Regulatory Impact Statement 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.
While ECL Section 19-0312 requires the Department to promulgate a regulation of this type, 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 Environmental Conservation Law (ECL) at Sections 1-0101, 1-0303, 3-0301, 19-0103, 19-0105, 19-0107, 19-0301, 19-0303, and 19-0305. These statutory provisions are described below.
Authority to Prevent and Control Air Pollution
ECL Section 1-0101. This section declares that it is a policy of New York State to conserve, improve and protect its natural resources and environment and control air pollution in order to enhance the health, safety and welfare of the people of New York State and their overall economic and social well being. This section further declares that the Department shall promote patterns of development and technology which minimize adverse impact on the environment.
ECL Section 1-0303. This section defines the term "pollution." Pollution is: "the presence in the environment of conditions and or contaminants in quantities of characteristics which are or may be injurious to human, plant or animal life or to property or which unreasonably interfere with the comfortable enjoyment of life and property throughout such areas of the state as shall be affected thereby."
ECL Section 3-0301. This section empowers the Department to develop programs to carry out the environmental policy of New York State set forth in section 1-0101. Section 3-0301 specifically empowers the Department to, among other things: provide for the prevention and abatement of air pollution; identify changes in ecological systems and to warn of emergency conditions; and adopt such regulations as may be necessary, convenient or desirable to effectuate the environmental policy of the State.
ECL Section 19-0103. This section declares that it is the policy of New York State to maintain a reasonable degree of purity of air resources. In carrying out such policy, the Department is required to balance public health and welfare, the industrial development of the State, propagation and protection of flora and fauna, and the protection of personal property and other resources. To that end, the Department is required to use all available practical and reasonable methods to prevent and control air pollution in the State.
ECL Section 19-0105. This section declares that it is the purpose of Article 19 of the ECL to safeguard the air resources of New York State under a program which is consistent with the policy expressed in section 19-0103 and in accordance with other provisions of Article 19.
ECL Section 19-0107. This section defines the terms "air contaminant" and "air pollution." "Air contaminant" is defined as "a dust, fume, gas, mist, odor, smoke, vapor, pollen, noise or any combination thereof." "Air pollution" is defined as "the presence in the outdoor atmosphere of one or more air contaminants in quantities, of characteristics and of a duration which are injurious to human, plant or animal life or to property or which unreasonably interfere with the comfortable enjoyment of life and property throughout the State or throughout such areas of the State as shall be affected thereby." CO2 and other greenhouse gases (GHGs) fit well within these definitions because they are gases which are present in the outdoor atmosphere in quantities that engender and/or provoke climate change, which is injurious to life and property in New York State.
ECL Section 19-0301. This section declares that the Department has the power to promulgate regulations for preventing, controlling or prohibiting air pollution, and shall include in such regulations provisions prescribing the degree of air pollution that may be permitted and the extent to which air contaminants may be emitted to the air by any source in any area of the State. The Department also has the authority to cooperate with other states, interstate agencies, or international agencies with respect to the control of air pollution or air contamination.
ECL Section 19-0303. This section provides that the terms of any air pollution control regulation promulgated by the Department may differentiate between particular types and conditions of air pollution and air contamination sources. Section 19-0303 also prescribes procedures for adopting any code, rule or regulation which contains a requirement that is more stringent than the Clean Air Act (Act) or regulations issued pursuant to the Act by the U.S. Environmental Protection Agency (EPA).
ECL Section 19-0305. This section authorizes the Department to enforce the codes, rules and regulations established in accordance with Article 19. Section 19-0305 also empowers the Department to conduct or cause to be conducted studies and research with respect to air pollution control, abatement or prevention.
Finally, Sections 71-2103 and 71-2105 set forth the civil and criminal penalty structures for violations of Article 19.
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. Generally speaking, under Article X, a decision on an application for a Certificate must be made by the Board within twelve months of a compliant application. This 12-month period may be reduced to six months for modified or repowered facilities that meet certain conditions, including a reduction in the rate of emissions of relevant siting air contaminants, and a reduction in the total annual emissions of each such contaminant.
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. Therefore, the Department will be proposing a new 6 NYCRR Part 487, Analyzing Environmental Justice Issues in Siting of Major Electric Generating Facilities Pursuant to Public Service Law Article X, which will apply to applicants seeking a Certificate from the Board.
In addition to these components of the process for siting major electric generating facilities under Article X, the Power NY Act also included a requirement to establish CO2 performance standards for such facilities. The Legislature therefore directed the Department to establish, as a threshold requirement for facilities subject to Article X, a minimum performance standard for CO2 emissions. This rulemaking implements this particular 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, 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. This will in turn serve to lessen the State's contribution to atmospheric concentrations of GHGs. Increased atmospheric concentrations of GHGs are contributing to global climate change, and hence endangering public health and welfare in the State.
Even aside from the Power NY Act and Article X, with numerous additional legislative enactments, the Legislature has directed and empowered the Department to promote the safety, health and welfare of the public, protect the State's natural environment, and also help ensure a safe, dependable and economical supply of energy to the people of the State. GHGs such as CO2, nitrous oxide, methane, hydrofluorocarbons (HFCs), perfluorocarbons (PFCs) and sulfur hexafluoride are atmospheric gases that allow incoming energy from the sun to pass through and then absorb heat radiated from the earth's surface. GHGs have increased significantly since pre-industrial times with a large portion of that increase occurring from the 1970s to the present. There is strong scientific evidence that the earth's climate is changing and 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. The changing climate threatens the State's air quality, water quality, marine and freshwater fisheries, tidal and freshwater wetlands, surface and subsurface drinking water supplies, river and stream impoundment infrastructure, forests, and wildlife habitats.1, 2
Among the GHGs, CO2 is the chief contributor to climate change. Emission sources that fire carbon-containing material, such as fossil fuels, emit significant quantities of CO2. Electricity generation is responsible for approximately 19 percent of all GHGs emitted in New York State. In 2008, fuel combustion by the electricity generation sector in New York State emitted approximately 47 million tons of CO2 into the atmosphere. In 2010, electric generating units in the State subject to RGGI emitted approximately 42 million tons of CO2 into the atmosphere.
Article 19 of the ECL requires the Department to promulgate regulations targeting reductions in emissions of CO2 from major electric generating facilities. In December 2009, 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 (the "Endangerment Finding").3 Following the Endangerment Finding, EPA has taken numerous additional actions under the Act regarding the regulation of GHG emissions. As a result of these actions, according to EPA, GHGs became "subject to regulation" under the Act as of January 2, 2011. EPA promulgated a rule to tailor the major source applicability thresholds for GHG emissions for purposes of the Prevention of Significant Deterioration (PSD) and Title V programs under the Act (the "GHG Tailoring Rule"),4 which the Department subsequently incorporated in its 6 NYCRR Parts 200, 201, and 231. PSD provisions establish preconstruction permitting requirements for new major stationary sources and major modifications at existing stationary sources. Most notably, PSD includes the requirement that applicable sources are subject to Best Available Control Technology (BACT) for GHGs. Finally, EPA is currently committed, pursuant to a litigation settlement, to propose new source performance standards (NSPS) under section 111 of the Act for GHG emissions from power plants. If adopted, such NSPS would apply to new and modified facilities, and EPA would issue emission guidelines for required state regulation of GHG emissions from existing power plants. EPA is currently in the process of developing such an NSPS.
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. Climate change represents one of the most pressing environmental challenges for the State, the nation, and the world, and reducing GHG emissions is a means to reduce or stem the pace of climate change. 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.
Statutory Language and Requirements
ECL Section 19-0312(3), enacted as part of the Power NY Act, directs the Department to promulgate regulations "targeting reductions in emissions of [CO2] that would apply to major electric generating facilities that commenced construction after the effective date of the regulations." The promulgation of this regulation is fulfilling this statutory requirement. While the statutory language does not specify the precise manner of regulation, the title of the section refers to "performance standards." Moreover, the language directs the Department to apply the regulation to facilities that commence construction after the effective date of the regulation. Taken together, the Department therefore interprets these aspects of ECL Section 19-0312 as requiring the Department to enact a regulation in the form of a performance standard for CO2.
The term "major electric generating facility" is defined in ECL Section 19-0312(1) as "any electric generating facility with a nameplate capacity of twenty-five thousand kilowatts or more." This is consistent with the definition of "major electric generating facility" in PSL Section 160(2) for purposes of Article X, which was also enacted as part of the same Power NY legislation. Moreover, pursuant to Article X, any new major electric generating facility - or increase in capacity of an existing electric generating facility by more than 25 MW - requires a Certificate from the Board prior to commencing construction. See PSL section 162(1). The Department therefore interprets ECL Section 19-0312, in the context of the overall Power NY Act, as requiring a regulation that includes a CO2 performance standard that applies to any facility that must obtain a Certificate from the Board pursuant to Article X (provided the facility will emit CO2). Part 251 will therefore apply to new major electric generating facilities, and to expansions at existing electric generating facilities that increase capacity by at least 25 MW.
In addition to the form of regulation and the applicability of the regulation, the Department must also determine the appropriate level of the CO2 emission standard. As referenced above, ECL Section 19-0312(3) directs the Department to promulgate regulations "targeting reductions in emissions of [CO2] . . . ." The Department interprets this language as requiring a CO2 performance standard that achieves targeted CO2 emission reductions, in a manner that is achievable in practice based on demonstrated technology, and that may be met without significant reliability impacts. Part 251 therefore establishes a primary CO2 emission standard based on a CO2 emission rate achievable by a new combined cycle natural gas-fired power plant. As described below, such a standard prevents new high carbon sources of energy in order to achieve targeted CO2 emission reductions, and is based on demonstrated technology. Part 251 will also include a separate CO2 emission standard for simple cycle combustion turbines, in order to allow for certain peaking facilities that may be necessary for purposes of electrical grid reliability. Finally, for other non-fossil fuel facilities that have varying CO2 emission profiles and that may present other considerations, the Department determined that a case-specific CO2 emission limit best meets the statutory requirements of ECL Section 19-0312, by allowing the Department to ensure that the emission rate achieves targeted CO2 emission reductions and is achievable in practice without reliability impacts.
As noted, Part 251 will apply to increases in capacity of at least 25 MW at existing electric generating facilities, in addition to new major electric generating facilities. Therefore, as described more below, just like a new coal-fired major electric generating facility could not meet the emission rate established in Part 251 without the use of carbon capture and sequestration (CCS) or other CO2 emission reduction technology, an existing coal-fired electric generating facility could not increase its capacity by at least 25 MW and continue firing coal without the use of CCS or other CO2 emission reduction technology. This is consistent with the Department's interpretation of the statutory requirement in ECL Section 19-0312, in that the Department interprets the statutory language as requiring a CO2 performance standard for facilities that must obtain a Certificate from the Board pursuant to Article X. Part 251 treats new subject facilities in the same manner as applicable expansions at existing facilities.
As described below, this is unlikely to serve as a disincentive for increases in efficiency at existing coal-fired power plants. This is because such efficiency upgrades are extremely unlikely to result in increases in capacity of at least 25 MW that would trigger Part 251 applicability. Finally, it is important to note that a "modification" to an existing facility that triggers New Source Review (NSR)/PSD applicability under the Act may or may not be subject to Article X and Part 251. The applicability of NSR is distinct from the applicability of Article X and Part 251. In order to be subject to Article X and Part 251, a "modification" for purposes of NSR must also increase the capacity of the facility by at least 25 MW.
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 advocacy groups. During this meeting, the Department presented some of the draft conditions of the rule, answered questions regarding the proposed rule, and requested feedback on several issues regarding Part 251. The Department also invited written comments, and requested that stakeholders submit any such informal comments to the Department by November 1, 2011. The Department reviewed these comments, and incorporated considerations of issues discussed at the stakeholder meeting, in further developing Part 251.
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. The presentation included a question and answer session 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. Finally, the Department held its last stakeholder meeting for Part 251 on November 22, 2011 with several waste-to-energy (WTE) facility representatives.
CO2 Emission Standards and Requirements
The proposed regulation will establish CO2 emission standards for new major electric generating facilities. Part 251 will also establish CO2 emission standards for expansions of existing electric generating facilities that increase electrical output capacity by at least 25 MW. For existing electric generating facilities that become subject to Part 251 by virtue of an increase in capacity of at least 25 MW, only those emission source(s) at the facility that are involved in the increase in capacity will be subject to the CO2 emission limits. This may be, for example, a new emission source that is added as part of an existing electric generating facility and that adds at least 25 MW of new capacity, or an existing emission source within an electric generating facility that is changed in order to increase capacity by at least 25 MW.
One concern raised by stakeholders was that a facility that sought to increase its operating efficiency, without increasing emissions, would be penalized by this regulation. In particular, some stakeholders were concerned that, if the rule applied to existing electric generating facilities that increased their capacity by at least 25 MW, then it might create a disincentive for increases in operating efficiency at those facilities.
The Department investigated the types of improvements that existing electric generating facilities can undertake to improve their operations and increase their output without adding new emission sources, physically modifying their fuel burning equipment, and/or increasing emissions. The two technologies that are currently available are computer software optimization programs and steam turbine improvements. The computer software optimization programs have been commercially available for approximately 20 years. Most optimization software is guaranteed to improve output efficiency 0.5 to 1.5 percent, depending on the type and age of the electric generating equipment. The other technology involves improvements to the steam turbine. Generally, this entails the addition of more blades or fins to the existing turbine. Other optimizations improvements regarding the steam handling of the turbine or electric generator improvements generally increase overall operating efficiency by one to two percent.
If all of the efficiency improvement projects were undertaken at once at a facility, a 1.5 to 3.5 percent efficiency increase would ostensibly occur. This translates to a 3.5 MW increase in capacity for every 100 MW of power generated, based on the maximum efficiency increase of 3.5 percent. Therefore, in order to become subject to Part 251 by virtue of increases in efficiency at an existing source, an existing facility that achieved the maximum efficiency improvements would need to have an existing electrical output capacity of 715 MW or greater. Based on these figures, of all the existing electric generating facilities in the State, only three residual oil-fired facilities could potentially be affected by this regulation under this scenario (Roseton, Oswego, and Northport). No existing coal-fired facilities have greater than 715 MW power output. Thus, the Department does not believe that Part 251 will serve as a disincentive to efficiency improvements at existing emission sources at existing facilities. On the other hand, the effect of Part 251 on new emission sources that are added as part of an existing electric generating facility and that increase capacity by 25 MW will be consistent with the effect of Part 251 on new major electric generating facilities.
Depending on the type of source, facilities subject to Part 251 will be required to meet one of three emission standards. First, 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). Second, except for emission sources directly attached to a gasifier, owners or operators of 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. Finally, 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 includes, for example, biomass-fired facilities and WTE facilities. Owners and operators will be required to submit their proposals to the Department for review and approval.
Derivation of CO2 Emission Limits
The Department established the CO2 emission standards above based on the level of emissions that may be expected from each particular subject emission source type assuming that (1) the particular emission source type uses existing technology that results in the lowest CO2 emissions profile for that emission source type, and (2) the subject sources operate somewhat less than optimally with respect to CO2 emissions due to the existence of certain typical or unavoidable ongoing operational constraints.
The Department has included the requirement that boilers subject to an emission limit of either 925 lbs/MW-hr or 120 lbs/mmBtu must fire a minimum of 70 percent fossil fuel. A boiler that fires less than 70 percent fossil fuel will instead be subject to a case-specific CO2 emission limit. This is intended to address the co-firing of non-fossil fuels in boilers. The Department currently utilizes a guidance document (DAR-3 Alternative Fuels), which provides a mechanism for fossil fuel-fired boilers to supplement their fuel feed with up to 30 percent "alternative fuel" (alternative fuels are reviewed on a case-by-case basis to determine acceptability). DAR-3 states that, if a proposal to fire an alternative fuel is acceptable to the Department (at or below the 30 percent co-firing level), the emission source shall continue to be regulated as a fossil fuel-fired emission source. Consistent with this longstanding Departmental policy and interpretation, Part 251 will treat a boiler that fires at least 70 percent fossil fuel the same as an entirely fossil fuel-fired boiler. In other words, provided that a boiler is permitted to fire at least 70 percent fossil fuel, then it will be subject to a CO2 emission limit of 925 lbs/MW-hr or 120 lbs/mmBtu, regardless of the type of any non-fossil fuel that may be co-fired. On the other hand, consistent with the current Department policy, a boiler subject to Part 251 that proposes to co-fire more than 30 percent non-fossil fuel will be required to conduct a case-by-case analysis (as an "other source") to determine its CO2 emission limit, regardless of the type of non-fossil fuel that may be co-fired.
To determine what technology resulted in the lowest CO2 emissions profile for each emission source type, the Department considered information related to the generation of CO2 emissions from the emission source type. The Department conducted a review of performance data obtained from leading manufacturers and vendors of combustion turbines. The Department also analyzed what type of operational constraints would likely affect subject sources. In undertaking this work, the Department consulted with DPS and the New York State Energy Research and Development Authority (NYSERDA).
The Department determined that modern natural gas-fired combined cycle combustion turbines have the lowest CO2 emissions profile. Of the existing technologies reviewed, natural gas-fired combined cycle combustion turbines are the most efficient in converting fuel to energy and are designed to primarily fire natural gas, the least carbon intensive fossil fuel. Natural gas-fired combined cycle combustion turbines, when firing natural gas solely, emit the lowest levels of CO2 of all surveyed types of combustion sources. Therefore, the Department established the CO2 emission standards for base loaded emission sources like boilers and combustion turbines to be equivalent to that expected from a well-operated and well-maintained combined cycle combustion turbine that primarily fires natural gas with minimal distillate oil back-up.
The Department also determined that, for the purposes of New York State electrical grid reliability, separate CO2 emission standards would also need to be developed for simple cycle combustion turbines. Simple cycle combustion turbines are used during periods of peak load operation and are able to be brought on-line quickly (within minutes). Many areas of the State that do not currently have natural gas available use oil-fired simple cycle turbines. So, the Department has also developed CO2 emission standards for well-operated and well-maintained simple cycle combustion turbines which fire either natural gas or distillate oil.
The Department reviewed both technical and operational factors before establishing the CO2 emission standards. These factors included constraints imposed to ensure the reliability of the electricity supply system (as indicated by the NYISO and generator owners) and typical losses in machine efficiency over time, as discussed with equipment manufacturers, the NYISO and DPS. The Department also reviewed factors that support the promotion of electrical system supply reliability, such as precautionary measures in the event of a sudden loss of natural gas supply which require the burning of back-up oil supplies, time periods where the firing of an emission source with oil may be necessary (such as during seasonal peak demands in the residential heating sector, notably in New York City and Long Island), or time periods when natural gas usage by the electric generating sector is curtailed due to residential demand and natural gas availability. Finally, the Department drafted emission standards which recognize that over the life of a typical natural gas-fired combustion turbine a percentage of heat rate degradation occurs which is unrecoverable even through implementation of good annual maintenance programs and occasional system overhauls.
The exact number of hours of oil combustion permissible under the proposed emission standards depends on the carbon content of the fuel consumed; the extent the fuel is oxidized in the combustion device; the feed rate of fuel in a given hour; and the efficiency of the system to generate electricity as a whole. Based on the factors identified above, and vendor information provided by turbine manufacturers, the range of days combined cycle combustion turbine could operate on oil and comply with the proposed CO2 emission standard is 40 to 45 days per year. Based on the factors identified above, and vendor information provided by turbine manufacturers, a simple cycle combustion turbine could operate 85 to 100 percent of its operating time on oil.
In addition to recognizing the need for backup oil-firing and other technical and operational factors in establishing the level of the CO2 emission standards, appropriate flexibility is also provided for regulated entities in Part 251, in order to recognize the potential for other reliability issues, or technical or operational constraints. First, under the regulation, emissions are calculated on a 12-month rolling average basis, which covers such factors as the impact of potentially frequent periods of start-up and shut-down. Second, a facility will be able to choose whether to include an input-based limit or an output-based limit in its permit for purposes of compliance with the relevant emission limit.
Case-Specific Emission Limit for Other Sources
The Department has proposed to implement a case-by-case approach for establishing CO2 emission limits for other sources that are not subject to a specific CO2 emission limit, including non-fossil fuel fired emission sources. At this time, the Department is unable to determine an appropriate single CO2 emission standard that could be applicable to all other types of major electric generating facilities. For these other types of facilities, there are a number of additional variables and considerations as compared to more traditional facilities such as those that utilize combustion turbines or fossil fuel-fired boilers.
The Department has proposed the case-by-case analysis based on the continually developing and uncertain nature of the science regarding the climate impacts of other types of sources, as well as the distinct considerations that come into play for such other sources. For example, with regard to biomass, only certain types of biomass may be considered carbon-neutral over time, under certain conditions. The treatment of CO2 emissions from biogenic sources is the subject of ongoing analysis and debate, as well as a continually developing and complex state of science. This issue is so unsettled that EPA has deferred, for a period of three years, any calculation and inclusion of biogenic CO2 emissions from PSD and Title V applicability under the Act in order "to conduct a detailed examination of the science associated with biogenic CO2 emissions from stationary sources, . . . and resolve technical issues in order to account for biogenic CO2 emissions in ways that are scientifically sound and also manageable in practice." 76 Fed. Reg. 43490,43496 (July 20, 2011). For these reasons, at this time, the Department is unable to determine a single emission standard or other approach that would work for all types of biomass-fired facilities, and that would take into account all appropriate considerations. In order to appropriately account for the carbon impact of a biomass-fired facility, a more comprehensive project-specific lifecycle analysis and carbon accounting methodology may be required. Therefore, the Department has proposed the case-by-case approach, in order to allow for appropriate consideration of all relevant factors on a project-specific basis.
Likewise, with regard to waste to energy (WTE) facilities, the Department recognizes that such facilities may present distinct variables and considerations, as compared to conventional fossil fuel-fired facilities. For example, WTE facilities may be considered to be serving a dual role, in terms of both the production of electricity and the management of waste. Just like with biomass-fired facilities, the carbon-intensity of a WTE facility depends on a variety of factors, and may require a more comprehensive project-specific lifecycle analysis and accounting methodology. When measured solely in terms of emissions from the facility, CO2 emissions from WTE facilities are generally higher than that from fossil fuel-fired facilities. Even if the biogenic CO2 emissions are deducted, average emissions from WTE facilities nationwide (l,045 lbs/MW-hr) are higher than emissions from modern state-of-the-art combined cycle natural gas-fired plants. Moreover, WTE facilities are not necessarily superior to landfills from a GHG perspective. The importance of carbon sequestered in landfills should not be overlooked in lifecycle analyses. The USDA Forest Service used published estimates of methane yields to estimate the amount of carbon released into the atmosphere from landfilled forest products. Their calculations suggested that maximally only 30 percent of the carbon from paper and 0-3 percent of the carbon from wood are ever emitted as landfill gas. The remaining carbon remains in the landfill indefinitely and serves as a significant carbon sink. However, the Department recently published a new State Solid Waste Management Plan, Beyond Waste, which discusses the pros and cons of solid waste management alternatives and concludes that current WTE treatment of residual waste that cannot be prevented, reused, recycled, or recovered may have several advantages over the disposal in landfills of residual wastes.
For emission sources that are directly connected to a gasifier, the Department was likewise unable, at this time, to determine a single CO2 emission standard that would be appropriate for all sources connected to a gasifier. Therefore, just as with biomass-fired and WTE facilities, the Department determined that a case-by-case approach would allow for consideration of all appropriate factors relevant to the carbon-intensity of a proposed facility on a project-specific basis. A gasifier converts a hydrocarbon feedstock into a fuel, which can then be used as the fuel for the electric generating facility. The gasification process may have substantial CO2 emissions of its own, in addition to the CO2 emissions from the electric generating facility that result from the combustion of the fuel produced by the gasifier. Because of these additional considerations that are distinct from those at conventional electric generating facilities not directly attached to a gasifier, facilities that burn a fuel that is produced by a gasifier that is directly attached to the emission source will be subject to a case-specific CO2 emission limit. The case-specific CO2 emission limit for an emission source directly attached to a gasifier must include any CO2 emissions from the gasifier that result from the gasification process, in addition to the CO2 emissions from the combustion of the fuel produced by the gasifier in order to generate electricity.
The Department will continue to investigate means and methods to resolve these uncertainties for biomass-fired facilities, WTE facilities, and other facilities that will be subject to a case-specific CO2 emission limit under Part 251. Based on this ongoing monitoring, research, and investigation, the Department may ultimately adopt a comprehensive policy regarding biomass and GHG emissions, or some approach regarding these types of facilities that does not require a case-by-case analysis.
The case-specific approach applies to, but is not limited to, biomass-fired facilities, WTE facilities, and electric generating emission sources that are directly connected to a gasifier. The case-by-case CO2 emission limit must be based on an analysis of existing control technologies and operating efficiencies of existing sources, as well as other appropriate considerations relevant to the source's CO2 emission profile. 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 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 CO2 emission rate associated with that input meets a CO2 emission rate of 925 lbs/MW-hr (output-based limit) or 120 lbs/mmBtu (input-based limit). A facility of this type may meet this emission rate through the imposition of CCS - which, as described below, is currently the only known source control technology that would allow coal or oil to meet the relevant limit - or some other method. This is consistent with the State policy of preventing new coal- or oil-fired facilities in the State, unless such facilities are able to employ CCS or some other method to reduce their CO2 emissions. Other than certain oil-fired peaking facilities as described above, no new coal-fired or oil-fired power plants should be built in the State that do not employ CCS or another CO2 emission reduction method. While the various types of solid fossil fuel and oil may have varying CO2 emission rates depending on a variety of factors, new plants that fire a majority of solid fossil fuel or oil should not be built in the State unless CCS or another CO2 emission reduction technology is employed. New plants built today will likely be in operation forty years from now, by which time GHG emissions from the power sector will need to have been reduced by over 80 percent from current levels, in order to be able to achieve and stabilize atmospheric concentrations of GHGs at levels necessary to minimize the most severe impacts of climate change. It is vital to preclude the introduction of such new high-carbon sources of energy, in order to minimize CO2 emissions from the power sector in the State, and therefore lessen the State's contribution to global climate change. This regulation accomplishes this objective.
In approving the case-by-case emission limit, the Department may consider other appropriate factors relevant to determining the overall carbon intensity of the proposed facility. For example, it is extremely important to accurately account for the carbon released as CO2 emissions from bio-energy in any policy, standard, or regulation designed to reduce GHG emissions from energy use. Different types of biomass may have different carbon impacts, based upon the lifecycle analysis of the particular biomass. When considering biomass as fuel, the lifecycle analysis should take into account the emissions associated with the growing, harvesting, processing, and combusting of the biomass. In addition, the analysis should consider the ability of biomass to offset carbon emissions with future re-growth and carbon uptake or carbon sequestration over time.
Sustainable practices for producing biomass can help promote bio-energy with a reduced risk of environmental impacts including water pollution, local air pollution, increased GHG emissions and depletion of carbon sinks, natural resources, and habitats. Therefore, in evaluating a case-by-case CO2 emission limit under Subdivision 251.3(c), the Department may consider the sustainability of the biogenic5 portion of any fuel, as well as the future carbon sequestration associated with such fuel, in determining if and how to adjust for biogenic CO2 emissions.
Carbon Capture and Sequestration (CCS)
Currently, the only known source control technology that would allow applicable coal-fired emission sources to meet the proposed CO2 emission standard is CCS. The Department has calculated that a new coal-fired facility would need to capture and sequester between 50 to 60 percent of its CO2 emissions to meet the proposed CO2 emission standard of 925 lbs/MW-hr or 120 lbs/mmBtu. The Department also calculated that a new oil-fired facility will need to capture and sequester between 33 to 40 percent (this range applies to either distillate or residual oil) of its CO2 emissions to meet the proposed CO2 emission standard of 925 lb/MW-hr or 120 lbs/mmBtu. The percent reduction calculations were based on the use of EPA's AP-426 emission factors divided by the proposed CO2 emission standards. AP-42 emission factors are derived from the testing and monitoring of emissions from a source category and are rated A through E (A ratings are the best based on the amount of reliable data used to develop the emission factor, while E ratings are emission factors based on a theoretical value). The emission factors for CO2 emissions for boilers that fire either coal or oil are rated C and B respectively. Any other control technology or other method that may be developed in the future with regard to CO2 emissions would, likewise, need to be employed to similar proportions of a facility's CO2 emissions in order to meet the relevant CO2 emission limits.
The United States Department of Energy's National Energy Technology Laboratory (NETL) Carbon Sequestration Program is developing a technology portfolio of safe, cost-effective, commercial-scale CO2 capture, storage, and mitigation technologies that will be available for commercial deployment beginning in 2020. NETL's primary Carbon Sequestration research and development (R&D) objectives are: (1) lowering the cost and energy penalty associated with CO2 capture from large stationary sources; and (2) improving the understanding of factors affecting CO2 storage permanence, capacity, and safety in geologic formations and terrestrial ecosystems. Once these objectives are met, new and existing power plants and fuel processing facilities around the world have the potential to be retrofitted with CO2 capture technologies.
In order to promote the development and full-scale application of CCS technology, The American Recovery and Reinvestment Act of 2009 (Recovery Act), an economic stimulus package enacted by the 111th United States Congress and signed into law by President Barack Obama on February 17, 2009, has set aside $3.4 billion for the funding of CCS projects. U.S. Department of Energy Secretary Steven Chu announced in early July 2009 that projects by Basin Electric Power Cooperative and Hydrogen Energy International LLC have been selected for up to $408 million in funding from the Recovery Act. The two projects selected -- an existing power plant in North Dakota and a new facility in California -- will incorporate advanced technologies to reduce CO2 emissions. Basin Electric Power Cooperative will partner with Powerspan and Burns & McDonnell to demonstrate the removal of CO2 from the flue gas of a lignite-based boiler by adding CCS to Basin Electric's existing Antelope Valley Station, located near Beulah, N.D. Hydrogen Energy International LLC, a joint venture owned by BP Alternative Energy and Rio Tinto, will design, construct, and operate an integrated gasification combined cycle power plant that will take blends of coal and petroleum coke, combined with non-potable water, and convert them into hydrogen and CO2. The CO2 will be separated from the hydrogen using the methanol-based Rectisol process. The hydrogen gas will be used to fuel a power station, and the CO2 will be transported by pipeline to nearby oil reservoirs where it will be injected for storage and used for enhanced oil recovery.7 In addition to the funding of in-the-ground projects, the U.S. Department of Energy has also recently announced the creation of a new National Carbon Capture Center (NCCC) to develop and test technologies to capture CO2 from coal-based power plants.8
Southern Company will establish and manage the NCCC at the Power Systems Development Facility (PSDF) in Wilsonville, Ala. The NCCC will meet a critical need of the Energy Department by serving as a test center for emerging carbon capture technologies. The center will enable testing and analysis at a scale large enough to provide meaningful data under real operating conditions. The Department supports investigations of CCS technology to increase confidence in commercial scale applications.
With regard to permitting, the U.S. Environmental Protection Agency recently finalized regulations in November 2010 to permit CCS installations.9 Some states are taking individual action to address legal issues related to geological sequestration. For example, the Governor of Montana, Brian Schweitzer, recently signed into law Senate Bill 498, which lays the groundwork for underground storage of CO2 in Montana by identifying processes for liability and property ownership.10 Washington State has partially implemented Engrossed Substitute Senate Bill (ESSB) 6001, Mitigating the Impacts of Climate Change (enacted in May 2007) by adopting Washington Administrative Code 173-218-115, which comprehensively amends the state's Underground Injection Control rules to allow for geological sequestration of CO2. Other states, including Kansas, Massachusetts, New Mexico, Oklahoma, Utah, and Wyoming, have proposed rules for CCS permitting or have established task forces to study statutory and regulatory requirements.11
NYISO and System Reliability
A key function of the NYISO is to study and provide for the reliability of New York's bulk electric power system. Implemented in 2005 and developed with NYISO stakeholders, the Comprehensive Reliability Planning Process (CRPP) is presently an annual, ongoing process that combines the expertise of the NYISO and its stakeholders to assess and establish the bulk electricity grid's reliability needs and solutions to maintain bulk power system reliability. The first step in the CRPP is the Reliability Needs Assessment (RNA), which evaluates the adequacy and security of the bulk power system over a 10-year Study Period.12 Fuel diversity is identified as a component of risk that the NYISO has determined requires ongoing study and monitoring. Historically, New York has enjoyed system reliability based on a very diverse resource mix of generation in the state, but over the last few years there has been an increasing market shift to natural gas-fired electric generation.
The 2010 RNA indicated that the planned baseline system as studied meets applicable Reliability Criteria for the next 10 years, from 2011 through 2020. As a result, the 2010 RNA, like the 2009 RNA, does not identify any Reliability Needs. Therefore, the NYISO did not initiate a request for market based or regulated solutions. The primary factors for the 2010 RNA's finding of no Reliability Need are reduced econometric forecasts of load growth, increased energy efficiency projections, an increase in planned resources in the 2010 RNA including special case resources (SCR) when compared to the 2009 RNA, and minimal generator retirements over the ten year planning horizon.13
The Department understands the historic market trend toward the construction of natural gas combustion units, effectively increasing natural gas demand, and the recent reduction in forecast electric demand potentially related to the current economic downturn and has taken these factors affecting future natural gas supply and demand into consideration. Considering these factors, the Department has adjusted the proposed emission standards to allow for dual fuel-fired resources with a significant allowance to fire oil. The Natural Gas Assessment contained in the 2009 State Energy Plan concludes that natural gas supplies are expected to remain adequate to meet projected demand, both nationally and for New York.14
Major electric generating facilities subject to Part 251 may be characterized as essential components of the electricity supply system for New York State. In considering the typical or unavoidable on-going operational constraints faced by these emission sources, the Department could not account for the occurrence of any sudden and reasonably unforeseeable events that may create an emergency situation that imperils the continued supply of electricity to residents of New York State. The Department recognizes that an emergency situation may arise with respect to the supply of electrical power, within the meaning of 6 NYCRR Section 201-2.1(b)(12), that requires a regulated emission source to operate in a manner that results in emissions that may contribute to a violation of the applicable emission standard. In that event, the owner or operator of the relevant emission source may be able to rely on the affirmative defense provided in 6 NYCRR Section 201-1.5 and 201-6.6(c). Emergency defense provisions aside, the Department respects the need for black start capacity at power generating stations that would provide start-up power to the station in the case of an area-wide power outage. Although not likely to be of an applicable size threshold or run for a significant length of time, black start units have been considered in calculating the proposed standards, providing ample allowance for the operation of an applicable unit on oil.
CO2 Emission Reduction Objective and Existing Programs
Executive Order 24, issued in 2009, established a goal of the State of New York to reduce GHG emissions from all sources within the State 80 percent below 1990 levels by 2050 (the "80 x 50 goal"). Achieving the 80 x 50 goal will require that close to 100 percent of New York's electricity come from low-carbon sources by 2050. The recently enacted Article 6 of the Energy Law requires the State Energy Plan to include an inventory of GHG emissions and strategies for facilitating and accelerating the use of low-carbon energy sources and carbon mitigation measures. Combined with other existing State programs, Part 251 would help the State to achieve the 80 x 50 goal.
New York State has already taken an important step to meet this significant challenge of reducing CO2 emissions by adopting California GHG emission standards for motor vehicles. These standards are included in New York's existing low emission vehicles (LEV) program to address the adverse climate impacts that GHGs can cause in New York, and globally, if left uncontrolled.
As another measure to mitigate climate change, the Department adopted 6 NYCRR Part 242, CO2 Budget Trading Program. Part 242 is the New York State component of a multistate regional cap-and-trade program known as RGGI. Part 242 and RGGI limit CO2 emissions from new and existing electric generating sources with a nameplate capacity equal to or greater than 25 megawatts (MW). Cap-and-trade programs that target air quality in general, in addition to performance standards, can be effective as demonstrated by the success of the Title IV Acid Rain Program. Furthermore, the State's Renewable Portfolio Standard (RPS) has been expanded so that, by 2015, 30 percent of the electricity in New York will be generated by low carbon-intensity, renewable sources. The expansion of the existing RPS combined with the Energy Efficiency Portfolio Standard (EEPS) will require that 45 percent of the State's electricity needs will be met by energy efficiency and clean, renewable energy generation.
In addition to these existing programs, to mitigate climate change, proposed Part 251 requires that new or expanded major electric generating facilities should meet a standard for CO2 emissions achievable through application of the best system of emission reduction that has been adequately demonstrated and is currently available. Approximately 33 percent of CO2 added to today's atmosphere will remain in the air at 100 years, 22 percent added CO2 will remain at 500 years, and 19 percent added CO2 will remain at 1,000 years.15 Given its long atmospheric lifetime, controlling CO2 emissions from new emission sources is critical to the urgent global need to stabilize atmospheric CO2 concentrations. By imposing emission standards to promote the use of low carbon intensity fuels and encouraging development of capture and sequestration of CO2 emissions from high carbon intensity fossil fuels, the Department is acting in collaboration with other state programs and global efforts to address this significant threat to public health and the environment.
Climate Change and New York State
A naturally occurring greenhouse effect has regulated the earth's climate system for millions of years. Solar radiation that reaches the surface of the earth is radiated back out into the atmosphere as long wave or infrared radiation. CO2 and other naturally occurring GHGs trap heat in our atmosphere, maintaining the average temperature of the planet approximately 50°F above what it would be otherwise. An enhanced greenhouse effect, and associated climate change, results as large quantities of anthropogenic GHGs, especially CO2 from the burning of fossil fuels, are added to the atmosphere.
Since the mid-1700s, atmospheric concentrations of GHGs have increased substantially due to human activities such as fossil fuel use and land use change. Several of these GHGs, including CO2, have very long residence times in the atmosphere and, thus, have a lasting effect on the climate. Concentrations of CO2 have increased approximately 40 percent since the Industrial Revolution and are far higher than at any time in at least the last 650,000 years. There is clear scientific consensus that anthropogenic emissions of CO2 are contributing to the observed warming of the planet.
Scientists have already observed significant warming in New York's climate due in part to increased concentrations of GHGs in the atmosphere. The New York climate has already begun to change, gradually taking on the characteristics of the climate formerly found in the locations south of New York. Since 1970, the Northeast United States has been warming at a rate of 0.5°F per decade. Winter temperatures have risen even faster, at a rate of 1.3°F per decade from 1970 to 2000.16 Observed temperature trends in New York State indicate an average warming trend of 0.58°F per decade from 1970 through 2008. New York State winter temperature increases averaged 1.14°F per decade for the same period.17
In a study performed for New York State, Rosenzwieg et al. used three emissions scenarios assuming various levels of economic growth and intensity of fossil fuel use.. Under these scenarios, projected mean annual temperature changes for seven regions of the State, relative to a 1971-2000 baseline, ranged from +1.5 to 3.0°F by the 2020s, from +3.0 to 5.5°F by the 2050s, and +4.0 to 9.0°F by the 2080s. Projected increases in mean annual precipitation range from 0 to 5 percent in the 2020s to 0 to 15 percent in the 2080s.18
It is clear that climate change, in part due to GHG emissions from New York State, will have long-term, adverse impacts on New York's environment, human health, and economy. Extreme climate events such as heat waves, heavy rainstorms, tropical storms and flooding can significantly impact New York's communities and natural resources and often have disproportionate effects on urban and rural systems.
New York's shoreline will also be adversely affected by climate change. New York has approximately 2,625 miles of coastline including barrier islands, coastal wetlands, and bays.19 The major contributor to sea level rise is thermal expansion and melting of glaciers and ice sheets. Sea level rise along New York's coast line has been averaging 1.2 in. per decade since 1900. Rosenzweig et al. projected additional sea level rise in the State's coastal plain and Hudson estuary of +1 to +5 in. by the 2020s, +5 to +12 in. by the 2050s, and +8 to +23 in. by the 2020s.20 A "rapid ice-melt" scenario, an alternative study method that incorporates observed and longer-term historical melt rates, predicts sea level could rise by approximately 37 to 55 in. by the 2080s.21 These projections were also adopted by the New York State Sea level Rise Task Force.22 Accelerated sea level rise due to global climate change is expected to increase the frequency and magnitude of flood damage and storms. By the end of the 21st century, coastal flood levels currently associated with a 100-year flood could occur approximately four times as often under conservative sea level rise scenarios.23
New York's public water supply may also be stressed by changes in temperature and precipitation. The majority of drinking water is obtained from surface flow, which can be highly variable. A portion of the Northeast, including New York, has experienced drought conditions on six occasions in the last 20 years and several other areas have had situations that required restrictions on water use.24 The New York City water supply comes from a 2,000 square mile watershed area in upstate New York that is greatly influenced by temperature and precipitation levels.25
Lake Erie and Lake Ontario are critical water sources to New York State which would also be threatened by global climate change. New York relies on these Great Lakes for drinking water, hydroelectric power, commercial shipping, and recreation, including boating and fishing. New York State has approximately 331 miles of shoreline along Lake Ontario and approximately 77 miles along Lake Erie.26 Global climate change is likely to lower the water levels of the Great Lakes through increased evaporation. Simulations run by the Canadian Climate Center using the Canadian Climate Center Model project the average water levels will decrease from 1.5 to three feet for the Great Lakes within three decades.27 This could severely affect commercial shipping. Each one inch loss in draft in the Great Lakes shipping channels causes the ships used for inter-lake transportation to lose 270 tons of cargo capacity.28
Agriculture and forests in New York will also be affected by global climate change. The majority of crops grown in New York may be able to withstand a warmer climate with the exception of cold weather crops, such as apples and potatoes which would shift to the north or have reduced growing seasons. These shifts would eventually result in a different crop mix for New York's farmers. Potential change to the hydrologic cycle may also affect crop production. Dairy farmers will also be impacted since milk production is maximized under cooler conditions ranging from 41°F to 68°F.29 New York is the third largest producer of milk in the United States, behind California and Wisconsin, with 12.1 billion pounds of milk produced in 2006.30 During the unusually hot summer in 2005 many New York dairy herds reported declines in milk production of five to 15 pounds of milk per cow per day (an eight to 20 percent decrease).31 In 2007 New York reported approximately $2.38 billion dollars of cash receipts from its dairy industry.32 A loss of milk production efficiency from heat effects could result in the loss of hundreds of millions of dollars annually for New York's dairy industry.
New York State's Adirondack Park is the largest forested area east of the Mississippi and consists of six million acres including 2.6 million acres of state-owned forest preserve.33 The Adirondack Park, one the most significant hardwood ecosystems in the world, is also likely to be threatened by global climate change. Global climate change will affect the forest mix in New York which could change from the current mixed forest to a temperate deciduous forest. Tree species are expected to lose significant area as suitable climate conditions shift northward. These changes will also further impact fish, birds and wildlife as the forest composition changes. Global climate change will also negatively impact New York's maple syrup industry since specific temperature conditions are required in order for the sugar maples to produce sap. It is projected that sugar maple trees will be displaced to the north as the climate changes and temperatures increase. As forest species change, the dulling of fall foliage will likely have a negative impact on regional tourism.34 Distribution of wildlife is also likely to change due to increased temperature and changes in precipitation. Increased surface water temperatures will decrease the habitat for cold-water fisheries including trout and salmon.
Air Quality and Public Health Benefits
As previously stated in the Union of Concerned Scientists Synthesis Report of the Northeast Climate Impacts Assessment (NECIA), under the Higher Emissions Scenario, where the burning of fossil fuels remains unabated, scientific projections of the Northeast climate show an increase in the number of extreme heat days, high humidity, and poor air quality; thus, potentially putting large numbers of people in the region at risk for adverse health effects. The number of days with poor air quality is projected to quadruple in Buffalo and New York City under the Higher Emissions Scenario.
Higher temperatures, resulting from increased levels of GHG emissions, also contribute to conditions that enhance the formation of ground-level ozone. The presence of strong ultra-violet radiation (sunlight), stable air masses, and the presence of ozone precursors such as volatile organic compounds (VOCs) and oxides of nitrogen (NOx) are also required to promote ozone formation. The increased concentrations of ground-level ozone contribute to respiratory illness in children, the elderly, and those with pre-existing illnesses. Higher CO2 concentrations, temperatures, humidity and longer growing seasons may increase pollen quantity and other environmental allergens which in turn may exacerbate asthma. Increased temperature and precipitation levels also produce conditions favorable to the introduction or spread of vector-borne illnesses such as Lyme disease, equine encephalitis, West Nile virus, and other diseases spread by mosquitoes, ticks, and wild rodents.35
Air quality protection programs need to account for the predicted changes in pollution levels and achieve the public health benefits associated with the reduction of CO2 emissions from stationary source categories. According to a 2002 study, the expected health benefits of urban air pollution reductions from climate change mitigation strategies in the New York City area (assuming that they produce an approximately 10 percent reduction in PM10 and ozone concentrations), would be to avoid approximately 9,400 premature deaths (including infant deaths), 680,000 asthma attacks, and 12 million restricted activity days.36 These preliminary results draw attention to the broad range of more immediate air pollution benefits to public health that mitigating GHG emissions can provide. In addition to contributing to global climate change, the burning of fossil fuels contributes to other air quality problems including increases in local concentrations of nitrogen oxides (NOx), mercury, and sulfur dioxide (SO2). In addition to lower CO2 emissions, natural gas combined cycle facilities have lower emissions of NOx, SO2, carbon moNOxide (CO), particulate matter, and mercury. The proposed regulation ensures significant ancillary public health benefits by simultaneously reducing CO2 and other harmful pollutants.
Proposed Rulemaking Justification
Although New York is home to only 0.3 percent of the world's population, it emits 0.9 percent of the world's carbon emissions. The Legislature recognized the need for a regulation targeting reductions in emissions of CO2 from the power sector when it enacted the Power NY Act, and this regulation is fulfilling this statutory directive.
Because there are currently no specific numerical federal CO2 emission standards for stationary sources, many states are taking a proactive stance to develop climate mitigation measures to aid the global effort. By proposing this rule, New York State is joining several other leading states which have already put forth GHG emission performance standards, including California, Washington, Montana, and Oregon, and most recently, Illinois.37
California has established SB 1368,38 which sets an emission performance standard of 1,100 pounds of CO2 per Megawatt-hour for electricity procured by local publicly owned utilities, whether it is generated within state borders or imported from plants in other states. The standard applies to all new long-term electricity contracts after June 30, 2007. The standard was designed to discourage the purchasing of electricity produced from high-emissions sources, whether instate or out-of-state. It will push utilities to rely more on clean sources, including coal with CCS and renewable fuel sources. This will help California to achieve its economy-wide emissions targets.
The Washington State Department of Ecology completed rulemaking39 on June 19, 2008 for the adoption of a statewide Emissions Performance Standard (EPS) established in 2007 as part of a broader legislative package designed to reduce GHG emissions. The EPS became effective on July 19, 2008. The EPS requires base load electricity generation facilities to meet a GHG emission standard of 1,100 pounds of CO2 per megawatt hour. This standard will be reviewed and adjusted every five years to match the average emissions rate of new combined-cycle natural gas power plants. The EPS applies both to new in-state base load electric generation and to out-of-state generation imported under long-term contracts that began on July 1, 2008 or later. The EPS does not apply to permanently sequestered emissions.
On May 14, 2007, Montana Governor Brian Schweitzer signed HB 25,40 adopting a CO2 emissions performance standard for electric generating units in the state. HB 25 prohibits the state Public Utility Commission from approving electric generating units primarily fueled by coal unless a minimum of 50 percent of the CO2 produced by the facility is captured and sequestered. The bill applies only to electric generating units constructed after January 1, 2007.
In 1997, Oregon's House Bill 328341 established CO2 emissions standards for new power plants, and all electricity imported into the state. The standards apply to base load gas plants, non-base load power plants, and non-generating energy facilities that emit CO2. The law requires any new base load gas power plant to reduce net CO2 emissions 17 percent below the most efficient base-load gas plant operating in the U.S. The CO2 emissions standard for a non-base load power plant, regardless of fuel, is a net emissions rate of 0.675 lb CO2/kWh of net electric power output. The Oregon Energy Facility Siting Council issues rules periodically to update the standard, as more efficient power plants are built in other states. This performance standard is based on emissions rate, rather than on a set of emissions characteristics. Under Division 24 of the Council's rules, beginning at OAR 345-024-0500,42 there are specific standards for base load gas plants (0.675 lb CO2/kWh), non-base load (peaking) power plants (0.675 lb CO2/kWh), and non-generating energy facilities that emit CO2 (0.504 lb CO2/horsepower-hour).
More recently, on January 12, 2009, Illinois enacted SB 1987, the Clean Coal Portfolio Standard Law.43 The legislation establishes emission standards for new power plants that use coal as their primary feedstock. From 2009-2015, new coal-fired power plants must capture and store 50 percent of the carbon emissions that the facility would otherwise emit; from 2016-2017, 70 percent must be captured and stored; and after 2017, 90 percent must be captured and stored.
A wide range of technologies and practices, including increased energy efficiency, fuel switching to less carbon intensive fuels, and power recovery, have the potential to reduce CO2 emissions.44 Natural gas, for example, is a less carbon intensive fuel than coal, with reduced emissions of CO2 and criteria and hazardous air pollutants. This rulemaking promotes the use of less carbon intensive fuels and more efficient technologies in applicable new or expanded major electric generating facilities in New York. As previously emphasized, these sources have the potential to emit substantial amounts of CO2 during operating lifetimes of 50 years or more. Therefore, in order to achieve necessary reductions, it is imperative that these sources reduce CO2 emissions to the lowest extent practicable using existing technology.
Electric generating units with a nameplate capacity equal to or greater than 25 MW in New York State will also have to purchase CO2 allowances to operate under 6 NYCRR Part 242, CO2 Budget Trading Program (RGGI). Under proposed Part 251, new emission sources with reduced CO2 emissions will likely need to purchase fewer CO2 allowances for compliance allowing for potential electric generation growth under the RGGI cap. The performance standards of proposed Part 251 ensure that new generation occurs in a manner consistent with the overall goal of reducing emissions contributing to climate change. A CO2 performance standard for power plants, such as that in Part 251, does not preclude the adoption of other policy measures, such as a cap-and-trade program, to reduce power plant GHG emissions. In fact, a performance standard approach actually works in harmony to effectively achieve the most rapid and substantial CO2 emission reductions from both new and existing plants.45
Potential Impacts on Electricity Prices and Reliability
The U.S. Department of Energy (DOE) and the National Energy Technology Laboratory (NETL) published a report comparing the baseline capital costs and levelized costs of electricity of pulverized coal and natural gas combined cycle facilities. The levelized cost of electricity is a measurement of the fuel-to-busbar cost of power and includes total plant costs, fixed and variable operating costs and fuel costs levelized over a 20-year period. The report shows that a newly installed pulverized coal plant (i.e., wet scrubber, selective catalytic reduction [SCR], fabric filtration, low oxides of nitrogen [NOx] burners) would have a near similar cost of electricity when compared to a natural gas-fired combined cycle plant. The cost of electricity should therefore not increase substantially as a direct result of this proposed regulation and the cost to the consumer should not increase significantly regardless of plant design and primary fuel type selected. Also in the DOE/NETL study, CCS cost scenarios were calculated for the two base combustion installation cases. New coal-fired generation would be required to apply CCS technology to meet emission standards set forth in this proposed rulemaking. Levelized costs of electricity for any unit type, including coal-fired generation, will increase significantly if CCS is implemented for control of CO2.46
No new coal- or oil-fired electric generation emission sources are expected to be constructed in New York in the near future, regardless of whether or not the Department ultimately adopts Part 251. If, however, such a new unit is proposed, it would have to apply 50 to 60 percent CCS technology for coal-fired emission sources and 33 to 40 percent CCS technology for oil-fired emission sources to comply with the proposed emission standards in Part 251. The required application of CCS technology would create a significant increase in capital and operation costs when compared to base coal or oil plants without CCS technology, as discussed below.
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. The New York State Public Service Commission's (PSC) Renewable Portfolio Standard (RPS) goal is 30 percent of New York's electricity from renewable sources by year 2015. An introduction of increased wind, hydro and solar power capacity in the state will provide for lower CO2 emissions while providing power with a lower associated cost of electricity. A greater resource mix of renewable energy sources will also help curb a demand increase in natural gas. Photovoltaic systems can generate electricity with little maintenance and no direct emissions. Currently the cost of photovoltaic systems is substantial when compared to other bulk electric generating systems on a $/kW basis. However, photovoltaic systems may have greater benefit on smaller scale applications to assist in demand reduction and the offsetting of electric generation from fossil fuel-fired sources, further reducing electric generation CO2 emissions. Moreover, as new gas-fired combined cycle units replace less efficient existing natural gas-fired units, the demand for pipeline natural gas will decrease. Finally, the PSC's EEPS goal is to reduce electric usage by 15 percent of projected levels by 2015. Addressing demand for natural gas, the PSC established near- and long-term targets for gas efficiency designed to significantly reduce the amount of gas used by residential and business consumers over the planning horizon, establishing a target that will result in a 14.7 percent reduction in natural gas usage by 2020, independent of any fluctuations in usage caused by fuel-switching or other economic factors.47
Regional Greenhouse Gas Initiative (RGGI) Modeling Predictions
The proposed CO2 emission standards should create an incentive for the development of energy efficiency measures, renewable energy resources, and advanced CO2 reduction technology. However, for the foreseeable future, many new or expanded power plants will rely primarily on natural gas. In an effort to understand the potential impact of limiting high intensity carbon fuels as a future fuel source, the Department reviewed the modeling used to evaluate the costs and impacts of RGGI.
The State and the other RGGI participating states conduct electricity sector modeling using the Integrated Planning Model (IPM) to support program decision making. RGGI participating states recently updated their modeling analyses in preparation for RGGI Program Review. Under the Reference Case, also sometimes referred to as the Business as Usual (BAU) case, the RGGI program continues unchanged, and other existing regulations, programs, economic conditions, relative fuel prices, electricity demand, planned capacity additions and retirements, and various other factors are taken into account. The RGGI Reference Case projects that, even under a BAU scenario, new electricity generation in the State over the next decade will be primarily in the form of natural gas-fired facilities and wind facilities.
Specifically, the RGGI modeling predicts that, under the BAU case, 5,517 new MW of new total capacity will be added in the State between 2011 and 2020. Such new capacity additions in the State are projected to be primarily in the form of natural gas-fired combined cycle plants, as well as onshore wind turbines. No new capacity additions are projected to be in the form of coal-fired or oil-fired facilities during the 2011 through 2020 period. Likewise, under the RGGI Reference Case, net electricity generation from natural gas-fired combined cycle facilities is projected to increase, as is net electricity generation from wind-powered facilities. In particular, electricity from natural gas-fired combined cycle plants is projected to increase from 38,903 GW-hr in 2011 to 51,141 GW-hr in 2020, while onshore wind facilities are projected to produce 6,247 GW-hr of electricity in 2020 as compared to 882 GW-hr in 2011. On the other hand, under the Reference Case, net electricity generation from other types of facilities - including oil-fired facilities and coal-fired facilities - is projected to either decrease or stay roughly the same between 2011 and 2020 in the State.
Notably, the RGGI modeling assumes, as a baseline condition, that all new fossil fuel-fired capacity is projected to be provided by combined cycle natural gas-fired units, which can readily meet the proposed standard. Additional factors, independent of this rule, make it less likely that new coal-fired plants will be permitted in New York. First, RGGI raises the costs of operating a coal-fired unit more than a gas-fired unit, as costs are be based on carbon emissions. Second, economic considerations, including the relative price of natural gas, mean that new coal-fired facilities are already unlikely to be built in the State. Third, other regulations, including federal regulations for criteria pollutants and potential forthcoming federal regulations of GHG emissions from power plants, may already make new coal-fired facilities impractical in the State. As a result, banks and other financers are becoming increasingly reluctant to fund the construction of coal-fired plants that are not equipped with CCS equipment. Therefore, the application of this regulation to proposed new plants should not have any impact on electricity prices. In the New York deregulated electricity market, natural gas generators currently operating generally set the marginal market price of electricity.
Carbon Capture and Sequestration Costs
New natural gas-fired units will be able to meet the proposed emission standards and thus will not have to contend with CCS technology. Currently, CCS is the only source control technology that could potentially control CO2 emissions for facilities that, because of fuel choice like oil or coal, cannot meet the proposed standards. This technology, however, has not yet been implemented at full-industrial and power generating applications. CCS technology is projected to add significantly to the cost of construction and operation of new coal- or oil-fired electric generating facilities and ultimately, this expenditure would be anticipated to be passed along as increased electricity costs for the end user. There is also an energy penalty associated with CCS due to reduced efficiency as CCS is incorporated into plant design.48
A DOE/NETL report summarizing numerous study scenarios affecting cost of electricity compares baseline (no CCS installed) facility costs and operation and maintenance to those where CCS had been installed. Baseline costs for pulverized coal sources without CCS installed ranged from 63.3 to 64 dollars per MW-hr. The baseline costs for natural gas fired combined cycle facilities was reported to be 68.4 dollars per MW-hr. The addition of CCS will increase the cost of electricity from pulverized coal sources by approximately 86 percent. This increase would raise the pulverized coal electricity production cost to as much as 119 dollars per MW-hr.49 In other words, for example, based on an approximately 86 percent increase in the cost of electricity, the cost of pulverized coal electricity production from a 100 MW coal-fired facility would increase by approximately $48.1 million. This is based on an assumption that a facility would be operating 100% of the time at its nominal capacity, and would mean that the cost of such electricity production would increase from approximately $56.1 million to approximately $104.2 million, as a result of adding CCS.
Moreover, the United States Energy Information Administration (EIA) projects current and future costs of new electricity generation capacity. EIA updates its cost and performance assumptions annually, as part of the development cycle of the 'Annual Energy Outlook'. A recent update by EIA projects, for example, that a new 650 MW capacity single unit advanced pulverized coal plant would cost $3,167/kW in capital costs without CCS, as compared to $5,099 with CCS. Fixed operation and maintenance costs for such a plant are projected to be $35.97/kW without CCS, compared to $76.62/kW with CCS. This translates to a capital cost of over $2 billion for a new coal-fired plant without CCS, and of over $3.3 billion with CCS (an increase of approximately $1.3 billion in capital costs as a result of adding CCS). The additional fixed operation and maintenance costs would be approximately $26.4 million under this scenario as a result of the addition of CCS. Similarly, as another example, a new 1,300 MW capacity dual unit advanced pulverized coal plant would cost $2,844/kW in capital without CCS, and $4,579/kW in capital costs with CCS. This translates to a capital cost of approximately $3.7 billion for a new dual unit coal-fired facility without CCS, and of over $5.9 billion for the same facility with CCS (an increase of approximately $2.2 billion in capital costs as a result of adding CCS). The additional fixed operation and maintenance costs would be approximately $43.6 million under this scenario as a result of the addition of CCS.50
Costs to the Regulated Community
The Department has determined that new combined cycle combustion turbines (with up to 45 days of oil firing capability), new natural gas-fired boilers, and new natural gas-fired stationary internal combustion engines can meet the presumptive CO2 emission standard of 925 lbs/MW-hr or 120 lbs/mmBtu without controls. The Department has also determined that new oil-fired simple cycle combustion turbines and new oil-fired stationary internal combustion engines can meet the CO2 emission standard of 1450 lb/MW-hr without controls. This is also true for expansions at existing facilities that increase capacity by at least 25 MW, and that utilize the equipment and fuel listed above. Therefore, for members of the regulated community 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 of 925 lbs/MW-hr or 120 lbs/mmBtu without the installation of controls (such as CCS). As described above, 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 925 lbs/MW-hr or 120 lbs/mmBtu 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 925 lb/MW-hr or 120 lbs/mmBtu 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. In other words, while the initial capital cost of a new coal-fired plant depends on a variety of factors, including the nominal capacity of the plant and the type of equipment, this means that the capital cost of building a new coal-fired plant with CCS may be as much as double the capital cost of building the same new coal-fired plant without CCS. As stated above with reference to projections made by EIA, this could mean, for example, an increase in capital cost of $1.3 billion for a new 650 MW single unit advanced pulverized coal plant, as a result of adding CCS. As stated above, 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, for example, at least $50 million per year increase in maintenance and operations costs for a 100 MW coal-fired boiler. New oil-fired projects will likely have similar 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, similar to the federal NSPS rules. Provided that a proposed project utilizes such modern and efficient equipment, and proposes and meets a CO2 emission limit approved by the Department, then the cost of this regulation for such a facility will be zero.
Proposed projects that do not utilize the maximum degree of CO2 emission reduction or operating efficiencies will not be approved by the Department. The Department is unsure of the cost implications for such emission sources required to meet the case-by-case requirement, given the uncertainty of the fuel types projected for use in these emission sources, the potential different types of sources that may be proposed, and the complexity of the science used to determine their impact on climate change. In any case, because the Department's case-specific CO2 emission limit will be largely based on existing control technologies and operating efficiencies already installed or used in practice on existing emission sources, the Department believes that the cost increase for emission sources subject to the case-by-case CO2 emission limit will be minimal. However, this will depend in part on the future determinations of the impacts of these fuels, and firing configurations, on climate change. Finally, for proposed projects subject to a case-specific emission limit and that propose to derive greater than 50 percent of the heat input from solid fossil fuel or oil, additional costs may be similar to that described above for new coal-fired and oil-fired facilities that employ CCS.
The costs associated with CO2 compliance for other dual-fuel sources would be partially based on changing fuel prices and the cost differential between a preferred fuel and that blend of fuels required to meet the proposed emission standards. Natural gas has been trending to a lower cost compared to distillate fuel oil and forecasts project a continued future lower cost.51 A facility owner would select natural gas not only for Part 251 compliance considerations, but more specifically for a reduction in variable operation costs at the source level.
Facilities subject to this Part will be required to meet a 12-month rolling average CO2 emission standard. They are also required to meet regulatory requirements for other regulated pollutants (e.g., a limit for emissions of SO2 and/or NOx). To demonstrate compliance with other applicable regulations already in place, via federal monitoring requirements contained within 40 CFR Part 75, both a CO2 continuous emission monitoring system (diluent monitor) and a fuel flow monitor would have been installed. Thus, as monitoring equipment is generally already required by other existing regulations, there will be no additional costs incurred to demonstrate compliance with the proposed CO2 standard. Newly subject sources will have standard operating expenses associated with operating permit requirements, including provisions for recordkeeping, monitoring and reporting necessary to demonstrate compliance with this rule.
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 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 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, but it is not expected to be unduly burdensome. 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. 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, or that are considering proposing projects that may be subject to the regulation. The Department is not currently aware of any proposals for new or expanded facilities that would be subject to Part 251 and that would be owned or operated by a local government. 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. As described above, however, Part 251 is unlikely to prevent any operational changes, efficiency increases, or other changes to an existing facility that do not increase emissions from the existing facility.
With the promulgation of Part 251, consideration must be made by local governments when deciding to install or expand power generation that would be subject to the rule, so that the design and fuel choice aligns itself with proposed rule requirements for the emission of CO2. Such consideration will be the same for local governments that own or operate a subject source as it will be for other entities that own or operate a subject source. Provided that the proposed facility is of a type that would meet the relevant CO2 emission limit in Part 251, then Part 251 will not impose any additional costs. Parameters and items to be considered (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.
Most 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 twelve 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 described above, as a result of several actions by EPA, GHGs, including CO2, became "subject to regulation" under the Act as of January 2, 2011. EPA modified the relevant applicability thresholds for GHGs for purposes of PSD and Title V permitting under the Act in the GHG Tailoring Rule. 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 BACT 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. Thus, while the applicability provisions are separate and not identical, a source that is subject to Part 251 may also be subject to BACT for GHGs under the PSD permitting program. While BACT is established on a case-by-case basis for each particular source pursuant to an established top-down review process, 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.
While stationary sources may be subject to Title V and PSD permitting requirements for GHGs under the Act, there are currently no specific CO2 emission standards for stationary sources in the federal regulations. Therefore, because there currently is no federal standard, the proposed Part 251 CO2 emission performance standards are more stringent than the current federal standards. Pursuant to ECL Section 19-0312, the Department is required to promulgate a regulation targeting reductions in CO2 emissions from major electric generating facilities by August 4, 2012. Therefore, postponing or deferring regulation of CO2 emissions from major electric generating facilities until additional federal rules are adopted is not an available option to the Department. Moreover, any additional delay may result in increased CO2 emissions due to new carbon-intense power generation being built in New York State. The proposed Part 251 standards are protective of public health and the environment in the absence of similar federal emission standards. The potential adverse impact to global air quality and New York State's environment from CO2 emissions necessitates that New York State take action now to halt the increase in CO2 emissions that contribute to climate change.
Finally, it should be noted that EPA is committed, pursuant to a litigation settlement, to propose an NSPS for GHG emissions from power plants. According to the settlement, EPA will propose both an NSPS for new sources under Section 111(b) of the Act, and an NSPS for existing sources under Section 111(d) of the Act. Thus, if and when EPA ultimately adopts a GHG NSPS for power plants, it would likely apply both to new sources of the type that will be subject to Part 251, as well as to existing sources that may not be subject to Part 251. The Department will continue to monitor the development of power plant GHG NSPS by EPA. The Department's current understanding is that EPA plans to propose a GHG NSPS rule in early 2012, with a regulation final by early 2013.
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 its 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. Pursuant to Article 19 of the ECL, Part 251 will be effective thirty days after its filing with the Department of State.
1 Frumhoff, P.S., J.J. McCarthy, J.M. Melillo, S.C. Moser, and D.J. Wuebbles. 2007. Confronting Climate Change in the U.S. Northeast: Science, Impacts, and Solutions. Synthesis Report of the Northeast Climate Impacts Assessment (NECIA). Cambridge, MA: Union of Concerned Scientists (UCS).
2 Rosenzweig, C., W. Solecki, A. DeGaetano, M. O'Grady, S. Hassol, P. Grabhorn (Eds.). 2011. Responding to Climate Change in New York State: The ClimAID Integrated Assessment for Effective Climate Change Adaptation. Technical Report. New York State Energy Research and Development Authority, Albany, NY.
3 Endangerment and Cause or Contribute Findings for Greenhouse Gases Under Section 202(a) of the Clean Air Act, 74 FR 66496, December 15, 2009.
4 Prevention of Significant Deterioration and Title V Greenhouse Gas Tailoring Rule, 75 FR 31514, June 3, 2010.
5 According to the EPA, biogenic CO2 emissions are defined as CO2 emissions directly resulting from the combustion, decomposition, or processing of biologically based materials other than fossil fuels, peat, and mineral sources of carbon through combustion, digestion, fermentation, or decomposition processes. EPA is developing an assessment framework for biogenic CO2 emissions from stationary sources. See 75 FR 41173 (July 15, 2010).
6 AP 42, Fifth Edition Compilation of Air Pollutant Emission Factors, Volume 1: Stationary Point and Area Sources
7 Secretary Chu Announces Two New Projects to Reduce Emissions from Coal Plants, U.S. DOE press release, July 1, 2009.
8 DOE Establishes National Carbon Capture Center to Speed Deployment of CO2 Capture Processes, May 27, 2009, http://www.netl.doe.gov/publications/press/2009/09034-National_Carbon_Capture_Center_Est.html.
9 See Final Rule for Federal Requirements Under the Underground Injection Control (UIC) Program for Carbon Dioxide (CO2) Geologic Sequestration (GS) Wells. Nov. 22, 2010, http://water.epa.gov/type/groundwater/uic/upload/pre-FR_class6_2010-11-22.pdf. See also Federal Requirements Under the Underground Injection Control (UIC) Program for Carbon Dioxide (CO2) Geologic Sequestration (GS) Wells, 73 FR 43, 491 (July 25, 2008) (proposal); Federal Requirements Under the Underground Injection Control (UIC) Program for Carbon Dioxide (CO2) Geologic Sequestration (GS) Wells; Notice of Data Availability and Request for Comment, 74 FR 44802 (Aug. 31, 2009) (supplemental publication).
10 Montana Governor Signs Carbon Dioxide Storage Bill, by Charles S. Johnson, May 6, 2009, http://www.greatfallstribune.com.
11 See Pollak, Melisa F. and Elizabeth J. Wilson, Regulating Geologic Sequestration in the United States: Early Rules Take Divergent Approaches, University of Minnesota Center for Science, Technology, and Public Policy, March 30, 2009, available at: http://pubs.acs.org/doi/pdf/10.1021/es803094f.
12 NYISO, 2010 Comprehensive Reliability Plan, Final Report, January 11, 2011.
14 Natural Gas Assessment, New York State Energy Plan 2009. December 2009 (http://www.nysenergyplan.com/final/Natural_Gas_Assessment.pdf) 15 Figure 9(a). Carbon Cycle Constraints (a) Decay of Pulse CO2 Emissions, Hansen, J. et al. (46 co-authors). Dangerous human-made interference with climate: a GISS ModelE study, Atmos. Chem. Phys., 7, 1-26, 2007b.
16 Frumhoff et al., July 2007, Confronting Climate Change in the U.S. Northeast: Science, Impacts and Solutions, http://www.climatechoices.org/assets/documents/climatechoices/confronting-climate-change-in-the-u-s-northeast.pdf
17 Rosenzweig et al, p. 22.
18 Rosenzweig et al. pp27-29.
19 National Oceanic and Atmospheric Administration (NOAA). Treasure Our New York Coasts and Estuaries. June 2003. p. 1.
20 Rosenzweig et al., p. 33.
21 New York City Panel on Climate Change (NPCC). Climate Risk Information. February 17, 2009.
22 New York State Sea Level Rise Task Force. 2010. Report to the Legislature. www.dec.ny.gov/docs/administration_pdf/slrtffinalrep.pdf
23 Rosenzweig et al. p. 35
24 NAST. Page 119.
25 Ibid. Page 123.
26 Michigan Department of Environmental Quality: Shorelines of the Great Lakes. http://www.michigan.gov/deq/0,1607,7-135-3313_3677-15959B,00.html.
27 Slivitzky, Michel and Limno-Tech, Inc. Ecological Impacts of Water Use and Changes in Levels and Flows. June 2002. Page 11.
28 Climate Change and Water Quality in the Great Lakes Basin 2003: Report of the Great Lakes Water Quality Board to the International Joint Commission. Chapter 3.2, page 18.
29 Garcia, Alvaro. Dealing with Heat Stress in Dairy Cows. South Dakota Cooperative Extension Service. September, 2002. Page 1.
30 Milk Production, Disposition and Income: 2007 Summary, at p. 4, United States Department of Agriculture, National Agricultural Statistics Service, April 2008, available at http://usda.mannlib.cornell.edu/usda/current/MilkProdDi/MilkProdDi-04-25-2008.pdf.
31 Frumhoff, Peter. Confronting Climate Change in the U.S. Northeast: Science, Impacts, and Solutions, Northeast Climate Impacts Assessment, July 2007, p. 69.
32 Milk Production, Disposition and Income: 2007 Summary, at p. 9.
33 New York State Adirondack Park Agency (APA), http://www.apa.state.ny.us/About_Park.
34 NAST. Page 125.
35 National Assessment Synthesis Team (NAST), 2001: Climate Change Impacts on the United States, the Potential Consequences of Climate Variability and Change. Page 450.
36 Cifuentes, L., Borja-Aburto, V.H., Gouveia, N., Thurston, G., Davis, D.L. 2001. Assessing the health benefits of urban air pollution reduction associated with climate change mitigation (2000-2020): Santiago, Sao Paulo, Mexico City, and New York City. Environmental Health Perspectives, Vol. 109, Supplement 3: 419-425.
37 United States Environmental Protection Agency (EPA). EPA Climate Change. State Power Sector Table at http://www.epa.gov/climatechange/wycd/stateandlocalgov/state_power_sec.html. See also, Rubin , Edward S., A Performance Standards Approach to Reducing CO2 Emissions from Electric Power Plants, Prepared for the Pew Center on Global Climate Change, Carnegie Mellon University, June 2009, available at: http://www.pewclimate.org/docUploads/Coal-Initiative-Series-Rubin.pdf.
44 Bernstein, L et al. (2007). Industry in Climate Change 2007: Mitigation. Contribution of Working Group III to the Fourth Assessment Report of the Intergovernmental Panel on Climate Change [B. Metz, O.R. Davidson, P.R. Bosch, R. Dave, L.A. Meyer (eds)], Cambridge University Press, Cambridge, United Kingdom and New York, NY, USA.
45 Rubin, Edward S. A Performance Standards Approach to Reducing CO2 Emissions from Electric Power Plants, prepared for the Pew Center on Global Climate Change, Carnegie Mellon University, June 2009, available at: http://www.pewclimate.org/docUploads/Coal-Initiative-Series-Rubin.pdf.
46 U.S. Department of Energy and the National Energy Technology Laboratory (DOE/NETL). (May 2007). Fossil Energy Power Plant Desk Reference: Bituminous Coal and Natural Gas to Electricity Summary Sheets (DOE/NETL-2007/1282).
47 Order Establishing Targets and Standards for Natural Gas Efficiency Programs, NYS Public Service Commission May 14, 2009, (EEPS Proceeding, Case 07-M-0548).
48 Bergerson, J. and Lave, L. (2007) The long-term life cycle private and external costs of high coal usage in the U.S. Energy Policy 35: 6225-6234.
49 U.S. Department of Energy and the National Energy Technology Laboratory (DOE/NETL). (May 2007). Fossil Energy Power Plant Desk Reference: Bituminous Coal and Natural Gas to Electricity Summary Sheets (DOE/NETL-2007/1282).
50 U.S. EIA, Updated Capital Cost Estimates for Electricity Generation Plants, November 2010, Table 1 on p. 7, available at: http://www.eia.gov/oiaf/beck_plantcosts/pdf/updatedplantcosts.pdf.
51 DRAFT SEP 2009, Energy Price Reference Forecasts by Fuel Type, Tables 1 - 12