Regulatory Flexibility Analysis for Small Businesses and Local Government 6 NYCRR Parts 251 and 200
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 (CO2) 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.
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 CO2 emission limit. 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. Many facilities subject to Part 251 will also be subject to Part 242, and would already have to compute and report CO2 emissions data under Part 242. The additional paperwork for record keeping 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.
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.
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 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 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 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.
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.
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 CO2 emission standards for base load fossil fuel-firing emission sources and fossil fuel-firing peaking emission sources, as well as a case-specific CO2 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 CO2 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 CO2 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 CO2 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 CO2 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. CO2 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 CO2. 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.