Regulatory Impact Statement Summary 6 NYCRR Parts 251 and 200
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 (CO2) 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, CO2 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.
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 CO2 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.
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 CO2 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 CO2 emission reduction technology, working in conjunction with other State programs such as the Regional Greenhouse Gas Initiative (RGGI), in order to minimize CO2 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, CO2 is the chief contributor to climate change. Emission sources that fire carbon-containing material, such as fossil fuel, emit significant quantities of CO2. 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 CO2 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 CO2, 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 CO2 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 CO2 emission standards for new major electric generating facilities, and applicable expansions at existing electric generating facilities.
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.
CO2 Emission Standards and Requirements
The proposed regulation will establish CO2 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 CO2 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 CO2 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 CO2 emission limits described above, including emission sources directly attached to a gasifier, are required to propose a case-specific emission limit for CO2. 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.
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 CO2 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 CO2 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 CO2 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 CO2 emissions by 50 to 60 percent in order to meet the proposed CO2 emission standard. Oil-fired boilers would need to install 33 to 40 percent CCS or otherwise reduce their CO2 emissions by 33 to 40 percent in order to meet the proposed CO2 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 CO2 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 CO2 emission profile. The proposed emission limit must achieve the maximum degree of CO2 emission reduction for new emission sources, and cannot be less stringent than the CO2 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 CO2 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.
This rule will impose minimal additional paperwork for recordkeeping and monitoring to demonstrate compliance with 12-month rolling average CO2 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 CO2 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 record keeping 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.
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 record keeping requirements.
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 CO2 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 CO2 emission standards for each source and fuel type: The Department has determined that the establishment of CO2 emission standards for each source and fuel type would not promote or achieve the goal of reducing CO2 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 CO2 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.
As result of several actions by EPA, GHGs, including CO2, 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 CO2 emission standards for stationary sources in the federal regulations. Therefore, the proposed Part 251 CO2 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.
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.