Source: http://www.dec.ny.gov/regulations/82876.html
Timestamp: 2013-05-19 19:29:11
Document Index: 637444857

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Assessment of Public Comments 6 NYCRR Parts 251 and 200 - NYS Dept. of Environmental Conservation
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Comments received from January 18, 2012 through 5:00 P.M., March 15, 2012
Environmental Energy Alliance of New York, LLC:
Comment 1: The Alliance recognizes that legislative requirements have forced the schedule for this rule-making. Nonetheless, we have to point out that emission limits for boilers in this rule are at odds with the DPS Article Ten rulemaking and the existing NYS Energy Plan. In particular, rule precludes the use of coal and oil without carbon capture and sequestration and the Regulatory Impact Statement explicitly states "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." However, no reference for this State policy is provided and this is contrary to the stated objective of the 2009 NYS Energy Plan that describes the importance of fuel diversity as follows:
The State has a diverse mix of electricity generation sources, including coal, nuclear, hydropower, oil, gas and renewables. Statewide, fuel diversity safeguards against fuel supply disruptions and other factors which could pose reliability risks and/or cause significantly increased price levels and volatility. It is important to continue safe operation of nuclear, coal, natural gas, oil, and hydroelectric generation resources in ways that support the State's energy, environmental and economic objectives.
Response: The Department respectfully disagrees with the commenter's assessment that this regulation is not consistent with State's Energy Plan and that it eliminates fuel diversity. The commenter is correct in the assumption that new coal or oil will have to control carbon dioxide (CO2) emissions to operate in compliance with this regulation, but the regulation does not specifically ban or preclude the use of these or any other fuels. The regulation allows for fuel and fuel burning equipment diversity (including boilers and turbines firing natural gas, distillate oils, and other fuels like wood, renewables, and waste), as well as generation diversity like wind, water, nuclear, fossil fuels, other renewables, and wood. Therefore, the Department believes that this regulation supports the State's energy, environmental, and economic objectives.
Comment 2: The regulatory impact statement states "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". However, Alliance members have calculated the potential number of days on oil-firing with a variety of emission factors and cannot reproduce that estimate. In order to preserve the reliability driven ability to operate on oil and to account for some degradation of the systems over time, the Alliance proposes changing the limits from 120 lbs CO2 per mmBtu to 125 lbs CO2 per mmBtu and from 925 pounds of CO2 per MW hour gross electrical output to 960 pounds of CO2 per MW hour gross electrical output.
Response: The above-referenced number of days that natural gas-fired combined cycle turbines could fire distillate oil as back-up was based on the average emission rates from nationwide proposed projects. As set forth in the Regulatory Impact Statement (RIS), in addition to allowing for an appropriate level of backup oil-firing, the emission limits in Part 251 allow for appropriate flexibility in order to recognize the potential for other reliability issues, or technical or operational constraints. In addition to the level of the emission limit, the use of a 12-month rolling average calculation provides flexibility for factors such as the impact of potentially frequent periods of start-up and shut-down, and the ability to choose between an input-based limit or an output-based limit also adds flexibility. Therefore, the Department believes that the limits established in Part 251, along with attendant provisions that provide regulated entities with appropriate flexibility, adequately cover the normal operating scenarios for natural gas-fired (with distillate oil back-up) combined cycle combustion turbines and do not need to be raised.
Comment 3: The New York State Administrative Procedure Act requires the preparation of a Regulatory Impact Statement (RIS) that must include a statement of needs and benefits of the proposed Part 251 regulation. This RIS inadequately assesses the effect of the program to potential benefits and presents a biased description of the needs of the program.
Response: The Department respectfully disagrees with the commenter's suggestions that the RIS inadequately assesses the effect of the regulation and presents a biased description of the needs of the program. As required by the State Administrative Procedure Act (SAPA), the RIS contains a statement of the needs and benefits of Part 251. As discussed in the RIS, this regulation must be promulgated pursuant to statute, specifically Environmental Conservation Law (ECL) Section 19-0312. Moreover, while the needs and benefits section of the RIS focuses on the purposes and necessity of Part 251, and the benefits to be derived from the regulation, the RIS also includes a statement detailing the projected costs of the regulation.
Comment 4: The Regulatory Impact Statement (RIS) inadequately assesses the effect of the program to potential benefits. The sections on CO2 Emission Reduction Objective and Existing Programs, Climate Change and New York State, Air Quality and Public Health Benefits on one hand detail the threats of a changing climate but never tie the explicit difference of the expected change in emissions of the proposed program to the potential impact on climate. For example the justification states "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" but the RIS does not mention that in 2009 only 19 percent of the New York carbon emissions came from the Electric Generation sector. In order to be done correctly the RIS should estimate just how much the proposed program would be expected to reduce New York carbon emissions. There also is a disconnect in the emissions scenario discussions because the reports cited are evaluating global emissions scenarios not New York State emission scenarios. If we estimate the global warming potential of CO2 emissions based on 50 years of emissions and temperature changes, it takes about 1,767,250 million metric tons of CO2 emissions to raise the global temperature 1°C. In 2009, NYSERDA reports that the electric generation sector emitted 37.8 million metric tons of carbon dioxide equivalent. The fact of the matter is that this program will not have a measurable impact on global or regional climate impacts because 2009 New York electric sector total emissions only have a global warming potential of 0.00002°C and the program does not propose to completely eliminate CO2 emissions.
Response: The Department respectfully disagrees with the commenter's suggestion that the RIS inadequately assesses the effect of the program to potential benefits. The regulation will serve to further minimize the State power sector's contribution to atmospheric concentrations of greenhouse gases (GHGs). Part 251 establishes a minimum performance standard for CO2 emissions as a threshold requirement for facilities subject to Public Service Law Article 10 (Article 10). 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.
Comment 5: The benefits analysis also has an inadequate discussion of public health benefits. Citing results from a non-peer reviewed analysis from an advocacy organization is inappropriate. There also is an inconvenient difference between public health data and emissions and air quality trends relative to the projected health benefits cited. The RIS cites a report that claims a number of public health benefits projected for an assumed 10 percent reduction of ozone and PM-10 concentrations based on a health outcomes model. It presumes that there will be a carbon price of $56 per ton and that a ten percent reduction in PM and O3 will result from the resulting carbon emission reductions. The paper also attempts to correlate the benefits associated with emission reductions in NY City with similar reductions in Mexico City, Santiago and Sao Paulo.
However, observed data do not show the modeled effect. According to the CDC, "Among persons of all ages, the prevalence of asthma increased from 7.3 percent (20.3 million persons) in 2001 to 8.2 percent (24.6 million persons) in 2009, a 12.3% increase." According to the EPA ambient air quality data:
"Nationally, annual PM2.5 concentrations were 24 percent lower in 2010 compared to 2001. 24-hour PM2.5 concentrations were 28 percent lower in 2010 compared to 2001."
"Ozone levels did not improve in much of the East until 2002, after which there was a significant decline. 8-hour ozone concentrations were 13 percent lower in 2010 than in 2001. This decline is largely due to reductions in oxides of nitrogen (NOx) emissions required by EPA rules including the NOx State Implementation Plan (SIP) Call, preliminary implementation of the Clean Air Interstate Rule (CAIR), and Tier 2 Light Duty Vehicle Emissions Standards."
According to the NYS Ambient Air Monitoring Program Network May 2010 Assessment "annual average PM2.5 mass in the South Bronx was approximately 25 percent lower in 2009 compared to the average from 2002-2007". The statewide average of second highest one hour ozone values also appears to show a reduction of at least 10 percent between 2003 when the concentration was 0.12 ppm and the latest values. Clearly using national numbers as "proof" that there isn't a link is an over-simplification but if New York public health data suggest improvements commiserate with New York observed air quality improvements then there is justification to make further reductions to electricity sector emissions. Without that analysis we are left to wonder whether the cited paper accurately portrays the potential health effects. At some point air quality regulatory analyses are going to have to compare measured ambient air quality trends to observed public health trends because this kind of cursory comparison suggests the possibility that the health outcome models are not verifying with observations.
Response: The Department respectfully disagrees with the commentor's assessment that the benefits analysis has an inadequate discussion of public health benefits. Part 251 establishes an emission performance standard for CO2, and does not alter existing requirements for other pollutants, including criteria contaminants. In any case, requiring more efficient fuel burning equipment will reduce fuel usage throughout the State. Firing less fuel will reduce all of the pollutants generated in a combustion process including criteria contaminants like NOx, PM, PM-10, PM2.5, VOC, and SO2 as well as GHGs.
Comment 6: The RIS states "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." As shown above the "in part due to GHG emissions from New York State" is at best disingenuous because the potential change in temperatures due to New York is so small that it cannot be measured so surely any impacts also would be of the same relative magnitude. The RIS implicitly suggests that observed warming is already having an adverse impact on New York and cites a litany of potential impacts. In response to that I have attached an analysis by Dr. Craig Loehle, who gave me permission to submit his comments for your consideration. He is a research scientist with 135 peer-reviewed publications currently working for NCASI which does research for the wood products industry. Based on this analysis, within the United States, the claim that bad climate effects can "already" be detected is a totally subjective and unsupported hypothetical statement.
Response: The Department respectfully disagrees. GHG emissions, including those from New York State, contribute to increased atmospheric concentration of GHGs. The worldwide increase in atmospheric concentrations of GHGs is causing climate change, and the related adverse impacts described in the RIS are already being felt. Climate change effects are in fact already being observed in New York State, including annual average temperatures have risen about 2.4 °F since 1970, with winter warming exceeding 4.4 °F; sea level along New York's coastline has risen about a foot since 1900; and intense precipitation and heavy downpours have increased in recent decades.
As these climate trends continue, the number and duration of extreme heat events will increase with increased heat-related illness and deaths; short-term droughts will become more frequent with reduced summer flows and lowered groundwater leading to water-use conflicts and lost agricultural and forest productivity from temperature stress; coastal flooding associated with sea level rise is very likely to increase resulting in permanent inundation of low lying areas, increased beach erosion, reduction of coastal wetland area and species, and flood events that are more frequent and more destructive to ecosystems, communities, and infrastructure.1
IPPNY:
Comment 7: During the stakeholder process on the development of this regulation, the DEC expressed a willingness to consider an alternative standard for a combined-cycle facility that cycles (starts and stops) on a daily basis or if the facility provides regulation service to support intermittent facilities. The DEC said it would look at having a separate emissions limit for start-up and shut-down periods, to be measured based upon a 12-month rolling average. The DEC also said that it would look at this issue and may decide that this area could be addressed better under Part 231. The DEC expressed a willingness to look at including bubbling or system averaging such as under the NOx RACT Rule, especially to provide flexibility during start-up and shut-down. The DEC thought that perhaps averaging could be done with facilities that are newly constructed after the effective date of the regulation.
Response: The Department determined that the 12-month rolling average, in addition to the level of the standard other elements described above in response to comment no. 2 and in the RIS, was sufficient to address periods of start-up and shutdown. In other words, the Department believes that the regulation already provides for these modes of operation, and that a system averaging approach or other methods were not needed to deal with these modes of operation.
Comment 8: Also, it is IPPNY's understanding that the DEC intends that the 12-month rolling average basis for the emission limit also account for the emissions that result during start-up and shut-down periods due to cycling requirements. In regards to the treatment of start-up and shut-down, Part 231 states that: "The average rate includes ... emissions associated with startups, shutdowns, and malfunctions." IPPNY urges the DEC to amend the draft regulation to include more specific language clarifying that flexibility would be provided for facilities that start-up and shut-down due to necessary cycling as part of meeting the electricity system's operational requirements.
Response: All emissions from the facility, including those that result during start-up and shut-down periods due to cycling requirements or other situations, must be included in the 12-month rolling average calculation. As explained above in response to comment no. 2, the Department believes that the use of the 12-month rolling average in conjunction with other elements of the rule already provide for the appropriate level of flexibility. The Department believes that the emission limit for combined cycle combustion turbines, for example, will be able to be met by new combined cycle natural gas-fired plants, even when taking into account start-up and shutdown due to necessary cycling or other operational constraints. Existing regulatory provisions under 6 NYCRR Section 201-1.4 address unavoidable noncompliance and violations that may result from necessary scheduled equipment maintenance, start-up/shutdown conditions, and malfunctions or upsets.
Comment 9: Additionally, the draft document notes that an emission rate of 925 pounds of CO2 per MW hour gross electrical output (output-based limit) or 120 pounds of CO2 per million Btu of input (input based limit) would apply to: (1) boilers that are permitted to fire greater than 70 percent fossil fuel; (2) combined-cycle combustion turbines; or (3) stationary internal combustion engines that fire only gaseous fuel. An emission rate of 1450 pounds of CO2 per MW hour gross electrical output (output based limit) or 160 pounds of CO2 per million Btu of input (input-based limit) would pertain to: (1) simple-cycle combustion turbines or (2) stationary internal combustion engines that fire either liquid fuel or liquid and gaseous fuel simultaneously. However, in order to preserve fuel diversity and the reliability driven ability to operate on oil and to account for some degradation of the systems over time, IPPNY proposes changing the emission limit from 120 lbs CO2 per million Btu to 125 lbs CO2 per million Btu and from 925 pounds of CO2 per MW hour gross electrical output to 960 pounds of CO2 per MW hour gross electrical output, while still allowing the flexibility to choose between an output-based limit or an input-based limit.
Response: The Department believes that the limits established in Part 251 adequately cover the normal operating scenarios for natural gas-fired (with distillate oil back-up) combined cycle combustion turbines and do not need to be raised. The Department believes that the existing emission standards in Part 251 preserve fuel diversity and reliability-driven needs. See also response to comment nos. 1 & 2.
Comment 10: Furthermore, in place of the specific references to 40 CFR part 75 in proposed Section 251.5 covering monitoring, we strongly recommend that the DEC allow the provisions of the United States Environmental Protection Agency's (EPA) Mandatory Greenhouse Gas (GHG) Reporting Rule (40 CFR 98) for purposes of compliance with this Part. The EPA's GHG reporting program already establishes rigorous methods for determining GHG emissions from all potential emission sources covered by Part 251, including the use of continuous emission rate monitoring systems for large facilities. This approach is especially pertinent to waste to energy (WTE) facilities, which are not regulated specifically under 40 CFR 60 and not regulated under 40 CFR 75. At a minimum, Part 251 should allow monitoring of CO2 mass emissions for non-Part 75 facilities in accordance with the provisions of 40 CFR 60.
Response: The Department recognizes that not all facilities which employ continuous emission monitoring systems (CEMS) are required to monitor under the 40 CFR Part 75 requirements. Therefore, the Department has clarified the language in the monitoring, recordkeeping, and reporting requirements under Section 251.5 and 251.6, in order to provide certain types of facilities the ability to choose between using 40 CFR Part 60 or 40 CFR Part 75 monitoring, recordkeeping, and reporting requirements.
Comment 11: Since the proposed rule is written to apply to expansions of 25 MW or more at existing facilities, IPPNY appreciates that the DEC has accepted our suggestion to limit applicability only to new equipment and that the draft regulation explicitly states that the rule's provisions would apply only to those emission source(s) involved in the increase in capacity at the electric generating facility.
Response: Thank you for your comment. The commenter is correct that Part 251 would only apply to those emission source(s) involved in any increase in capacity of at least 25 MW. In particular, subdivision 251.2(b) states the following: "Existing Sources. The provisions of this Part apply to owners or operators of existing electric generating facilities that commence construction for an increase in capacity of at least 25 MW at the facility after the effective date of this Part. Only those emission source(s) involved in the increase in capacity at the electric generating facility shall be subject to the emission limits established in Section 251.3 of this Part." (emphasis added). 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.
Comment 12: IPPNY also supports DEC's proposed regulation for allowing WTE facilities and biomass-fired facilities to propose and meet a case-specific emission limit for CO2. DEC should look at life-cycle assessments and the greenhouse gas offsetting aspects of WTE facilities in determining case-by-case requirements for WTE facilities. Life-cycle calculations would deduct from the amount of CO2 emissions arising due to the combustion of MSW, the avoided fossil CO2 emissions from the operation of WTE facilities, and the avoided methane emissions from not depositing MSW into landfills (i.e. CO2 emissions minus avoided emissions minus avoided methane emissions).
Response: As part of the case-by-case analysis under subdivision 251.3(c), the Department will review all factors involved in a project to determine the appropriate emission limits for the equipment proposed in the project. 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. These factors may include, but are not limited to, life cycle analyses, avoided emissions, efficiencies, and any other factor specific to a proposed project.
Comment 13: The Department's standards, however, can and should be refined further. As recognized by the Department, "controlling CO2 emissions from new emission sources is critical to the urgent global need to stabilize atmospheric CO2 concentrations." DEC, Regulatory Impact Statement. Thus, "it is imperative that [major electric generating facilities] reduce CO2 emissions to the lowest extent practicable using existing technology." Id. This principle is especially true when applied to new natural gas-fired facilities. Over the next decade, these facilities are expected to be one of the primary forms of new electricity generation in the State. Id. These facilities are also expected to provide few if any benefits to reducing climate change. As three reports have noted:
"[A]n increased share of natural gas in the global energy mix is not enough, on its own and with today's technology, to avert serious climate change[.]"
"[T]he temperature differences between the baseline and coal-to-gas scenarios are small (less than 0.1°C) out to at least 2100."
"Technologies that offer only modest reductions in emissions, such as natural gas . . . cannot yield substantial temperature reductions this century."
Given natural gas' ongoing contribution to global warming, the Department must ensure that its proposed standards are a real and effective limit to reducing CO2 emissions within the State.
Here, more protective standards are both warranted and achievable; accordingly, the Department should strongly consider the following additional and small refinements to its current proposal. At present, a natural gas combined cycle combustion turbine may burn oil for up to 45 days each year without violating the Department's proposed emission limit. This oil allowance is purportedly necessary to ensure the reliability of the State's electrical supply - e.g., as a precautionary measure in the event of a sudden loss of natural gas supply or during seasonal peak demands. See DEC, Regulatory Impact Statement.
But the Department's rationale for this allowance appears contrary to the reliability rules developed by New York State's Reliability Council. See generally New York State Reliability Council ("NYSRC") Reliability Rules For Planning and Operating the New York State Power System, Version 30 (Nov. 10, 2011). As the Council's rules explain, only select generators in New York City and Long Island are required to burn oil under such conditions - i.e., units subject to the Council's contingency and "minimum oil burn" requirements. Id. at 68 (discussing Local Reliability Rules I-R1, I-R3 & I-R5). Because these areas possess "unique local area characteristics or reliability needs" as compared to other areas of the State, the Council has required select generators to meet these more stringent requirements. Id. at 7 (italics in original); see id. at 66 (noting "unique circumstances and complexities related to the maintenance of reliable transmission service, and the dire consequences that would result from failure to provide uninterrupted service" to New York City and Long Island). No other areas within the State are required to prepare for such contingencies, and no other areas are subject to the Council's "minimum oil burn" requirements. See id. In short, nothing in the Council's rules suggests that the contingency or "minimum oil burn" requirements should apply to facilities outside New York City and Long Island.
Given the Reliability Council's determination that only select generators in New York City and Long Island are required to prepare for such contingencies by burning oil, the Department's determination that all facilities within the State must prepare for such contingencies is unnecessary and will lead to additional-and entirely avoidable - CO2 emissions and pollution. Instead of setting a one-size-fits-all standard to accommodate the handful of plants that are required to burn oil for reliability reasons, the Department should create a new, stricter standard for units that are not subject to the "minimum oil burn" requirements. That standard should reflect the best achievable control technology ("BACT") CO2 emission limit for a gas-fired combined cycle combustion turbine today. In light of EPA's recent BACT determinations, the input standard should be no greater than 774 lbs. per MW hour.
Response: The commenter suggests that a lower CO2 emission limit should apply to facilities outside New York City and Long Island, based on the New York State Reliability Council "minimum oil burn" requirements. While it is true that facilities located outside New York City and Long Island may not have specified "minimum oil burn" reliability requirements, facilities across upstate New York may be curtailed from natural gas firing in certain situations. For example, Federal regulations require natural gas pipeline owners to provide residential customers with natural gas before industrial or utility customers when the gas pressures drop below case-by-case specified levels in the pipeline. Based on these requirements or other considerations, most upstate combined cycle facilities have installed oil back-up capabilities, and may need to fire backup oil just like the "minimum oil burn" facilities. Therefore, the Department has established a Statewide CO2 emission standard, and not a "regionalized" CO2 emission standard that is different based on the location of the facility within the State.
Moreover, as explained in the RIS and in response to comment no. 2, the CO2 emission limit for combined cycle facilities was set at a level to provide appropriate technical, operational, and reliability-based flexibility for regulated entities. In addition to allowing for a reasonable amount of backup oil-firing at a natural gas combined cycle plant, flexibility is also provided for factors such as start-up and shutdown operations. While a new natural gas-fired combined cycle facility may be able to meet an emission rate of 774 lbs/MWhr, this may not be true under all technical or operational conditions or in all locations within the State. Part 251 is a performance standard that establishes a CO2 emission standard that every subject facility is required to meet.
The commenter also states that the Department should set the CO2 emission standard at a level equivalent to best available control technology (BACT) determinations, which the commenter states should be no greater than 774 lbs/MWhr. As stated above, Part 251 is a performance standard that, among other things, establishes a specific numerical CO2 emission standard that every combined cycle combustion turbine subject to the rule is required to meet. Part 251 is not a new source review (NSR) regulation that allows for a top-down BACT analysis to determine a relevant emission limit.
In any case, combined cycle combustion turbines subject to Part 251 are also likely to be subject to a GHG BACT analysis under the Department's Prevention of Significant Deterioration (PSD) program. Provided a facility that is subject to Part 251 meets the GHG major source applicability thresholds established in the GHG Tailoring Rule and incorporated in the Department's PSD regulations in 6 NYCRR Parts 200, 201, and 231, and is otherwise subject to PSD pre-construction permitting, then the facility will also be subject to a separate GHG BACT analysis. In other words, while Part 251 establishes a single emission standard for all combined cycle combustion turbines, that does not relieve a facility that is subject to PSD from also complying with a separate GHG emission limitation based on a BACT determination. GHG BACT may ultimately equate to a CO2 emission limit less than 925 lbs/MWhr for certain facilities, subject to the existing top down case-specific BACT determination process for the particular relevant facility.
But the Department believes that it is unrealistic to assume that every combined cycle turbine can meet the 774 lbs/MWhr standard proposed by the commenter. There are several combustion turbine manufacturers worldwide. Each manufacturer has several models of turbines based on size and firing structure. BACT determinations have not been established for each turbine available. At least until such time, the Department does not believe it is appropriate to establish a single standard based on limited determination.
Comment 14: The Department should also revise its proposed standard for units that actually are subject to the Council's contingency and minimum oil burn requirements. At present, this standard assumes that every such unit will burn oil for roughly 45 days. See DEC, Regulatory Impact Statement. This assumption, however, is unsupported by DEC. While data exists regarding the duration of oil burning under the Reliability rules, it is unclear whether the Department reviewed those records in determining the reasonableness of its 45-day assumption.
Response: The Department has set what it believes to be a reasonable CO2 emission standard, which could allow for back-up oil firing of up to 45 days per year. 45 days equates to less than 12.5 percent of the year. In any case, the 45 day oil burn consideration was not the only factor upon which the Department based the level of the emission limit. While the limit could allow for up to 45 days of back-up oil firing, it was also established in order to provide appropriate flexibility for technical, operational, and reliability-based considerations, as described above in response to comment no. 2. Moreover, the 925 lbs/MWhr standard is similar to, or more stringent, than standards already promulgated in other states. Likewise, the primary emission limit in subdivision 251.3(a) is more stringent than the emission limit proposed by the U.S. EPA in its draft CO2 New Source Performance Standard (NSPS). See Standards of Performance for Greenhouse Gas emissions for New Stationary Sources: Electric Utility Generating Units, 77 FR 22392 (Apr. 13, 2012).
Comment 15: The Department can do better. To best meet its charge for reducing the level of CO2 emissions, the Department should develop a separate performance standard for units burning oil. Whereas the currently proposed standard allows facilities to operate inefficiently, applying a separate standard for burning oil would remove this incentive and, better yet, ensure that easily avoidable CO2 emissions are not being released into the atmosphere. By also promulgating notice and documentation requirements (similar to the ones imposed by the New York Independent System Operator ("NYISO")), the Department may further ensure that any variance from its established emission limits is justified. Accordingly, for units that are subject to the minimum oil burn requirements, the Department should impose at least two standards: one that applies when the unit is burning natural gas (e.g., 774 lbs. per MW hour) and another when the unit is required to burn oil.
Response: The Department respectfully disagrees with this comment. The Department does not believe it necessary to develop separate CO2 emission standards for gas firing and oil firing. Part 251 is a new source performance standard that establishes a single emission limit that must be met at all times (subject to 12 month rolling average) regardless of fossil fuel type.
Comment 16: Finally, to ensure that the Department's standards reflect advances in technology, the Department should include regulations requiring the periodic revision and update of these performance standards. Technologies change over time and a wide range of technologies and practices (e.g., increased energy efficiency, fuel switching, and power recovery) have the potential to reduce CO2 emissions. Thus, to ensure that these standards reflect the maximum emissions reductions that can be achieved in the future, the Department should incorporate regulations allowing it to revise these standards periodically.
Response: Thank you for your comment. No regulations are required in order to provide the Department with the ability to update the standards in the future based on technological advancements. The Department already has the ability to revise, at any time, the CO2 emission standards in Part 251, pursuant to a subsequent rulemaking process under SAPA. The Department may consider periodically updating the requirements of Part 251 through such subsequent rulemakings.
Environmental Advocates of New York:
Comment 17: It is critical that these regulations consider the magnitude of the threat global warming poses to New York's economy, public health, infrastructure and natural resources. Combustion of fuels to produce electricity contributes almost a quarter of the pollution that is altering our climate. Electric Generating Facilities have significant lifespans and can operate for almost a half century in some cases. As a result these electric generating facilities will continue to spew climate-altering pollution from up to a half century in the future. We therefore cannot afford to set an incorrect standard, one that does not require the installation of only those facilities that are in line with state policies to reduce climate pollution.
These regulations must be consistent with other state policies and priorities including the State's goal to reduce greenhouse gas emissions by 80 percent by the year 2050, the State's renewable energy goals and participation in the Regional Greenhouse Gas Initiative.
Response: The Department agrees with the commenter regarding the magnitude of the threat of global climate change, the potentially significant lifespans of new electric generating facilities, and the importance of setting a standard at the appropriate level. Moreover, the Department agrees that Part 251 should be consistent with other State policies and priorities. The Department believes that it has established CO2 emission standards at a level that will prevent new high-carbon sources of energy. Moreover, the Department believes that Part 251 is consistent with other State policies, including the State's goal to reduce GHG emissions by 80 percent by 2050, and the RGGI program.
Comment 18: Part 251.3(a) and (b) emission limits must be changed to ensure that facilities are operated most efficiently and with lowest emission rates. To get New York on a path to reduce emissions 80 percent by the year 2050, the standard must ensure that only facilities that move us toward our state goals are sited and that those facilities are operated at their optimal efficiency. The standard as proposed fails to do so and would allow for the siting of inefficiently operated facilities that result in avoidable pollution. Indeed, the standards fail to meet what industry informs us is the emission rate for facilities that are being built today. According to industry the most efficient combined cycle facility can operate at an emission rate of 800 lbs/MWhr. To be consistent with other state standards like California and Oregon the standard for electric generating facilities defined in 251.3(b) should be 1,100 pounds per MW hour. Because of the dire need to reduce greenhouse gas emissions and the currently emerging technology, Environmental Advocates recommends that the Department amend Part
251.3(a) delete "925 pounds of CO2 per MW hour gross electrical output" and replace with "800 pounds of CO2 per MW hour gross electrical output" and under Part 251.3(b) delete "1450 pounds of CO2 per MW hour gross electrical output" replace with "1100 pounds of CO2 per MW hour of gross electrical output." Changes to the input based standard should be made to provide for the comparable input based standard.
Response: The Department thanks the commenter for their recommendations. As explained in the RIS and in response to comment no. 2, the Department developed the primary CO2 emission standard of 925 lbs/MWhr based on an emission rate achievable by a new natural gas-fired combined cycle plant, taking into account an appropriate level of flexibility for backup oil-burn, start-up and shutdown, or other technical, operational, and reliability considerations. The emission limits in the regulation prevent new high-carbon sources of energy in the State and encourage efficiency, while also providing for an appropriate level of flexibility. While the 925 lbs/MWhr standard may not represent the emission level of the most efficient possible new plant, as described above in response to comment no.13, Part 251 is a performance standard that establishes a single standard for all applicable combined cycle combustion turbines.
In terms of the separate standard under subdivision 251.3(b), many of the simple cycle combustions installed throughout New York State have been placed in areas that have limited or no natural gas availability. Therefore, the Department has determined that it is appropriate to establish a separate CO2 emission standard for simple cycle combustion turbines. This standard allows for a simple cycle combustion turbine to fire oil approximately 85 to 100 percent of the time, in order to ensure reliability considerations are taken into account.
Comment 19: Part 251.3(c) must be amended relating to municipal solid waste. This section would include sources such as municipal waste combustors (both conventional mass-burn incinerators and newer thermal processing technologies such as gasification, pyrolyisis and plasma arc incinerators). These facilities are major greenhouse gas emitters, releasing more CO2 per MWhr than coal-fired power plants. According the United States Environmental Protection Agency, the emission rate for a waste-to-energy facility is significantly greater than coal. The average emission rates in the United States from coal fired generation are: 2,249 lbs/MWhr of carbon dioxide while the average air emission rates in the United States from municipal solid waste-fired generation are: 3685 lbs/MWhr of carbon dioxide. We cannot continue to allow technologies with such high emission rates to operate. Merely basing the emissions limit on operating efficiencies of existing sources, as proposed, would not meet the objective of the Power New York Act or the Part 251 regulations to prevent the construction of new high-carbon sources of energy. Part 251.3(c) should be amended to state that "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, OR MUNICIPAL SOLID WASTE, unless the CO2 emission rate associated with that input meets the CO2 emission limit in Subdivision (a) of this Section." In addition, language should be added stating that "for the purpose of calculating CO2 emissions, a source using MSW as a fuel may not exclude emissions from the biogenic portion of the waste."
Response: Subdivision 251.3(c) regulates CO2 emissions on a case-by-case basis. This applies to any proposed project that will fire fuels other than those listed in subdivisions (a) and (b) of section 251.3 and includes municipal solid waste firing facilities. All of these facilities will be required to undergo a case-by-case analysis to determine a Department-approved project- specific CO2 emission standard. The Department believes that a case-by-case analysis is the best way to approach development of CO2 emission standards for municipal solid waste firing facilities, and therefore does not believe it is necessary to make the first amendment referenced by the commenter. Furthermore, Part 251 does not specifically exclude any CO2 emissions attributable to the burning of the biogenic portion of waste, and so the Department believes the commenter's second suggested addition is unnecessary.
Comment 20: Under 251.3(c) the Department must require that any proposal for an emission limit submitted provide the assumptions and calculations used to determine the emission rate and proposed standard. Not all biomass is created equal and different feedstocks have differing emission profiles which must be taken into account when determining a facilities emission rate.
Response: The Department agrees that not all biomass is created equal, and that different types of biomass feedstocks will have differing CO2 emission profiles. As explained in the RIS, only certain types of biomass may be considered carbon-neutral over time, under certain conditions. Biomass was included in the case-by-case analysis provisions under 251.3(c) for these reasons, among others. 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. This may include, for example, consideration of the sustainability of the biogenic portion of any fuel, as well as the future carbon sequestration associated with such fuel, in determining whether and how to adjust for biogenic CO2 emissions.
Comment 21: When reviewing a proposal under Part 251.3(c) the Department must not assume that all biomass is carbon neutral and perform a full lifecycle assessment of the proposed fuel. Also, need to take into account that not all biomass is created equal, meaning that different biomass feedstocks have different emission levels.
Response: As stated in the RIS and in response to comment no. 20, the Department does not assume that all biomass is carbon neutral. In reviewing and approving case-specific emission limits under 251.3(c), the Department will take into account all appropriate factors relevant to determining the overall carbon intensity of the proposed facility. This may include consideration of a lifecycle analysis of the particular biomass feedstock(s) proposed to be burned at the facility.
Comment 22: Revisit the standard and adjust downward to account for evolving technology. We urge DEC to incorporate into the rule an explicit requirement to occasionally revisit the performance standard (for both simple cycle and combined cycle units), account for advances in technology and emissions controls, and adjust the number downward as appropriate. Every five years would seem reasonable.
Response: Thank you for your comment. As explained in response to comment no. 16 the Department may consider periodically updating the requirements of Part 251 pursuant to a subsequent rulemaking.
Comment 23: These regulations should not be drafted in a manner to provide exceptions for technologies that emit high levels of carbon dioxide.
Response: The Department does not believe that this regulation provides exceptions for technologies that emit high levels of CO2. In fact, Part 251 does not exempt any technologies; any new major electric generating facility, or increase in capacity of at least 25 MW at an existing electric generating facility, is subject to Part 251 regardless of the type of technology.
Comment 24: An applicant's proposal under Part 251.3(c) should also be subject to public notice and comment. The Department should consider public comments on proposed applications under Part 251.3(c).
Response: The permitting requirements for any facility subject to Part 251, including provisions providing for public notice and comment, are found in 6 NYCRR Parts 201 and 621. Also, facilities that are subject to Part 251 are subject to the requirements of Article 10 and implementing regulations. Public notice and participation is required by all of these regulations. Therefore, members of the public will have the opportunity to review any case-specific determinations made by the Department under 251.3(c).
Comment 25: Section 251.3(a) - emission rate should be 800 pounds of CO2 per MW hour, as the industry has stated it can achieve
Response: The Department established the emission standard in 251.3(a) based on an emission rate achievable by a new natural gas-fired combined cycle plant, taking into account an appropriate level of flexibility for technical, operational, and reliability-based considerations. See also response to comment nos. 2 and 13.
Comment 26: Section 251.3(b) - emission rate should be 1,100 pounds of CO2 per MW hour, consistent with standards set in California and Oregon
Response: See Response to comment no. 18.
Comment 27: Section 251.3(c) - re: case specific emissions limit. This section would include sources such as municipal waste combustors (both conventional mass-burn incinerators and newer thermal processing technologies such as gasification, pyrolysis and plasma arc incinerators). These facilities are major greenhouse gas emitters, releasing more CO2 per MWhr than coal-fired power plants. Merely basing the emissions limit on operating efficiencies of existing sources, as proposed, would not meet the objective of the Power New York Act or the Part 251 regulations to prevent the construction of new high-carbon sources of energy. The language should be amended to state that "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, OR MUNICIPAL SOLID WASTE, unless the CO2 emission rate associated with that input meets the CO2 emission limit in Subdivision (a) of this Section." In addition, language should be added stating that "for the purpose of calculating CO2 emissions, a source using municipal solid waste (MSW) as a fuel may not exclude emissions from the biogenic portion of the waste."
Response: See response to comment nos. 19 and 20.
Comment 28: Similarly, biomass facilities (for non-MSW) are a significant source of greenhouse gases, emitting more CO2 than coal-fired power plants. Emission projections should not just be based on an analysis of existing control technologies and operating efficiencies of existing sources, they must also be based on the emissions profiles for the specific feedstock(s) being proposed. We do not believe that biomass facilities should be given a free pass to pollute, even if the feedstock is considered "renewable" under certain definitions. In considering case-specific emissions limits for biomass facilities, the DEC should require a full life-cycle assessment of the proposed fuel.
Response: The case-specific emission limit under 251.3(c) may be based on other appropriate considerations relevant to the source's CO2 emission profile. The Department agrees that biomass facilities should not "be given a free pass to pollute." In making a case-specific determination for biomass-fired facilities, the Department will take into account all appropriate factors relevant to determining the overall carbon intensity of the proposed facility. This may include consideration of a lifecycle analysis of the particular biomass feedstock(s) proposed to be burned at the facility. See also response to comment no. 21.
Comment 29: Proposed Section 251.3(a) provides that new or significantly expanded combined cycle combustion turbines, boilers permitted to fire greater than 70 percent fossil fuel, and stationary internal combustion engines that fire only gaseous fuel must meet an emission rate of 925 lbs CO2/MWhr gross electrical output or 120 lbs CO2/mmBtu of input.
Any gas plant would meet the proposed input standard of 120 lbs CO2/mmBtu. As a result, the standard provides no incentive for use of the most efficient generation technology. Yet greenhouse gas emission rates from combined cycle gas plants vary significantly. Leaving plants with the option of choosing an input-based limit would not fulfill the Power NY Act's mandate to reduce CO2 emissions. These standards will not effectively reduce the greenhouse gas impact-and harm to the citizens of New York-caused by the State's power generation. Further, standards that do not require use of the most efficient generation technology fail to reflect the importance of using natural gas wisely, both because of the impacts of its extraction and broader energy security concerns. We strongly urge DEC to require all sources subject to the Sec. 251.3(a) standards to meet an output-based standard.
Response: The Department agrees that emission rates may vary across combined cycle natural gas-fired plants. The Department established an emission rate for such plants based on an emission rate achievable by new natural gas-fired combined cycle plants, taking into account appropriate flexibility for technical, operational, and reliability-based considerations. See also response to comment no. 13.
Part 251 fulfills the requirements of ECL section 19-0312. The Department respectfully disagrees with the commenter regarding the use of an input versus an output-based emission standard. Both standards are used to determine the overall efficiency of an electric generating emission source on a Btu per kilowatt hour basis. Thus, an emission source that can fire less fuel to achieve a higher electric output is no less efficient than an emission source that increases output without firing more fuel. Both standards are measurable and compliance can be determined for either standard. Therefore, to allow flexibility (based on what the Department considers to be equivalent standards) both emission standards have been included in the regulation.
There are also other practical reasons for allowing the use of an input-based standard. Cogeneration sources provide both steam and electricity. Output from these facilities is more than just megawatts but also pounds of steam. To estimate the electrical output and determine compliance with an output based standard, the facility would be required to convert their steam output into electrical output. This is not a precise calculation. For these types of facilities, the efficiency of their fuel burning and the amount of fuel burned are known quantities. Therefore, compliance with the proposed standards can be precisely measured and monitored.
Comment 30: In addition, we strongly recommend that the output-based standard be revised to more closely reflect currently available technologies and the emission rates being achieved in practice. Data submitted to the Environmental Protection Agency indicates that 15 percent of combined cycle gas plants in operation today have emission rates at or below 822 lbs CO2/MWhr. State of the art combined cycle turbines can achieve an emission rate on the order of 670 lbs CO2/MWhr. A plant recently built in California has a BACT permit that will result in an emission rate of approximately 800 lbs CO2/MWhr. Given these demonstrations of what is currently achievable, we urge DEC to set the performance standard for the Section 251.3(a) sources at or below 800 lbs CO2/MWhr.
Response: See response to comment no. 13.
Comment 31: Proposed Section 251.3(b) provides that new or significantly expanded simple cycle combustion turbines and stationary internal combustion engines must meet an emission rate of 1,450 lbs CO2/MWhr gross electrical output or 160 lbs CO2/mmBtu input.
As discussed above, any plant that selects the input standard will have no incentive to choose the most efficient generation technology, which fails to ensure responsible resource use or fulfill the legislature's directive to target reductions in greenhouse gas emissions from the power sector. We strongly urge DEC to require all sources subject to the Sec. 251.3(b) standard to meet an output-based standard.
Comment 32: Further, we urge DEC to set the output based standard at a level reflecting what is achievable using currently available technologies. Data submitted to the Environmental Protection Agency indicates that 15 percent of combustion turbine plants in operation today have emission rates at or below 1,189 lbs CO2/MWhr. The top three percent of simple cycle combustion turbines currently in operation have emission rates at or below 1,075 lbs CO2/MWhr. We therefore strongly recommend that DEC set the performance standard for Sec. 251.3(b) sources at or below 1,200 lbs CO2/MWhr.
Response: The emission levels that the commenter cites are based on natural gas-fired simple cycle combustion turbines, while simple cycle combustion turbines in the State may need the ability to fire primarily oil. See also response to comment no. 18.
Comment 33: We appreciate that Minimum Oil Burn Rules require that certain units be able to immediately burn oil in the event of a natural gas supply disruption. However, instead of weakening the Sec. 251.3(b) emission standards to accommodate the possibility of such events, we urge DEC to create an exemption for those specific units that would enable the units to meet the oil burn requirements should natural gas supply be disrupted, but require those units to meet the emission standards at all other times.
Response: The Department established the emission standards in both 251.3(a) and (b) based on the possibility of oil burn requirements, as well as other operational, technical, and reliability-based considerations. See response to comment nos. 2,13, and 18.
Moreover, Part 251 is a performance standard that establishes a threshold level emission limit that all applicable facilities must meet. Subdivisions (a) and (b) of section 251.3 establish specific emission limits that are applicable to all relevant source and fuel types at all times (subject to the 12 month rolling average). A specific-unit exemption or an approach that imposes different emission limits at different times of operation would be inconsistent with this performance standard approach. See Response to comment no. 15.
Comment 34: Finally, we ask that DEC ensure that the utilization of any new power plants allowed to meet the relaxed Sec. 251.3(b) standard be limited to those services that only less efficient plants can provide. Baseload power should be generated using our most efficient generation sources. To the extent that new simple cycle combustion turbines are needed to provide peaking power or to ensure reliability and the stability of electricity service, these important roles should be reflected in the greenhouse gas performance standards. We ask that DEC require any simple cycle combustion turbine subject to the Sec. 251.3(b) standard to have an average capacity factor of no more than 10 percent during any three consecutive calendar years, and a capacity factor of no more than 20 percent in any specific calendar year. The regulations could provide exclusions provided for units called upon to provide essential reliability services or to ensure voltage stability.
Response: The commenter is requesting that the Department insert electric system operating requirements into Part 251. The Department generally goes not directly regulate the precise manner, frequency, or length of operation of power plants. Part 251 only regulates the CO2 emissions from subject power plants, based on the source type, and does not dictate when or how such plants can run. The approach requested by the commenter would be inconsistent with the performance standard approach of Part 251 and would be counter to the Department's typical manner of regulation.
Comment 35: We believe that WTE and sustainably sourced biomass facilities should not be subject to CO2 performance standards given their national and worldwide recognition as renewable energy sources and demonstrated ability to actually mitigate greenhouse gas ("GHG") emissions. In particular, WTE's ability to mitigate GHG emissions is demonstrated when a life cycle approach is taken based on avoided landfill methane emissions, recovery of metals for recycling and displacement of fossil fuel based electrical generation. Based on national averages, every ton of waste processed at a WTE facility reduces GHG emissions by one ton of CO2 equivalents. Indeed, the DEC Commissioner's policy on Climate Change and DEC Action specifically calls upon DEC staff to consider the implications of department actions or choices based on a life-cycle models.
The Nobel Prize winning Intergovernmental Panel on Climate Change ("IPCC") identifies WTE as a key GHG mitigation technology for the waste sector. WTE facilities in developing countries are eligible to generate tradable GHG credits under an approved offset methodology under the Kyoto Protocol. A recent paper coauthored by EPA and North Carolina State researchers demonstrated the value of WTE over landfilling from both a GHG and energy perspective. The World Economic Forum at their 2009 meeting in Davos, Switzerland, identified WTE as one of eight renewable technologies likely to make a meaningful contribution to a future low-carbon energy system. WTE's mitigation potential is also recognized by the European Union, the European Environmental Agency, the Global Roundtable on Climate Change convened by Columbia University's Earth Institute, and the U.S. Conference of Mayors. Finally, recent U.S. WTE capacity expansions, including the Lee County, Florida Resource Recovery Facility recent capital expansion, are generating carbon offset credits for the voluntary market.
Response: The Department respectfully disagrees with the commenter's determination that waste to energy (WTE) and sustainably sourced biomass facilities should not be subject to CO2 performance standards. As explained in the RIS, the Department believes that exempting WTE or sustainably sourced biomass facilities from Part 251 would be counter to the statutory requirements of ECL 19-0312, Article 10, and the Power NY Act. Based on the statutory language, Part 251 will apply to any major electric generating facilities that commence construction after its effective date, and to existing electric generating facilities that increase capacity by at least 25 MW, regardless of the source's configuration or fuel type.
Comment 36: If upon further analysis, DEC confirms that the statute will not allow an exemption for WTE and biomass to energy facilities, then we agree that setting case specific emissions is a prudent and reasonable approach. WTE and biomass facilities are fundamentally different than traditional fossil fuel fired power plants. In additional to their well proven ability to mitigate GHG emissions, WTE facilities are built primarily for solid waste management, not electrical generation and the MSW fueling WTE facilities has highly variable heat, carbon and materials content compared to fossil fuels. Specifically, the amount of fossil based carbon materials in MSW, such as plastics, directly determines the amount of fossil based CO2 emissions and can change over time due to changes in the waste shed. Furthermore, the combustion of biomass, or the biomass portion of MSW, releases biogenic CO2, which is accounted separately from fossil based carbon internationally, nationally, and in New York State. For these reasons it is important that WTE and biomass to energy facilities be subject to case specific CO2 performance standards.
Response: As explained in the RIS, the Department agrees with the commenter's assessment that WTE and biomass-fired facilities are different from traditional fossil fuel-fired facilities. To address these differences, the Department included a case-by-case analysis and Department-approved CO2 emission limit in subdivision 251.3(c), which applies to any proposed project that will fire fuels other than those listed in subdivisions (a) and (b). This includes WTE and biomass to energy facilities, which will be subject to case-specific CO2 performance standards to be approved by the Department.
Comment 37: We believe flexibility needs to be included in the regulation for those facilities not regulated under the provisions of 40 CFR 75. In place of the specific references to 40 CFR Part 75 (for Acid Rain Sources) in proposed Section 251.5 covering monitoring, we strongly recommend that the NYS DEC allow the provisions of the U.S. EPA Mandatory Greenhouse Gas Reporting Rule (40 CFR 98) for purposes of demonstrating compliance with this part. The U.S. EPA GHG Reporting Rule already establishes rigorous methods for determining GHG emissions from all potential emission sources covered by Part 251, including the use of continuous emission rate monitoring systems for large WTE facilities. This is especially pertinent to WTE facilities which are already regulated specifically under 40 CFR 60 and not under 40 CFR 75. At a minimum, Part 251 should allow monitoring of CO2 mass emissions for non-Part 75 facilities in accordance with the provisions of 40 CFR 60.
Response: See response to comment no. 10.
Energy Recovery Council:
Comment 38: We believe that WTE facilities should not be subject to CO2 performance standards given WTE's national and worldwide recognition as a renewable energy source and demonstrated ability to actually mitigate greenhouse gas ("GHG") emissions. WTE's ability to mitigate GHG emissions is demonstrated when a life cycle approach is taken based on avoided landfill methane emissions, recovery of metals for recycling and displacement of fossil fuel based electrical generation. Based on national averages, every ton of waste processed at a WTE facility reduces GHG emissions by one ton of CO2 equivalents. Indeed, the DEC Commissioner's policy on Climate Change and DEC Action specifically calls upon DEC staff to consider the implications of department actions or choices based on a life-cycle models.
Further the Intergovernmental Panel on Climate Change ("IPCC") identifies WTE as a key GHG mitigation technology for the waste sector. WTE facilities in developing countries are eligible to generate tradable GHG credits under an approved methodology under the Kyoto Protocol. A recent paper coauthored by EPA and North Carolina State researchers demonstrated the value of WTE over landfilling from both a GHG and energy perspective. The World Economic Forum at their 2009 meeting in Davos, Switzerland, identified WTE as one of eight renewable technologies likely to make a meaningful contribution to a future low-carbon energy system.
Response: As explained in the RIS, the statutory language does not provide the Department with the ability to exempt WTE facilities. See response to comment nos. 35 and 36.
Comment 39: In summary, we believe that WTE facilities and biomass-fired facilities should not be subject to CO2 performance standards given their national and world wide recognition as part of the solution to reduce worldwide carbon or CO2 equivalent (CO2e) emissions. Certainly NYDEC and/or the state legislature should further review the underlying statute to determine if WTE and other biomass to energy facilities cannot be exempted. If upon further analysis it is confirmed that the statute will not allow an exemption for
WTE and biomass to energy facilities then we agree that setting case specific emissions limits that differentiate these facilities from fossil fuel fired facilities is a prudent and reasonable approach. WTE facilities are significantly different than fossil fuel fired facilities for two primary reasons: 1) WTE facilities are built for the primary purpose of solid waste management and not electrical generation and 2) WTE fuel is municipal solid waste (MSW) that has highly variable heat, carbon and materials content compared to fossil fuels. The amount of fossil based carbon materials in MSW, such as plastics, and other non-biogenic materials directly determines the amount of fossil based CO2 emissions and will change over time due to changes in the waste shed. Steam and/or electrical generation efficiency for a WTE facility will also be dependent on the WTE technology chosen and characteristics of MSW and case based limits will provide the necessary flexibility. For these reasons it is important that WTE and biomass to energy facilities be subject to case base CO2 performance standards.
Response: The Department agrees that WTE and biomass-fired facilities are different from traditional fossil fuel-fired facilities. Indeed, WTE and biomass-fired facilities will be subject to a case-specific emission limit under subdivision 251.3(c). See response to comment no. 36.
Comment 40: We believe flexibility needs to be included in the regulation for those facilities not regulated under the provisions of 40 CFR 75. In place of the specific references to 40 CFR Part 75 (for Acid Rain Sources) in proposed Section 251.5 covering monitoring, we strongly recommend that the NYS DEC allow the provisions of the U.S. EPA Mandatory Greenhouse Gas Reporting Rule (40 CFR 98) for purposes of demonstrating compliance with this part. The U.S. EPA GHG reporting program already establishes rigorous methods for determining GHG emissions from all potential emission sources covered by Part 251, including the use of continuous emission rate monitoring systems for large WTE facilities. This is especially pertinent to WTE facilities which are already regulated specifically under 40 CFR 60 and not under 40 CFR 75. At a minimum, Part 251 should allow monitoring of CO2 mass emissions for non-Part 75 facilities in accordance with the provisions of 40 CFR 60 and EPA GHG monitoring provisions of 40 CFR 98.
Response: The Department has clarified the regulatory language in Section 251.5 and 251.6 to address this concern. See response to comment no. 10.
Wheelabrator Technologies Inc (WTI):
Comment 41: We believe that WTE facilities should not be subject to CO2 performance standards given WTE's national and worldwide recognition as a renewable energy source and demonstrated ability to actually mitigate greenhouse gas ("GHG") emissions. WTE's ability to mitigate GHG emissions is demonstrated when a life cycle approach is taken based on avoided landfill methane emissions, recovery of metals for recycling and displacement of fossil fuel based electrical generation. Based on national averages, every ton of waste processed at a WTE facility reduces GHG emissions by one ton of CO2 equivalents' Indeed, the DEC Commissioner's policy on Climate Change and DEC Action specifically calls upon DEC staff to consider the implications of department actions or choices based on a life-cycle models.
Further the Intergovernmental Panel on Climate Change ("IPCC") identifies WTE as a key GHG mitigation technology for the waste sector. WTE facilities in developing countries are eligible to generate tradable GHG credits under an approved methodology under the Kyoto Protocol. A recent paper coauthored by EPA and North Carolina State researchers demonstrated the value of EfW over landfilling from both a GHG and energy perspective. The World Economic Forum at their 2009 meeting in Davos, Switzerland, identified WTE as one of eight renewable technologies likely to make a meaningful contribution to a future low-carbon energy system WTE's mitigation potential is also recognized b the European Union, the European Environmental Agency, the global roundtable on Climate Change convened by Columbia University's Earth Institute and U.S Conference of Mayors.
Comment 42: In summary, we believe that waste-to-energy (WTE) facilities and biomass-fired facilities should not be subject to CO2 performance standards given their national and world wide recognition as part of the solution to reduce worldwide carbon or CO2 equivalent (CO2e) emissions. Certainly NYDEC and/or the state legislature should further review the underlying statute to determine if WTE and other biomass to energy facilities cannot be exempted. If upon further analysis it is confirmed that the statute will not allow an exemption for WTE and biomass to energy facilities then we agree that setting case specific emissions limits that differentiate these facilities from fossil fuel fired facilities is a prudent and reasonable approach. WTE facilities are significantly different than fossil fuel fired facilities for two primary reasons: 1) WTE facilities are built for the primary purpose of solid waste management and not electrical generation and 2) WTE fuel is municipal solid waste (MSW) that has a highly variable heat, carbon and materials content compared to fossil fuels. The amount of fossil based carbon materials in MSW, such as plastics, and other non-biogenic materials directly determines the amount of fossil based CO2 emissions and will change over time due to changes in the waste shed. Steam and/or electrical generation efficiency for a WTE facility will also be dependent on the WTE technology chosen and characteristics of MSW and case based limits will provide the necessary flexibility. For these reasons it is important that WTE and biomass to energy facilities be subject to case base CO2 performance standards.
Response: As explained in the RIS, the statutory language does not provide the Department with the ability to exempt WTE or biomass-fired facilities. See response to comment nos. 35 and 36.
Comment 43: We believe flexibility needs to be included in the regulation for those facilities not regulated under the provisions of 40 CFR 75. In place of the specific references to 40 CFR Part 75 (for Acid Rain Sources) in proposed Section 251.5 covering monitoring, we strongly recommend that the NYS DEC allow the provisions of the U.S. EPA Mandatory Greenhouse Gas Reporting Rule (40 CFR 98) for purposes of demonstrating compliance with this part. The U.S. EPA GHG reporting program already establishes rigorous methods for determining GHG emissions from all potential emission sources covered by Part 251, including the use of continuous emission rate monitoring systems for large WTE facilities. This is especially pertinent to WTE facilities which are already regulated specifically under 40 CFR 60 and not 40 CFR 75. At a minimum, Part 251 should allow monitoring of CO2 mass emissions for non-Part 75 facilities under the provisions of 40 CFR 60 and USEPA GHG monitoring program under 40 CFR 98.
Comment 44: The proposed CO2 regulations provide a limit of 925 pounds of CO2/MWhr for fossil-fueled, combined cycle generating facilities. Within New York City, there are gas supply limitations that could prevent some generating facilities from burning natural gas 100 percent of the time. Further, the New York State Reliability Council has a local reliability rule for New York City that requires certain generating facilities to burn fuel oil under specified conditions to ensure that New York City does not suffer a blackout in the event of a loss of gas (Rule I-R3). The NYSDEC should ensure that new generating facilities will be able to satisfy the 925 pound limit when burning a combination of natural gas and, for a limited number of hours per year, fuel oil. If this limit is too stringent, it should be re-set at a level that ensures maximum protection of the environment while not jeopardizing the ability of generating facilities to operate during periods when their output is most critically needed to protect public health and safety (e.g., during heat waves).
Response: Thank you for your comment. The Department does not believe the 925 lbs/MWhr limit is too stringent. The Department established this standard based, in part, on the recognition that certain generating facilities in New York City may not be able to burn natural gas 100 percent of the time, due to minimum oil burn requirements or other considerations. This standard allows for up to 45 days of backup oil burn. The Department believes that the CO2 emission standards in Part 251 adequately ensure maximum protection of the environment while not jeopardizing the ability of generating facilities to operate during periods when their output is most critically needed to protect public health and safety.
See also response to comment no. 2.
Comment 45: Consider lowering the 925 lbs/MWhr standard for new plants not subject to the Minimum Oil Burn Rule. DEC has proposed a 925 lbs/MWhr performance standard for combined cycle facilities. Industry has demonstrated that the most efficient, state of the art gas turbines available on the market today can achieve lower rates closer to 800 lbs/MWhr on a rolling average basis (EPA has listed a BACT emissions rate for new combined-cycle gas combustion turbines of 774 lbs CO2/MWhr.). At the stakeholder meeting on the rule and in DEC's Regulatory Impact Statement on Part 251 it was explained that the reason for the higher number is that many gas power plants in New York include oil as a back-up fuel, and some burn this more carbon intensive fuel roughly 40-45 days a year. "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."
Response: See response to comment nos. 13 & 14.
Comment 46: While we understand the need for select plants in Zones J and K to comply with the Loss of Gas Minimum Oil Burn (LOGMOB) requirements for reliability (thereby necessitating a higher number to account for times when oil rather than gas is being burned), we question why this same provision is being applied statewide. 3 A reasonable alternative would be to apply one standard to any new facility that will be subject to the Minimum Oil Burn Rule (such as the proposed 925 lbs/MWhr), and to apply a lower standard for all other newly constructed facilities (such as 800 lbs/MWhr).
Comment 47: Revisit the standard and adjust downward to account for evolving technology. We urge DEC to incorporate into the rule an explicit requirement to occasionally revisit the performance standard (for both simple cycle and combined cycle units), account for advances in technology and emissions controls, and adjust the number downward as appropriate. Every five years would seem reasonable. In addition, staff could include some form of "forward looking assumed decrease in emission rates" based on "historical declines experienced" in gas turbines over the past twenty years. That is, establish a standard in Part 251 now, and build in an assumed percent increase in the efficiency of the technology going forward that would reduce the performance standard automatically over time. Then, during the five year review, DEC could determine if that trajectory was too aggressive or conservative based on real world developments, and adjust it accordingly.
Response: Thank you for your comment. The Department may consider periodically updating the requirements of Part 251 pursuant to subsequent rulemaking. See response to comment no. 16.
Comment 48: Ensure full public participation in any waste to energy or biomass applications for a custom performance standard. We support the provision included to address waste to energy and biomass facilities. These technologies make up a small fraction of New York's generation fleet, and it is highly unlikely they will make up a significant portion of new generation proposals in the future. Furthermore, due to their unique emissions profiles (often much more carbon intensive "at the smokestack" than combined cycle natural gas), calculating an appropriate standard that could be applied to any new project would be difficult if not impossible to determine under the regulatory time constraints under which DEC is working. Thus, requiring such facilities to propose and justify a CO2 standard on a case by case basis seems to be a reasonable solution.
We assume any such proposal would trigger a public comment period and be posted in the State Register, as is required when any developer applies for a Title V permit. However, in order to ensure the newly promulgated CO2 aspect of such a proceeding is fully addressed, we suggest that some explicit language be added to Part 251 that ensures the CO2 component of that proceeding is carved out and highlighted in some way. Doing so would ensure that aspect of the permit receives the needed attention, analyses and feedback from all stakeholders. The process of determining the accurate carbon balance of a biomass facility or emissions rate of a next generation waste-to-energy plant will be incredibly complex, and warrant substantial analyses and discussion by all parties to arrive at the appropriate numbers.
Response: Thank you for your comment. The permitting requirements, including provisions for public notice and comment, for any facility subject to Part 251 are found in 6 NYCRR Parts 201 and 621. Also, the facilities that are subject to Part 251 are subject to the requirements of Article 10 and implementing regulations. Public notice and participation is required by all of these statutes and regulations. See response to comment no. 24.
Comment 49: DEC estimates that combined cycle combustion turbines could operate on oil and comply with the standard set for them 40-45 days/year and that a simple cycle combustion turbine could operate 85-100 percent of its operating time on oil. The NYISO appreciates the analysis performed by the DEC and agrees with these observations. The DEC is correct that electric grid reliability requires the use of oil as a generating fuel on occasion. The NYISO believes these CO2 standards support the occasional reliability-required oil burn and do not present short-term reliability concerns.
DEC also states that it understands fuel diversity has been identified by the NYISO (in its 2010 RNA) as a component of risk in future supply reliability that requires ongoing study and monitoring. DEC states that it also took into account the historic market trend towards construction of natural gas combustion units by setting a standard that will "allow for dual-fuel fired resources with a significant allowance to fire oil." The NYISO agrees this "significant allowance to burn oil" should cover short-term reliability issues that could require the use of oil.
Comment 50: DEC acknowledged that an emergency situation could arise, perhaps from an unforeseeable event, which would require a regulated emission source to operate in a manner that would result in emissions that contribute to a violation of this carbon standard. In that event, DEC advises the owner or operator of the regulated source to rely on the affirmative defense provided in its regulations (6 NYCRR Section 201-1.5 and 201-6.6 (c)).
This is an insufficient strategy to deal with significant emergencies such as a catastrophic loss of natural gas to New York. The use of natural gas as a fuel in New York is growing and with it the dependency of New Yorkers on a steady flow of natural gas to keep the lights on. Of the 8,650 MWs of electric generating capacity added in New York since 2000, 1,336 MW are powered by wind and the vast majority of the other 7,314 MW fire on natural gas. Moreover, in the NYC and LI area, 9,628 MW of capacity is now operating beyond its original design life span of 30 years. 8,938 MW of this is dual fuel capacity. It is reasonable to expect that much of this capacity will be replaced in the next decade, and it is very likely to be replaced with gas burning facilities.
Response: The Department appreciates the importance of fuel diversity and ensuring continued reliability. The Department respectfully disagrees with the commenter's position that the affirmative defense provisions of Part 201 are insufficient when dealing with significant emergencies like the catastrophic loss of natural gas throughout New York State. Moreover, the emission standard in subdivision 251.3(a) takes into account reliability considerations, including by providing for up to 45 days of backup oil firing at dual fuel units. See response to comment no. 2. Moreover, the standard in subdivision 251.3(b) allows for a simple cycle combustion turbine to operate 85 to 100 percent of its operating time on oil. See also response to comment nos. 9 and 18.
Comment 51: While DEC acknowledges New York's growing dependency on natural gas as a generating fuel it has not responded adequately to the very significant reliability impacts that would result from a catastrophic loss of the fuel. This significant dependency on natural gas as a generating fuel requires an increased sensitivity to the potential for its loss. In an instant, dual fuel units may be needed to operate on oil just to keep the lights on.
Response: See response to comment nos. 8, 9, and 50.
Comment 52: DEC suggests that the availability of an affirmative defense of emergency provides sufficient assurance that these units will operate on oil, potentially exposing them to financial penalties for violating their environmental requirements. The NYISO disagrees. When generators are asked to operate in a manner that may violate their carbon standard, the NYISO needs to be assured that they will comply without question. The vague opportunity to assert an affirmative defense of emergency after a determination that a violation has occurred does not offer that level of assurance.
The NYISO would like to be prepared for such a circumstance with a specific protocol and set of compliance options that would allow such units to understand in advance that they could continue to operate without fear of penalty for violating the carbon standard. The NYISO would like to work with the DEC to develop such a protocol and set of compliance options. We recommend that the DEC acknowledge this as a necessary future effort.
Response: As described above, the Department believes that the emission standards in Part 251 provide appropriate flexibility to ensure continued reliability, and recognizes that an emergency situation may arise within the meaning of 6 NYCRR 201-2.1(b)(12). See response to comment nos. 2 and 50 . Although the Department believes that Part 251 and other existing provisions are sufficient, the Department appreciates the opportunity to work with the NYISO to address these issues, and will continue to interact with the NYISO and other stakeholders to research other potential compliance options.
Comment 53: In particular, Entergy strongly supports New York's efforts, as put into practice through the Department's proposed Part 251 regulations as well as other means such as the Part 242 regulations implementing RGGI, to reduce the State's GHG emissions and address the issue of climate change. Indeed, nuclear power, which emits virtually no CO2 or other GHGs in the generation of electricity, is essential to New York State meeting its CO2 reduction goals. As the Department notes in the Preamble to the proposed regulations, "[i]n 2010, electric generating units in the state subject to RGGI emitted approximately 42 million tons of CO2 into the atmosphere." 34 N.Y. Reg. at 15. By comparison, the volume of CO2 emissions avoided in New York State due to nuclear power plant operation in 2009 was approximately 28 tons (approximately 25.40 million metric tons), or roughly two-thirds of the total emitted by power plants in New York subject to RGGI and the proposed regulations. Thus, if nuclear powered electricity generation in New York were to cease, replacing that electricity with fossil-fueled Generating electricity as would most likely occur, would result in a dramatic increase in CO2 emissions in the State. As such, the continued operation of existing nuclear facilities, such as Indian Point and FitzPatrick, is essential not only for the prevention of increased carbon emissions in the State of New York, but also for the State to meet its GHG reduction goals under RGGI.
As an example, a 2011 report commissioned by the City of New York's Department of Environmental Protection highlights the importance of even a single nuclear facility's generation in maintaining air emissions at current levels. The report found that any option to replace Indian Point's electric generating capacity would significantly increase air pollutants because Indian Point is able to provide 2,000 MW of generation with virtually no air emissions. See Charles River Associates, Indian Point Energy Center Retirement Analysis, Prepared for the New York City Department of Environmental Protection, 13 (Aug. 2, 2011). According to this report, New York would see "approximately a 15 percent increase in carbon emissions under most conventional [Indian Point] replacement scenarios, with roughly a seven to eight percent increase in nitrogen oxide emissions." Id. at 13. Therefore, were New York State to eliminate just Indian Point, the resulting increase in CO2 emissions from its replacement alone would make it difficult to maintain current emissions, let alone meet the State's RGGI commitments, which require a 10 percent reduction in CO2 emissions by 2018.
Response: The Department appreciates Entergy's support for Part 251 and the Department's other ongoing efforts to reduce the State's GHG emissions and address climate change. Existing nuclear facilities such as Indian Point are not subject to Part 251, and the Department's promulgation of Part 251 does not alter the Department's policies or positions with regard to existing nuclear facilities. The Department notes Entergy's comments.
Saranac Power Partners, LP:
Comment 54: Based on CO2 emissions performance and current cycling mode of operation, the Saranac facility could be impacted by the proposed regulation to establish CO2 emission standards for increases in capacity of at least 25 MW at existing electric generating facilities as follows: All generation sources at Saranac are below the proposed limit of 120 lbs/mmBtu under both base load and cycling mode of operation. Whereas the Saranac gas turbines were able to achieve CO2 emissions below the proposed 925 lbs/MWhr limit when base-loaded, it is unable to meet the lbs/MWhr in the cycling mode of operation. As a result, it is possible that if Saranac increased its capacity by 25 megawatts with no or only a slight increase in fuel utilization, it would become subject to the emission performance standards. Contrary to the Department's conclusions that increases in capacity of at least 25 megawatts at existing facilities that utilize the equipment and fuel designated would meet the standard and would have a cost of zero, the potential impacts on the Saranac facility could be significant. Fundamentally, the issue of concern may not relate to the efficiency of the equipment at existing facilities as much as on the mode of operation and operating schedule, which is beyond Saranac's control.
It is well recognized that base load operation has inherently fewer emissions per MWhr generated because virtually all of the fuel burned is used to generate electrical energy. Saranac's turbines are efficient; however, in a cycling mode of operation, a significant portion of the fuel combusted is used in turbine acceleration and plant warm-up, producing relatively little electrical energy. The ramp for plant shutdown also reduces MWhr output relative to fuel burned, though less so.
Response 55: The Department has incorporated into the regulation the flexibility for permit applicants to utilize either a heat input based emission standard or a power output standard. Also, the Department incorporated a 12-month rolling average for compliance with the proposed CO2 emission standards. The Department therefore believes that, even if the commenter's facility were to become subject to Part 251 by virtue of an increase in capacity of at least 25 MW, the combination of these and other provisions provide sufficient flexibility to allow the commenter to comply with the regulation. See also response to comment no. 2.
Comment 56: Currently Saranac is not considering any modification or new construction to increase plant capacity; however, if Saranac were it to consider such options in the future, several aspects would have to be considered:
Saranac currently specifies a minimum scheduled run time of three hours to allow plant thermal equalization and time to properly assess and control Heat Recovery Steam Generator chemistry.
The ramp time in 2010 and 2011 constituted 19 percent and 20 percent of the run time respectively. A significant portion of plant scheduled operation is in a 1x1 minimum generation configuration which is less efficient than base load operation; 36 percent in 2010 and 29 percent in 2011. As the deployment of renewable, intermittent, generation increases, the need for facilities such as Saranac increases to maintain electric system reliability by effectively providing load and capacity following energy to avoid black-out or brown-outs.
Response: See response to comment no. 11.
Comment 57: As noted above, proposed regulations may not allow a facility to meet the emission performance standard and will potentially serve to increase CO2 emissions overall. In order to increase generation at Saranac and meet both limits under the currently proposed regulation, it would require:
A change in mode of operation closer to base load operation in order to meet the lb/MWhr limit - this is not likely under current market conditions.
Response: Part 251 does not require a facility to meet both the output-based lbs/MWhr standard and the input based lbs/mmBtu standard. Instead, the Department has incorporated into the regulation the flexibility for permit applicants to utilize either a heat input based emission standard or a power output standard. See also response to comment nos. 2 & 11.
Comment 58: An investment in new technology to significantly reduce CO2 emissions not only from the new generation but from existing generation in order to be able to meet the proposed lb/MWhr limit. The proposed rule suggests that carbon capture and sequestration is technically and/or economically feasible - at least with respect to coal and oil-fueled boilers. While Saranac disagrees with this suggestion, we note that under current market and technology cost conditions, this investment would be even less feasible for a plant such as the Saranac facility.
The proposed limits are stated such that either a heat input limit or an output-based could apply. Since that language is proposed Saranac suggests the following options:
The proposed language could be modified to allow the output-based limit for peaking units to also apply to cycling combined cycle units. This limit is 1,450 lbs/MWhr.
The proposed language could be modified to eliminate the lbs/MWhr limits since they are largely dependent on the mode of operation. The lbs/mmBtu, however, appears to be largely independent of mode of operation.
The language could be modified such that the least limiting limit applies. As noted above, the proposed regulations state:
The Department has determined that new combined cycle combustion turbines, new natural gas-fired boilers, new natural gas-fired stationary internal combustion engines, new oil-fired simple cycle combustion turbines, and new oil-fired stationary internal combustion engines can meet the proposed CO2 emission standards in Part 251. 'This is also true for increases in capacity of at least 25 MW at existing facilities that utilize the equipment and fuel listed above. For facilities that propose a project that utilizes the equipment and fuel listed above, the Department has calculated the increase in cost from this regulation to be zero. (emphasis added).'
Response: The Department has incorporated into the regulation the flexibility for applicants to utilize either a heat input based emission standard or a power output standard. Also, the Department incorporated a 12-month rolling average for compliance with the proposed CO2 emission standards. The Department believes that the combination of these provisions, and the level of the emission standard, will allow the commenter to comply with the regulation. Therefore, the Department will not consolidate combined cycle and simple cycle combustion turbines under the currently proposed simple cycle CO2 emission standards.
Comment 59: We respectfully disagree with the Department's conclusions for the reasons stated herein. In addition, to the specific comments provided, Saranac notes generally that the utilization of an emission performance standard for CO2 that is based on a capacity increase of 25 megawatts is not well reconciled with the federal greenhouse gas permitting requirements advanced under the greenhouse gas tailoring rule where the threshold trigger for permitting is 75,000 tons per year. For natural gas-fueled facilities, a 25 megawatt increase in capacity may not come close to triggering the federal PSD/BACT requirements - as a result, the New York regulations may be significantly more stringent than the federal requirements, particularly since there is no emission increase trigger in the proposed rule.
Likewise, while the proposal contemplates the implementation of federal New Source Performance Standards for greenhouse gases at electric generating units, there is no effort to ensure that the state standards are linked to the federal requirements. While Saranac supports the Department's goals of limiting CO2 emissions from major electric generating facilities, we believe it is important to consider modifying the proposed rules as follows:
Owners or operators of simple cycle combustion turbines, (add combined cycle combustion turbines operated for peaking purposes), 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-load limit) or 160 lbs/mmBtu (input-based limit).
Making the above modification to the proposed regulation will assure facilities with well controlled emissions comply with the proposed regulations as outlined in the cost justification section of the proposed regulations.
Response 60: The commenter is correct that Part 251 does not have the same applicability thresholds as the New Source Review GHG Tailoring rule or the recently proposed NSPS. The Department is required to promulgate Part 251 pursuant to ECL Section 19-0312 and the Power NY legislation, and not based on any federal requirements. The 25 MW capacity applicability threshold for Part 251 is specified in ECL Section 19-0312 and is consistent with the requirements of Article 10. The Department also notes that Part 251 only regulates CO2 emissions, and not all GHG emissions like the federal GHG Tailoring Rule. In other words, there is no direct link between Part 251 and PSD or NSPS regulations. A facility may be subject to any combination of Part 251, NSPS, and PSD GHG BACT in the future. The Department will not consolidate combined cycle and simple cycle combustion turbines under the currently proposed simple cycle CO2 emission standards. Finally, the Department recognizes that Part 251 is more stringent than current federal requirements and is more stringent than the CO2 performance standards recently proposed by EPA.
The American Coalition for Clean Coal Electricity (ACCCE):
Comment 61: ACCCE urges DEC not to adopt its proposed CO2 Performance Standards for Major Electric Generating Facilities because those standards could be inconsistent with the stated goal of reducing greenhouse gas (GHG) emissions. A central purpose of the CO2 Performance Standards is to incent the use of natural gas for electricity generation to reduce GHG emissions. The Regulatory Impact Statement (RIS) that accompanies the proposed standards states that the standards were based on the performance of a natural gas-fueled combined cycle combustion turbine (RIS at 23), that a coal-fueled facility could not meet the standards without carbon capture and sequestration at a "significant increase in capital and operation cost" (RIS Summary at 8), and that the standards would result in the substitution of natural gas for coal for new electric generation (RIS at 54, RIS Summary at 8).
Response: The Department respectfully disagrees with the commenter's statement that the CO2 emission standards could be inconsistent with the stated goal of reducing GHG emissions. Part 251 will serve to prevent new high-carbon sources of energy in the State. Finally, the Department must adopt a regulation pursuant to ECL Section 19-0312, and thus does not have the option to not adopt the standards as requested by the commenter.
Comment 62: However, recent studies suggest that a life cycle comparison of natural gas and coal to generate electricity may show that, contrary to conventional wisdom and the basis for these performance standards, that substituting gas for coal is a wise strategy for addressing climate change. Other literature also suggests that by incenting the use of natural gas over coal for new generation, the CO2 Performance Standards could be counterproductive by increasing overall GHG emissions. While the scientific community continues to examine life cycle GHG emissions from the use of natural gas and coal to generate electricity, it would be more prudent for the DEC to consider alternative approaches to meeting Section 19-0312 of the Environmental Conservation Law, including the alternative it rejected in its RIS of establishing separate standards for coal and gas that would be achievable for each.
Although DEC is correct that the CO2 emissions from a new natural gas combined cycle facility are about one-half those of a new coal-fired facility, DEC failed to consider the relative GHG emissions of the two types of facilities on a life-cycle basis. Life-cycle analysis is particularly important in comparing coal and natural gas electric generating facilities because the natural gas sector is, by a wide and growing margin, the leading source of methane emissions in the nation. Methane is released during natural gas well completion, routine venting and equipment leaks, processing, and transport, storage, and distribution. Moreover, methane is a much more potent greenhouse gas than CO2. Further work must be done to accurately quantify the life-cycle emissions associated with shale gas. As a May 4, 2010 letter from the Council of Science Society Presidents to President Obama stated, "the development of natural gas (methane) from shales is another example where policy has preceded adequate scientific study.... Prior, thorough science-based studies are required to evaluate the impact of massive shale development on ... full life- cycle greenhouse gas emissions."
A fundamental premise for the proposed C02 Performance Standards is that "[n]atural gas ... is a less carbon intensive fuel than coal. .." RIS at 54. Since some scientific literature suggests this premise may be flawed on a life-cycle basis, DEC should reconsider its proposal. The New York legislature cannot have intended that DEC adopt a standard knowing that it could result in a net overall increase in GHG emissions, even if the standard resulted in reduced CO2 emissions at the generating station.
As DEC states, the purpose of Section 19-0312 is to "target[ ] CO2 emissions from major electric generating facilities in order to reduce GHG emissions in New York State." RIS Summary at 5-6. Moreover, the "purpose" and "policy" behind DEC's actions must be to control or abate "air pollution," which DEC considers to be climate change caused by anthropogenically-emitted GHGs. See Sections 1-0101, 19-0103, and 19-0105, cited by DEC as additional authority for adopting the CO2 Performance Standards. This purpose and policy cannot be achieved by adopting standards that could increase, rather than reduce, the emission of substances that DEC considers to be "air pollution." Additionally, DEC's failure to examine the life-cycle GHG emissions of natural gas-fueled facilities violates Section 19-0303 of the ECF. That section provides that if DEC proposes a requirement that is more stringent than the federal Clean Air Act or regulations issued by the U.S. Environmental Protection Agency under that Act, DEC must include in the RIS "a detailed explanation of the reason or reasons that justify exceeding federal minimum requirements, including ... (b) an evaluation of the cost-effectiveness of the proposed code, rule or regulation, in comparison with the cost-effectiveness of reasonably available alternatives; and (c) a review of the reasonably available alternative measures considered by the commissioner and an explanation of the reasons for rejecting such alternatives." Since the RIS for the proposed CO2 Performance Standards fails to discuss the possibility that those standards could result in a net increase in GHG emissions, the RIS discussion as to why it was necessary for DEC to exceed federal standards and as to possible alternatives is inadequate. The RIS considered the alternative of establishing specific CO2 standards for each source and fuel type to meet the requirements of Section 19-0312, but rejected such alternative as not going far enough in reducing CO2 emissions. RIS at 72-73. But that analysis is incomplete absent careful consideration of life cycle GHG emissions. Because the CO2 Performance Standards that DEC is proposing could cause a net increase in GHG emissions, separate and achievable standards for coal- and gas-fueled facilities would make more sense than the proposed CO2 Performance Standards that could turn out to be counterproductive in reducing GHG emissions.
Response: The Department respectfully disagrees that the regulation may cause a net increase in GHG emissions. The CO2 emission limits in subdivisions 251.3(a) and (b) are based on the emissions attributable to the combustion of fuel at the subject emission source. One of the more authoritative analyses on the lifecycle benefits of natural gas is an analysis conducted by the Argonne National Laboratory that concludes that shale gas life-cycle emissions are 6% lower than conventional natural gas, 23% lower than gasoline, and 33% lower than coal.2 Another recent study concludes that the use of natural gas from the Marcellus shale for production of electricity generally has life cycle GHG emissions than are 20-50% lower than coal for production of electricity in the absence of any effective carbon capture and storage processes, depending upon plant efficiencies and natural gas emissions variability.3
The Department recognizes that Part 251 contains CO2 emission standards that are more stringent than those imposed under the federal Clean Air Act. Moreover, Part 251 contains a limit that is more stringent than the NSPS recently proposed by U.S. EPA, which generally includes a 1,000 lbs/MWhr CO2 emission limit rather than the 925 lbs/MWhr limit under subdivision 251.3(a). The Department adequately explained this in the RIS.
1 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. Final Report. New York State Energy Research and Development Authority (NYSERDA), NYSERDA Report 11-18, Albany, New York. http://www.nyserda.ny.gov/climaid
2 Burnham, A., Han, J., Clark, C.E., Wang, M., Dunn, J.B, Palou-Rivera, I. Life-cycle greenhouse gas emissions of shale gas, natural gas, coal, and petroleum. Environ Sci Technol. 2011 Nov 22. [Epub ahead of print]
3 Jiang, M., Griffin, W.M., Hendrickson, C., Jaramillo, P., VanBriesen, J. and Venkatesh, A., Life cycle greenhouse gas emissions of Marcellus shale gas, Environmental Research Letters, August 5, 2011