applicability of Part 251 is consistent with the applicability required under ECL Section 19-0312, the Power NY Act, and Article 10. A facility may be subject to any combination of Part 251, GHG BACT requirements pursuant to PSD pre-construction permitting requirements, and potentially in the future, CO new source performance standards (NSPS). Moreover, the Department recognizes that Part 251 contains CO emission standards that are more stringent than those imposed under the federal Clean Air Act, and that Part 251 contains a limit that is more stringent than that contained in the CO NSPS recently proposed by EPA.
One commenter urged the Department to not adopt Part 251, because it could be inconsistent with the stated goal of reducing GHG emissions and cause a net increase in GHG emissions. This commenter suggested that, when making a lifecycle comparison of coal and natural gas, recent studies and literature suggest that substituting natural gas for coal-fired generation may not be a wise strategy for addressing climate change.
The Department responded that Part 251 will serve to prevent new high-carbon sources of energy in the State. The Department disagrees that Part 251 could cause a net increase in GHG emissions. Recent studies and analyses conclude that, even when using a lifecycle comparison, electricity generation from natural gas generally has less GHG emissions than coal-fired electric generation.
Finally, some commenters focused on the monitoring, recordkeeping, and reporting requirements under Part 251. In particular, these commenters noted that certain facilities, most notably WTE facilities, may not be subject to requirements under 40 CFR part 75. As a result, these commenters suggested that the monitoring, recordkeeping, and reporting requirements should be clarified in order to allow for certain facilities to comply with the requirements of 40 CFR part 60 rather than 40 CFR part 75.
The Department responded that it recognizes that not all facilities subject to Part 251 are otherwise required to meet the monitoring, recordkeeping, and reporting requirements of 40 CFR Part 75. Therefore, the Department has clarified the language in the monitoring, recordkeeping, and reporting requirements under Sections 251.5 and 251.6, in order to provide certain types of facilities the ability to choose between using 40 CFR Part 60 or 40 CFR Part 75 monitoring, recordkeeping, and reporting requirements.
