ENV-03-12-00009-P CO Emissions from Major Electric Generating Facilities

1/18/12 N.Y. St. Reg. ENV-03-12-00009-P

NEW YORK STATE REGISTER

VOLUME XXXIV, ISSUE 3

January 18, 2012

RULE MAKING ACTIVITIES

DEPARTMENT OF ENVIRONMENTAL CONSERVATION

PROPOSED RULE MAKING

HEARING(S) SCHEDULED

I.D No. ENV-03-12-00009-P

CO Emissions from Major Electric Generating Facilities

PURSUANT TO THE PROVISIONS OF THE State Administrative Procedure Act, NOTICE is hereby given of the following proposed rule:

Proposed Action:

Amendment of Part 200; and addition of Part 251 to Title 6 NYCRR.

Statutory authority:

Environmental Conservation Law, sections 1-0101, 1-0303, 3-0301, 19-0103, 19-0105, 19-0107, 19-0301, 19-0303, 19-0305 and 19-0312; and Energy Section Law, sections 3-101 and 3-103

Subject:

CO emissions from major electric generating facilities.

Purpose:

To promulgate regulations targeting reductions in emissions of CO from major electric generating facilities.

Public hearing(s) will be held at:

3:00 p.m., March 5, 2012 at Department of Environmental Conservation, 625 Broadway, Public Assembly Rm. 129, Albany, NY; 3:00 p.m., March 6, 2012 at Department of Public Service, 90 Church St., 4th Fl., New York, NY; 3:00 p.m., March 8, 2012 at Department of Environmental Conservation, Region 9 Hearing Rm., 270 Michigan Ave., Buffalo, NY.

Interpreter Service:

Interpreter services will be made available to hearing impaired persons, at no charge, upon written request submitted within reasonable time prior to the scheduled public hearing. The written request must be addressed to the agency representative designated in the paragraph below.

Accessibility:

All public hearings have been scheduled at places reasonably accessible to persons with a mobility impairment.

Text of proposed 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, 2007)	*
251.5(b)(1)	40 CFR 75.13(July 1, 2007), page 220	*
	40 CFR 75.71(July 1, 2007), pages 326-328	*
	40 CFR 75.72(July 1, 2007), pages 328-331	*
	appendix G of 40 CFR part 75(July 1, 2007), pages 455-457	*
251.5(b)(2)	40 CFR part 75(July 1, 2007)	*
251.5(c)	appendix D of 40 CFR part 75(July 1, 2007), pages 409-438	*
	appendix E of 40 CFR part 75(July 1, 2007), pages 438-443	*
251.5(d)(1)	40 CFR part 75(July 1, 2007)	*
	subpart D of 40 CFR part 75(July 1, 2007), pages 262-279	*
	appendix D of 40 CFR part 75(July 1, 2007) , pages 409-438	*
	appendix E of 40 CFR part 75(July 1, 2007) , pages 438-443	*
251.5(d)(2)	40 CFR part 75(July 1, 2007)	*
251.6(a)	40 CFR 75.73(July 1, 2007), pages 331-335	*
251.6(b)	40 CFR 75.62(July 1, 2007), page 317	*
251.6(c)	40 CFR 75.63(July 1, 2007), pages 317-318	*
	40 CFR 75.73(c) (July 1, 2007), page 332	*
	40 CFR 75.73(e) (July 1, 2007), page 333	*
251.6(e)(2)	subpart H of 40 CFR part 75(July 1, 2007), pages 323-344	*
	40 CFR 75.64(July 1, 2007), pages 318-320	*
	subpart G of 40 CFR part 75(July 1, 2007), pages 313-323	*
251.6(f)	40 CFR part 75(July 1, 2007)	*

(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 any applicable monitoring, recordkeeping, and reporting requirements as provided in this Section and all applicable sections of 40 CFR part 75.

(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 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 40 CFR part 75 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 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 40 CFR part 75, data shall be substituted using the applicable procedures in 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 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 and any applicable recordkeeping and reporting requirements under 40 CFR 75.73. 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 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 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 subpart H of 40 CFR part 75 and 40 CFR 75.64. Quarterly reports shall include all of the data and information required in 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 SO2 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 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.

Text of proposed 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: 251GHG@gw.dec.state.ny.us

Data, views or arguments may be submitted to:

Same as above.

Public comment will be received until:

March 15, 2012.

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. This rule must be approved by the Environmental Board.

Summary of Regulatory Impact Statement

INTRODUCTION

The Legislature recently passed the "Power NY Act" (A.8510/S.5844), which includes the reauthorization of a revised Public Service Law (PSL) Article X (Article X), regarding the siting of power plants. Governor Cuomo signed the Power NY Act into law on August 4, 2011 (chapter 388, laws of 2011). The legislation also adds a new Section 19-0312 to the Environmental Conservation Law (ECL), which includes a requirement for the Department of Environmental Conservation (Department) to promulgate regulations targeting reductions in emissions of carbon dioxide (CO) from major electric generating facilities (defined as facilities that have a nameplate capacity of at least 25 megawatts (MW)). This regulation must be promulgated by the Department within one year of the statute's effective date, meaning by August 4, 2012, pursuant to the statutory text. Moreover, the availability to applicants of the process for siting power plants under Article X is partially dependent on the promulgation of this regulation by the Department. See PSL sections 161(1) and 162(1) and (4)(d).

Therefore, the Department is proposing to adopt a new 6 NYCRR Part 251, CO Performance Standards for Major Electric Generating Facilities and revisions to 6 NYCRR Part 200, General Provisions. The revisions to Part 200 incorporate references to federal rules. This is not a mandate on local governments. It applies equally to any entity that proposes to construct a new major electric generating facility or to expand an existing electric generating facility by increasing its electrical output capacity by at least 25 MW. Part 251 does not mandate any particular project or activity by any local government.

STATUTORY AUTHORITY

The statutory authority to promulgate Part 251 is found primarily in ECL Section 19-0312. This section not only provides statutory authority for Part 251; ECL Section 19-0312 also explicitly requires the Department to promulgate a regulation, by August 4, 2012, targeting reductions in emissions of CO from major electric generating facilities. The promulgation of Part 251 by the Department will therefore serve to fulfill this statutory requirement. The statutory authority to promulgate Part 251 also derives from the Department's obligation to prevent and control air pollution, as set out in the ECL at Sections 1-0101, 1-0303, 3-0301, 19-0103, 19-0105, 19-0107, 19-0301, 19-0303, and 19-0305.

LEGISLATIVE OBJECTIVES

The Power NY Act included the reauthorization of a revised Article X, providing a process for the siting of major electric generating facilities. Pursuant to Article X, a Certificate of Environmental Compatibility and Public Need (Certificate) is required from the New York State Board on Electric Generating Siting and the Environment (Board) prior to commencing construction of a new major electric generating facility, or increasing the capacity of an existing electric generating facility by more than 25 MW. The requirements and process for obtaining a Certificate from the Board are generally set forth in Article X, as well as in regulations to be promulgated by the Department of Public Service (DPS). Moreover, as a component of the Power NY Act, the Department is also responsible for promulgating regulations regarding the analyzing of environmental justice issues, which is being done through the promulgation of a new 6 NYCRR Part 487.

This rulemaking implements the CO performance standard component of the overall process contemplated in the Power NY Act for the siting of major electric generating facilities. In addition to having to obtain a Certificate from the Board under Article X in order to commence construction, new major electric generating facilities (and increases in capacity of at least 25 MW at existing electric generating facilities) will also need to demonstrate compliance with Part 251 and obtain a permit from the Department that incorporates Part 251's requirements prior to commencing construction. Part 251 will serve to prevent the construction of new high-carbon sources of energy, including new coal-fired facilities that do not utilize carbon capture and sequestration (CCS) or some other advanced CO emission reduction technology, working in conjunction with other State programs such as the Regional Greenhouse Gas Initiative (RGGI), in order to minimize CO emissions from the power sector in the State.

With numerous legislative enactments, the Legislature has directed and empowered the Department to promote the safety, health and welfare of the public, and protect the State's natural environment. There is strong scientific evidence that the earth's climate is changing and that greenhouse gases (GHGs) from fossil fuel combustion and other human activities are the major contributor to this change. Climate change represents an enormous environmental challenge for the State because, unabated, it will have serious adverse impacts on the State's natural resources, public health and infrastructure.

Among the GHGs, CO is the chief contributor to climate change. Emission sources that fire carbon-containing material, such as fossil fuel, emit significant quantities of CO. Electricity generation is responsible for approximately 19 percent of all GHGs emitted in New York State. In 2010, electric generating units in the State subject to RGGI emitted approximately 42 million tons of CO into the atmosphere. In December 2009, the U.S. Environmental Protection Agency (EPA) issued findings concluding that current and projected concentrations of GHGs in the atmosphere endanger the public health and welfare of current and future generations.¹ Article 19 of the ECL requires the Department promulgate regulations targeting reductions in emissions of CO, a GHG, from major electric generating facilities.

NEEDS AND BENEFITS

As noted, Article 19 of the ECL requires the Department to promulgate regulations targeting reductions in emissions of CO from major electric generating facilities, in order to reduce GHG emissions in New York State. This regulation targets an easily achievable, first-tier target for GHG emission reduction by establishing CO emission standards for new major electric generating facilities, and applicable expansions at existing electric generating facilities.

Stakeholder Outreach

The Department held a stakeholder meeting on October 20, 2011 to discuss the likely elements of the proposed Part 251 and to obtain feedback. The stakeholder group consisted of the regulated community (electric generating facility representatives) to be affected by the proposed regulation, consultants (both technical and legal), and interested environmental advocate groups. The Department also conducted additional informal stakeholder outreach throughout October and November 2011 in order to obtain input used in the development of Part 251.

CO Emission Standards and Requirements

The proposed regulation will establish CO emission standards for all new major electric generating facilities, and for increases in capacity of at least 25 MW at existing electric generating facilities. Except for emission sources directly attached to a gasifier, owners or operators of boilers that fire a minimum of 70 percent fossil fuel, combined cycle combustion turbines, or stationary internal combustion engines that fire only gaseous fuel are required to meet a limit of either 925 pounds of CO per MW hour (lbs/MW-hr) gross electrical output (output-based limit) or 120 pounds per million British thermal unit of input (lbs/mmBtu - input-based limit). Except for emission sources directly attached to a gasifier, owners or operators simple cycle combustion turbines, or stationary internal combustion engines that fire either liquid fuel or liquid and gaseous fuel simultaneously, are required to meet a CO emission limit of either 1450 lbs/MW-hr (output-based limit) or 160 lbs/mmBtu (input-based limit). As part of an application for a permit or permit modification, an owner or operator will choose whether to include the relevant output- or input-based limit in the permit for purposes of compliance. Owners or operators of any other source that is not subject to one of the specific CO emission limits described above, including emission sources directly attached to a gasifier, are required to propose a case-specific emission limit for CO. This proposal will be submitted to the Department for review and approval. This includes, for example, biomass-fired facilities and waste-to-energy (WTE) facilities.

COSTS

Potential Impacts on Electricity Prices and Reliability

The cost of electricity should not increase substantially as a direct result of this proposed regulation. New, large-scale, coal- or oil-fired electric generation facilities are not expected to be constructed in New York, regardless of whether or not the Department ultimately adopts Part 251. If, however, a new coal-fired unit is proposed, it would have to apply 50 to 60 percent CCS or other carbon control technology in order to comply with the CO emission limits in Part 251. The required application of CCS technology would create a significant increase in capital and operation costs when compared to a base coal plant without CCS technology.

This proposed rulemaking will necessitate that additional energy demand be met with less carbon- intensive fuels, such as natural gas, or by renewable energy such as wind power. The bulk of new fossil fuel-fired generation has been and is expected to be gas-fired, combined-cycle units, even absent Part 251. New York State programs to increase the use of renewable energy and decrease energy demand may reduce projected demand for natural gas, and minimize the impact of any potential rise in the cost of fuel for an electric generating facility combusting natural gas. As new gas-fired combined cycle units replace less efficient existing natural gas-fired units, natural gas demand may also decrease.

Costs to the Regulated Community

The Department has determined that new combined cycle combustion turbines, new natural gas-fired boilers, new natural gas-fired stationary internal combustion engines, new oil-fired simple cycle combustion turbines, and new oil-fired stationary internal combustion engines can meet the proposed CO emission standards in Part 251. This is also true for increases in capacity of at least 25 MW at existing facilities that utilize the equipment and fuel listed above. For facilities that propose a project that utilizes the equipment and fuel listed above, the Department has calculated the increase in cost from this regulation to be zero.

New coal-fired and oil-fired boilers will not be able to meet the proposed CO emission standard without the installation of controls (such as CCS). Coal-fired boilers would need to install 50 to 60 percent CCS or otherwise reduce their CO emissions by 50 to 60 percent in order to meet the proposed CO emission standard. Oil-fired boilers would need to install 33 to 40 percent CCS or otherwise reduce their CO emissions by 33 to 40 percent in order to meet the proposed CO emission standard. Initial installation costs of CCS units on either coal- or oil-fired boilers will vary greatly, depending on the size of the system needed for capture and the distance the captured CO must be piped before sequestration. Depending on the CCS scenario, the initial project cost may increase as little as 10 percent up to 100 percent in the worst case scenario. The increase in cost to operations and maintenance of new coal-fired emission sources will be approximately 86 percent (56 dollars per MW-hr). This will project to be at least 50 million dollars per year increase in maintenance and operations costs for a 100 MW coal-fired boiler. It has been estimated that new oil-fired projects will have similarly associated cost increases. The Department also estimates that applicable increases in capacity at existing facilities that modify existing coal-fired or oil-fired boilers will incur similar costs for installation, maintenance, and operation of a retrofitted CCS system.

For other sources, the case-by-case analysis is based on an analysis of existing control technologies and operating efficiencies already installed or used in practice on existing emission 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 emission sources, and cannot be less stringent than the CO emission control or operating efficiency that is achieved in practice by the best controlled similar source(s). This requirement promotes the installation of the most modern and efficient equipment. Provided that a proposed project utilizes modern and efficient equipment, and proposes and meets a CO emission limit approved by the Department, the cost of this regulation will be zero.

Costs to the Department

The Department will not incur additional costs associated with the implementation of the proposed regulation and can properly administer the proposed regulation with the application of existing resources. Current Department staff will have to review permit applications and monitoring plans which will now include Part 251 requirements. The Department will use existing staff to execute and modify permits and inspect the subject sources, including the continuous emission monitors.

PAPERWORK

This rule will impose minimal additional paperwork for recordkeeping and monitoring to demonstrate compliance with 12-month rolling average CO emission standards. Facilities subject to this regulation are already required to meet emission standards for other air contaminants, for example, oxides of nitrogen, and thus have systems in place to monitor emissions of air contaminants and submit annual and semi-annual reports to the Department. Depending on the source, the facility owner may need to modify the data acquisition handling system software, in order to compute and report CO monitoring data in pounds per gross electric output rate in terms of megawatt/hr, or fuel input rate in terms of million Btu per hour. The records and reports will be required to be kept and submitted in the same formats used to track other pollutants with emission standards and will be submitted electronically accompanied by paper summary reports. Therefore, minimal additional costs for recordkeeping and reporting are projected.

LOCAL GOVERNMENT MANDATES

This is not a mandate on local governments. It applies equally to any entity that owns or operates a subject source. Local governments have no additional compliance obligations as compared to other subject entities. However, the promulgation of Part 251 may impact decision making by local governments which operate sources subject to the rule. Local governments which operate coal-fired electric generating units may not be able to undertake certain applicable expansion projects that would rely on additional coal-firing, until CCS is available, and instead may elect to replace an existing coal-fired unit with one designed to utilize a less carbon-intensive fuel. Parameters and items to be considered when designing a new facility (unit type and size, fuel type and supply, power needs, etc.) would be considered regardless of the existence of the proposed rule and therefore this rule does not impose additional requirements. With the commercial demonstration of CCS, even more options for power generation will become available to municipal governments.

DUPLICATION

Facilities subject to Part 251 will also be subject to the Part 242 (RGGI) requirements. Monitoring and recordkeeping requirements for Part 242 do not conflict with the requirements of this proposed regulation. Therefore, this proposed regulation does not duplicate any existing monitoring or recordkeeping requirements.

ALTERNATIVES

The following alternatives have been evaluated to address the goals of Part 251 as set forth above:

(1) Take no Action: The establishment in regulation of CO emission standards for major electric generating facilities is required by section 19-0312 of the ECL. Therefore, the "Take no action" alternative is not available to the Department under the statutory language, and has been rejected.

(2) Establish specific CO emission standards for each source and fuel type: The Department has determined that the establishment of CO emission standards for each source and fuel type would not promote or achieve the goal of reducing CO emissions from new major electric generating facilities as required by section 19-0312.3 of the ECL: "No later than 12 months after the effective date of this section, the commissioner shall promulgate rules and regulations targeting reductions in emissions of carbon dioxide that would apply to major electric generating facilities that commenced construction after the effective date of the regulations." Therefore, the "Establish specific CO emission standards for each source and fuel type" alternative has been rejected.

(3) Exempt sources that fire biomass or WTE facilities: This option was proposed by the Department at the October 20, 2011 stakeholder meeting. The stakeholders overwhelmingly rejected this alternative, suggesting that it could give an unfair competitive advantage to electric generating facilities that fire either biomass or waste over traditional fossil fuel-fired sources. The argument was also made that the carbon emissions from these sources were just as "detrimental" to the environment as carbon emissions from fossil fuel fired electric generating facilities. Therefore, the "Exempt sources that fire biomass or WTE facilities" alternative was rejected based on stakeholder comments.

FEDERAL STANDARDS

As result of several actions by EPA, GHGs, including CO, became "subject to regulation" under the Clean Air Act (Act) as of January 2, 2011. EPA modified the relevant applicability thresholds for GHGs for purposes of Prevention of Significant Deterioration (PSD) and Title V permitting under the Act in the GHG Tailoring Rule.² The Department has since incorporated these modified applicability thresholds for GHGs into its 6 NYCRR Parts 200, 201, and 231. Most notably, this means that new major stationary sources, and major modifications at existing stationary sources, are subject to best available control technology (BACT) requirements for GHGs under the PSD permitting program, provided that the source emits GHGs above the relevant applicability threshold. A source that, for PSD purposes, is a new major stationary source, or a major modification at an existing stationary source, may also be subject to Part 251. Generally speaking, a new natural gas-fired combined cycle facility that satisfies BACT for GHGs is likely to also comply with the emission limit in Part 251. There are currently no specific CO emission standards for stationary sources in the federal regulations. Therefore, the proposed Part 251 CO emission standards are more stringent than the current federal standards. However, EPA is committed, pursuant to a litigation settlement, to propose a new source performance standard (NSPS) for GHG emissions from power plants. If adopted, such a GHG NSPS would likely apply to sources of the type that will be subject to Part 251. The Department will continue to monitor the development of power plant GHG NSPS by EPA.

COMPLIANCE SCHEDULE

Part 251 will apply to the owner or operator of any new major electric generating facility that commences construction after the effective date of Part 251, and to any existing electric generating facility that commences construction for an increase in electrical output capacity by more than 25 MW after the effective date of Part 251. The Department intends to promulgate Part 251 by August 4, 2012, in accordance with ECL section 19-0312.

¹ Endangerment and Cause or Contribute Findings for Greenhouse Gases Under Section 202(a) of the Clean Air Act, 74 FR 66496, December 15, 2009.

² Prevention of Significant Deterioration and Title V Greenhouse Gas Tailoring Rule, 75 FR 31514, June 3, 2010.

Regulatory Flexibility Analysis

EFFECT OF RULE ON SMALL BUSINESSES AND LOCAL GOVERMENTS

There are currently three municipally owned major electric generating facilities in New York State. The Samuel A. Carlson Generating Station is owned by the Jamestown Board of Public Utilities (BPU). The BPU consists of four coal-fired stoker boilers and a natural gas-fired combustion turbine. The Village of Freeport owns and operates two natural gas-fired combustion turbines. Finally, Rockville Center owns and operates stationary internal combustion engines. None of these existing facilities will be subject to Part 251, unless and until such facilities propose to undertake a project that would increase capacity by at least 25 MW.

Currently, none of these facilities have a proposed project submitted to the Department for review. However, these facilities would become subject to Part 251 if they were to add new emission source(s) at the facility with at least 25 MW in electrical output capacity, or otherwise modify an existing emission source such that the facility's capacity is increased by at least 25 MW. If they undertake such a project, only the new or modified emission source(s) involved in the increase in capacity would be subject to the carbon dioxide (CO) emission limits of Part 251.

None of the existing facilities mentioned above are owned or operated by a small business. The Department does not expect that a small business will construct a new facility that would be subject to Part 251 in the future. Sources of applicable size and capacity are not generally constructed by small businesses, due to the significant capital costs necessary to construct such a facility.

COMPLIANCE REQUIREMENTS

This is not a mandate on local governments. Local governments have no additional compliance obligations as compared to other subject entities. Facilities subject to 6 NYCRR Part 251 will be required to meet a 12-month rolling average CO emission limit. This rule will impose minimal additional paperwork for recordkeeping and monitoring to demonstrate compliance with 12-month rolling average CO emission standards. Facilities subject to this regulation are already required to meet emission standards for other air contaminants, for example, oxides of nitrogen, and thus have systems in place to monitor emissions of air contaminants and submit annual and semi-annual reports to the Department. Depending on the source, the facility owner may need to modify the data acquisition handling system software, in order to compute and report CO monitoring data in pounds per gross electric output rate in terms of megawatt/hr, or fuel input rate in terms of million Btu per hour. Many facilities subject to Part 251 will also be subject to Part 242, and would already have to compute and report CO emissions data under Part 242. The additional paperwork for recordkeeping and reporting for this proposed rule will be minimal as data is submitted electronically accompanied by paper summary reports. The records and reports will be required to be kept and submitted in the same formats used to track other pollutants with emission standards. The additional requirements imposed by this rule are not expected to be unduly burdensome.

PROFESSIONAL SERVICES

Each electric generating facility is unique in setup and site layout and requires site-specific considerations in the planning, design, construction, and installation of new emissions sources or modifications to existing emission sources. If the City of Jamestown, the Village of Freeport, Rockville Center, or any other municipally-owned facility does propose to construct a new emission source(s), or expand by modifying existing equipment, the professional services that would be required will consist of engineering services from an environmental consulting firm. These professional services would be required whether or not the Department ultimately adopts Part 251.

COSTS

New coal-fired and oil-fired boilers will not be able to meet the proposed CO emission standard without the installation of controls, such as carbon capture and sequestration (CCS) or some other advanced carbon reduction technology. Coal-fired boilers would need to install 50 to 60 percent CCS or otherwise reduce their CO emissions by 50 to 60 percent in order to meet the proposed CO emission standard. Oil-fired boilers would need to install 33 to 40 percent CCS or otherwise reduce their CO emissions by 33 to 40 percent in order to meet the proposed CO emission standard. Initial installation costs of CCS units on either coal- or oil-fired boilers will vary greatly depending on the size of the system needed for capture and the distance the captured CO must be piped before sequestration. Depending on the CCS scenario, the initial project cost may increase as little as 10 percent up to 100 percent in the worst case scenario. The increase in cost to operations and maintenance of new coal-fired emission sources will be approximately 86 percent (56 dollars per MW-hr). This will project to be an increase of at least 50 million dollars per year in maintenance and operations costs for a 100 MW coal-fired boiler. It has been estimated that new oil-fired projects will have similarly associated cost increases. The Department also estimates that projects at existing facilities that modify existing coal-fired or oil-fired boilers will incur similar costs for installation, maintenance, and operation of a retrofitted CCS system.

MINIMIZING ADVERSE IMPACTS

The Department has considered the issues and determined that Part 251 will not have an adverse impact on small businesses or local governments. The ability of a new or modified source to meet the requirements of Part 251 will not be influenced by whether the source is owned by a local government or small business, as compared to some other entity. The proposed regulation establishes specific CO emission standards for base load fossil fuel-firing emission sources and fossil fuel-firing peaking emission sources, as well as a case-specific CO emission limit for any other affected emission source. The rule only applies to new facilities, or to increases in capacity of at least 25 MW at existing facilities, and therefore allows ample time to design systems that comply with applicable emission limits. Also, the rule has been designed such that it can be met by electric generating systems that are commercially available. In particular, the CO emission standards for base load facilities can be met by natural gas-firing combined cycle plants, and the standard was established with an allowance for minimal oil-firing (up to 45 days). Likewise, the CO emission standards for peaking emission sources were established with an allowance for up to 100 percent oil-firing. Because most of the new electric generating facilities anticipated to be built in the State are already of a type that would comply with Part 251, any adverse impact will be minimized. For facilities subject to a case-specific CO emission standard, the proposed emission limit must achieve the maximum degree of reduction for new sources and shall not be less stringent than the emission control or operating efficiency that is achieved in practice by the best controlled similar source(s).

In satisfying the requirements of section 202-b for minimizing adverse impacts to small business, the State Administrative Procedures Act (SAPA) requires that each proposal address the following:

(1) 'Establishment of differing compliance requirements or reporting times.' The compliance and reporting times are consistent with other air permitting regulations and quarterly, semi-annual and annual reporting that affected facilities would already be subject to.

(2) 'Use of performance rather than design standards.' Part 251 is a unit-specific rule making based on performance standards and technology currently available. Part 251 restricts emissions of CO at subject facilities, but does not dictate what design or control strategies facilities must implement to achieve compliance with applicable rates.

(3) 'Exemption from coverage by the rule for small business and local governments.' The Department has determined that Part 251 should apply to sources regardless of ownership. CO emissions may be significant from municipally-owned power stations and facilities and the objectives of this rule would not be met if certain owners or operators were exempted from its provisions. Moreover, any facility subject to Part 251 would also require a Certificate from the Siting Board pursuant to Public Service Law Article X (Article X), regardless of ownership.

SMALL BUSINESS AND LOCAL GOVERNMENT PARTICIPATION

The State Administrative Procedures Act requires agencies to provide public and private interests in rural areas the opportunity to participate in the rule making process and or public hearings. The Department held a stakeholder meeting on October 20, 2011 to discuss the likely elements of the proposed Part 251 and to obtain feedback. The Department also conducted additional stakeholder outreach during the development of Part 251, prior to its formal proposal for public comment. This additional outreach included a presentation to the New York Independent System Operator (NYISO) Environmental Advisory Committee on October 21, 2011. These meetings and presentations also included question and answer sessions which allowed the Department to obtain additional feedback and input from stakeholders prior to proposing Part 251. Moreover, the Department discussed the forthcoming Part 251 rulemaking at several events regarding Article X and the implementation of the Power NY Act, including at the Business Council's 2011 Annual Industry-Environment Conference on October 27, 2011, and at the Alliance for Clean Energy New York's 5th Annual Fall Conference & Membership Meeting on October 26, 2011. The Department also conducted additional informal stakeholder outreach throughout October and November 2011 in order to obtain input used in the development of Part 251. The Department will hold public hearings on Part 251 and small businesses and local governments will be able to comment on the proposed rule during the notice and comment period.

CURE PERIOD OR AMELIORATIVE ACTION

No additional cure period or other additional opportunity for ameliorative action is included in Part 251. First, because of the nature of Part 251 as a performance standard that only applies to certain new or expanded facilities, Part 251 will not result in immediate violations or impositions of penalties for existing facilities. Any new or existing facility that may be subject to Part 251 will also need to first obtain a Certificate from the Board pursuant to Article X, and submit an application to the Department for a permit or permit modification, as appropriate. Because facilities must already comply with these procedures before commencing construction, there is no need to provide for any additional cure period or other additional opportunities for ameliorative action. Second, Part 251 is intended, in large part, to prevent new or expanded major electric generating facilities that would have substantial emissions of CO. Providing for an additional curing period or other opportunity for ameliorative action in Part 251 may undercut this objective by allowing for new or expanded carbon-intensive facilities to be built in the interim. Finally, pursuant to the Power NY Act, the Legislature established that the promulgation of Part 251 is a prerequisite to the availability of the process under Article X for the siting of major electric generating facilities. Any additional curing period may therefore impact or delay the ability to build new or expanded major electric generating facilities in the State.

Rural Area Flexibility Analysis

TYPES AND ESTIMATED NUMBERS OF RURAL AREAS AFFECTED

The proposed rule (6 NYCRR Part 251) is not expected to have a substantial adverse impact on rural areas in New York State. The proposed rulemaking will apply statewide and thus all rural areas of New York State will be affected.

Rural areas are defined as rural counties in New York State that have populations of less than 200,000 people, towns in non-rural counties where the population densities are less than 150 people per square mile, and villages within those towns.

COMPLIANCE REQUIREMENTS

Facilities subject to Part 251 will be required to meet a 12-month rolling average CO emission limit. This rule will impose minimal additional paperwork for recordkeeping and monitoring to demonstrate compliance with 12-month rolling average CO emission standards. Facilities subject to this regulation are already required to meet emission standards for other air contaminants, for example, oxides of nitrogen, and thus have systems in place to monitor emissions of air contaminants and submit annual and semi-annual reports to the Department. Depending on the source, the facility owner may need to modify the data acquisition handling system software, in order to compute and report CO monitoring data in pounds per gross electric output rate in terms of megawatt/hr, or fuel input rate in terms of million Btu per hour. Many facilities subject to Part 251 will also be subject to Part 242, and would already have to compute and report CO emissions data under Part 242. The additional paperwork for recordkeeping and reporting for this proposed rule will be minimal as data is submitted electronically accompanied by paper summary reports. The records and reports will be required to be kept and submitted in the same formats used to track other pollutants with emission standards. The additional requirements imposed by this rule are not expected to be unduly burdensome.

COSTS

MINIMIZING ADVERSE IMPACT

The Department has considered the issues and determined that Part 251 will not have an adverse impact on rural areas. The ability of a new or expanded source to meet the requirements of Part 251 will not be influenced by the location of the facility in a rural area, as compared to a suburban or urban area. Facilities proposed in rural areas that utilize the equipment type and fuel listed above will be able to comply with the relevant CO emission limit, and thus will not be adversely impacted by Part 251. Just like coal-fired or oil-fired facilities in suburban or urban areas, coal-fired or oil-fired facilities proposed to be located in rural areas would have to install CCS or some other advanced carbon control technology in order to comply with Part 251, as described above.

The proposed regulation establishes specific CO emission standards for base load fossil fuel-firing emission sources and fossil fuel-firing peaking emission sources, as well as a case-specific CO emission limit for any other affected emission source. The rule only applies to new facilities, or to increases in capacity of at least 25 MW at existing facilities, and therefore allows ample time to design systems that comply with applicable emission limits. Also, the rule has been designed such that it can be met by electric generating systems that are commercially available. In particular, the CO emission standards for base load facilities can be met by natural gas-firing combined cycle plants, and the standard was established with an allowance for minimal oil-firing (up to 45 days). Likewise, the CO emission standards for peaking emission sources were established with an allowance for up to 100 percent oil-firing. Because most of the new electric generating facilities anticipated to be built in the State are already of a type that would comply with Part 251, any adverse impact will be minimized. For facilities subject to a case-specific CO emission standard, the proposed emission limit must achieve the maximum degree of reduction for new sources and shall not be less stringent than the emission control or operating efficiency that is achieved in practice by the best controlled similar source(s).

RURAL AREA PARTICIPATION

The State Administrative Procedures Act requires agencies to provide public and private interests in rural areas the opportunity to participate in the rule making process and or public hearings. The Department held a stakeholder meeting on October 20, 2011 to discuss the likely elements of the proposed Part 251 and to obtain feedback. The Department also conducted additional stakeholder outreach during the development of Part 251, prior to its formal proposal for public comment. This additional outreach included a presentation to the New York Independent System Operator (NYISO) Environmental Advisory Committee on October 21, 2011. These meetings and presentations also included question and answer sessions which allowed the Department to obtain additional feedback and input from stakeholders prior to proposing Part 251. Moreover, the Department discussed the forthcoming Part 251 rulemaking at several events regarding Article X and the implementation of the Power NY Act, including at the Business Council's 2011 Annual Industry-Environment Conference on October 27, 2011, and at the Alliance for Clean Energy New York's 5th Annual Fall Conference & Membership Meeting on October 26, 2011. The Department also conducted additional informal stakeholder outreach throughout October and November 2011 in order to obtain input used in the development of Part 251. The Department will hold public hearings on Part 251 in upstate and other rural areas and will notify interested parties of this proposed rulemaking.

Job Impact Statement

NATURE OF IMPACT

The Department is not currently aware of any proposed projects in the State that will be negatively affected by the proposed new 6 NYCRR Part 251, CO Performance Standards for Major Electric Generating Facilities. There are currently no permit applications or permit modifications pending before the Department for facilities that would be subject to Part 251 and that would be unable to meet the carbon dioxide (CO) emission limits established in the regulation. Therefore, the proposed Part 251 will not have an adverse impact on employment opportunities at any specific currently proposed projects or facilities.

The proposed rule could potentially impact the installation of new coal-fired or oil-fired electric generating facilities, as well as expansions at existing facilities that utilize coal-firing or oil-firing. New, large-scale, coal-fired or oil-fired electric generating facilities are not expected to be built in the State, for a variety of reasons, even without the promulgation of Part 251. Therefore, Part 251 is not anticipated to have an adverse impact on employment opportunities in the state.

A project sponsor considering construction or expansion of a facility utilizing coal or oil electric generating facility might decide to not go forward with an expansion project utilizing coal or oil, or instead might have to utilize natural gas or some other fuel or technology in order to comply with the CO emission limits in Part 251. Likewise, an applicant might decide not to build a new major electric generating facility that would have utilized coal or oil, because such a facility would not be able to comply with the CO emission limits in Part 251 without utilizing carbon capture and sequestration (CCS) or some other carbon reduction technology. If a project was not built specifically because of Part 251, then Part 251 may have adverse impacts on employment opportunities in the State, but this is an extremely unlikely scenario.

On the other hand, a coal-fired or oil-fired electric generating facility that is constructed or expanded and subject to Part 251 would have to employ a new advanced technology such as CCS. This might create more jobs for an area, based on the level of controls needed to achieve compliance with the proposed CO emission standards. By utilizing CCS or some other new carbon reduction technology, the project would likely require more employees than a conventional facility without such technology. Therefore, under this potential scenario, the proposed rule could actually have a slight positive impact on employment opportunities in New York State. Similarly, the biomass-fired facilities, waste-to-energy (WTE) facilities, or other facilities subject to a case-specific CO emission limit under Part 251, the installation of the most stringent existing control technologies and operating efficiencies may require additional employees as compared to a higher emitting or less efficient facility. In any case, Part 251 is unlikely to adversely impact employment opportunities in the state.

CATEGORIES AND NUMBERS OF EMPLOYMENT OPPORTUNITIES AFFECTED

Existing electric generating facilities that continue to operate under current permits will not be subject to additional requirements through this rulemaking and thus there should not be any adverse impact to employment opportunities for these facilities as a result of proposed Part 251. Should the facility owner or operator decide to expand their electric generating facility, with regard to plant design and fuel selection, new construction and additional labor force may be needed in order to meet the requirements of this regulation, especially in regards to implementing CCS or other advanced carbon reduction technology. This would create job opportunities in the area the plant is located.

REGIONS OF ADVERSE IMPACT

Because the Department is not currently aware of any proposed projects that would be subject to Part 251 and unable to meet the CO emission limits established in the regulation, the Department is unable to specify which regions of the State may be impacted by the proposed regulation. Any potential positive or adverse impacts on job opportunities would be focused on the region in which an electric generating facility is proposed, including the region in which any potential CCS is utilized in order to comply with Part 251. Therefore, any region located in New York State may or may not be adversely impacted by this proposed regulation.

MINIMIZING ADVERSE IMPACT

ENV-03-12-00009-P CO Emissions from Major Electric Generating Facilities

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