Rural Area Flexibility Analysis 6 NYCRR Parts 251 and 200

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 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.

Costs

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 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 CO₂ 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 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).

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.