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Part 222 and Subpart 227-2 Revised Regulatory Flexibility Analysis for Small Businesses and Local Governments

The Department of Environmental Conservation (Department) proposes to adopt 6 NYCRR Part 222, 'Distributed Generation Sources' and revise Part 200, 'General Provisions' and Subpart 227-2, 'Reasonably Available Control Technology (RACT) for Oxides of Nitrogen (NOx)' to conform to new Part 222. A distributed generation (DG) source is any stationary internal combustion engine used to produce electricity exclusively for use at the host facility. The purpose of this rulemaking is to establish emission limits, recordkeeping and testing requirements for DG sources.

Effect of The Rule

Distributed generation can be used to meet all or part of the electricity demand of any facility for short periods of time (e.g., emergency generator use during a blackout) or year-round. The type of DG application depends upon the needs of the facility (e.g., the need for a constant, reliable electricity supply) and economic considerations. Distributed generation is used in a wide range of commercial and industrial facilities including, but not limited to, hospitals, financial institutions, colleges, shopping centers, farms, apartment complexes and office buildings. It is estimated that as many as 26,000 sites in New York could potentially use combined heat and power (CHP) systems.1,2 Although not all of those sites would use CHP systems, this estimate provides insight as to the number of sites where DG applications might be used. Small businesses and local governments with DG sources other than emergency generators would be subject to emission standards and emissions testing requirements set forth in Part 222.

Energy services companies (ESCOs) would also be affected by Part 222. ESCOs enroll facilities into demand response (DR) programs sponsored by the New York Independent System Operator and some transmission operators. ESCOs' DR portfolios contain curtailment, load shifting, energy efficiency and DG resources. Most DG resources in these portfolios are uncontrolled, diesel-fired engines that would be subject to NOx and PM emission standards set forth in Section 222.4 of the rule. These standards would take effect on May 1, 2017. Post-combustion pollution control systems would likely be required for most engines that commenced operation prior to the effective date of Part 222 in order to meet the emission standards. There is a possibility that owners of generators enrolled in DR programs may not make the necessary investments to meet the emission standards and would be dropped from ESCOs' DR portfolios resulting in a reduction in income for both the ESCO and the source owner.3 DG resources comprised 13 percent of the resources enrolled in the NYISO's Emergency Demand Response Program and Special Case Resources Program (combined) as of May 2011.4 Therefore, it is expected that the provisions of Part 222 would minimally impact ESCOs.

Compliance Requirements

On the effective date of this rule, Part 222 would apply to DG sources that meet the following thresholds:

  1. mechanical output rating of 200 horsepower (hp) or greater for sources located in the New York City metropolitan area; and
  2. mechanical output rating of 400 hp or greater for sources located outside of the New York City metropolitan area.

Emergency generators owned by municipalities or municipal agencies may by operated in cases where the usual supply of electricity is still available if such operation would prevent a violation of the Clean Water Act or Article 17 of the ECL through April 30, 2021. The purpose of this provision is to allow such generators to run in order to prevent direct sewage discharges to waterways in the state. Beginning May 1, 2021, such sources would be required to meet the standards set forth in Section 222.4 of Part 222 or be replaced with engines meeting standards adopted by the United States Environmental Protection Agency.

Also on the effective date of this rule, the maintenance and testing of emergency power generating stationary internal combustion engines would be prohibited during the hours of 1:00 pm and 8:00 pm during the period of May 1 through September 30 of each year.

By January 2, 2017, owners or operators of DG sources required to operate under permits or registration certificates must notify the Department whether the sources would be operated as emergency generators or economic dispatch sources. In cases where such notification is not provided by the compliance date, the DG source would be considered an economic dispatch source for regulatory purposes.

On May 1, 2017, the following NOx emission limits would apply to economic dispatch sources subject to Part 222:

  • natural gas-fired simple cycle combustion turbines: 50 parts per million on a dry volume basis (ppmvd)
  • corrected to 15 percent O2
  • oil-fired simple cycle combustion turbines: 100 ppmvd corrected to 15 percent O2
  • natural gas-fired combined cycle combustion turbines: 25 ppmvd corrected to 15 percent O2
  • oil-fired combined cycle combustion turbines: 42 ppmvd corrected to 15 percent O2
  • natural gas engines: 1.5 grams per brake horsepower-hour (g/bhp-h)
  • diesel-fired engines: 2.3 g/bhp-h

Also on May 1, 2017, diesel-fired DG sources must be in compliance with one of the following requirements regarding particulate emissions:

  1. must be equipped with a pollution control device designed to remove 85 percent or more of the PM in the exhaust stream; or
  2. must be in compliance with a particulate emission limit of 0.30 g/bhp-h.

By April 30, 2017, owners and operators of DG sources subject to an emission limit(s) must conduct an initial emissions test to demonstrate compliance with the emission limits set forth in Part 222. Additional testing must be conducted at a frequency of once every 10 years. Also, the rule requires owners and operators of DG sources to notify DEC 60 days prior to testing and to submit a copy of the test report to DEC within 60 days following the test. Records of the emission tests must be maintained and made available to the DEC.

Emission testing for PM is not required for engines equipped with pollution control devices verified by the California Air Resources Board (CARB) as meeting the Level 3 or Level 3 Plus classification per the California Code of Regulations, Title 13, Sections 2700-2711.

Within one year of the effective date of the rule or within 12 months of commencing operation of a DG source subject to the rule, whichever is later, the owner and operator of the source must conduct an initial tune-up of the source. Additionally, the DG source must be tuned-up at least once every 12 months. Records of annual tune-ups must be maintained at the facility for a period of five years.

Professional Services

The services of an engineering consultant may be required in order to complete a permit. A stack testing company would be required to conduct the emissions testing required in 222.6. The services of a certified technician may be required to conduct the annual tune-up required in Section 222.4.

Compliance Costs

The costs for post-combustion control systems are presented in the following sections for 1200 hp and 2000 hp engines. As a point of comparison, replacement costs for new 1200 hp or 2000 hp engines that meet the NSPS requirements range from $525,000 to $1,000,000.5,6

Selective Catalytic Reduction (SCR) Systems

Selective catalytic reduction (SCR) systems can reduce the NOx emissions from lean-burn natural gas fired-engines and diesel-fired engines by up to 90 percent.7 The capital cost (installed) of SCR control systems are presented in Table 1.

Table 1: Capital Costs for SCR Systems
Cost Component 1200 hp Engine 2000 hp Engine
SCR System8 $103,000 $171,700
Installation $61,800 $103,000
Taxes $8,300 $13,800
Testing9 $15,000 $15,000
Total Cost $188,100 $303,500

Operational costs vary depending upon several factors. The primary driver is the reagent (urea) cost. The other operational factors DEC considered in developing cost estimates for SCR systems were insurance, maintenance and labor costs.

The Department evaluated the costs for operating SCR systems under a wide range of scenarios over a 10-year period. Control costs of $5,000 per ton of NOx reduced are considered reasonable under Subpart 227-2. For pre-NSPS engines, the cost per ton of NOx reduced would be less than $5,000 for sources operating 1,500 hours per year or more. For post-NSPS engines, the $5,000 per ton threshold would be met when operating 3,000 hours per year or more. Therefore, in the opinion of the Department, the costs to operate SCR systems are reasonable.

Non-Selective Catalytic Reduction (NSCR) Systems

Non-selective catalytic reduction (NSCR) systems can reduce the NOx emissions from rich-burn natural gas fired-engines engines by up to 98 percent.10 The capital cost (installed) of NSCR control systems are presented in Table 2.

Table 2: Capital Costs for NSCR Systems
Cost Component 1200 hp Engine 2000 hp Engine
SCR System $26,700 $44,400
Installation $16,000 $26,700
Taxes $2,100 $3,500
Testing11 $8,000 $8,000
Total Cost $52,800 $82,600

NSCR catalysts need to be replaced every five years.12 Replacement catalysts are estimated to cost 7 percent of the original NSCR system cost. In DEC cost analyses, the cost of installing the replacement catalyst was assumed to be 60 percent of the cost of the new catalyst. Annual costs for operating NSCR include insurance, maintenance and labor. The cost per ton of NOx reduced is less than $5,000 when operating more than 200 hours per year.

'Particulate Matter (PM) Emissions'

Particulate control equipment (e.g. - particulate traps or oxidation catalysts) may be required in order for some sources to comply with the particulate emission standard. The costs for particulate control equipment are approximately $55 per KW installed ($49,200 - $82,000 for the engine sizes discussed in this section).13

'Compliance Testing'

The emission testing costs are estimated to be $8,000 (NOx only) to $15,000 (NOx and PM) per source.14 Emission testing for PM is not required for engines equipped with pollution control devices verified by the California Air Resources Board as meeting the Level 3 or Level 3 Plus Classification per Chapter 14, Title 13 of the California Code of Regulations.

Minimizing Adverse Impact

There were several instances where the Department incorporated measures into Part 222 to minimize the impact of the rule on small businesses or local governments. Summaries of these measures are presented below.

There are five alternative compliance options for owners or operators of economic dispatch sources set forth in Section 222.5 of Part 222. These options include source-specific emission rates in cases where it is economically or technically infeasible to meet the NOx standard; additional time to permanently shut down a DG source; converting a diesel-fired economic dispatch source to fire natural gas; and a credit for using a renewable generation system (photovoltaic or wind generation systems). Further, a one-year extension of the compliance date for sources enrolled in demand response programs established to maintain reliability of the electric grid is included in the rule. This provision is limited to DG sources enrolled in demand response programs in 2014 or 2015.

The Department considered establishing caps on the number of sources enrolled in demand response programs to reduce emissions from this source category. The capacity of such units, measured in units of megawatts, would have been used as a basis for the caps. This alternative was rejected because the implementation of the capping provisions would put the Department in the position of determining which demand response sources could be enrolled in a demand response program by approving or denying permit applications. This could put the Department in the position of regulating demand response programs which is not within the Department's legal authority.

New biogas-fired sources would be exempt from Part 222. Farms with animal waste digesters and municipalities with waste water treatment plants would only need to comply with 40 CFR 60 Subpart JJJJ when installing and operating new DG sources fired with biogas.

Small Business and Local Government Participation

The proposed rulemaking is the result of a stakeholder process initiated by the Department in 2001. Stakeholder Meetings were held on November 13, 2001, December 12, 2002, April 8, 2003, May 17, 2004, June 29, 2006 and June 25, 2013. Drafts of Part 222 were circulated electronically to stakeholders in May 2004, January 2005, June 2006 and May 2013. More than 175 stakeholders have been involved in the process of developing Part 222 and anyone who requested to be added to the list of stakeholders was added. The meeting of April 8, 2003 was advertised in the Department's Environmental Notice Bulletin.

Many of the participants in the stakeholder process represented small businesses and local governments. These groups include law firms, consultants, trade organizations, manufacturers, and governmental agencies that work with small businesses and local governments.

Economic and Technical Feasibility

The pollution control technologies that would be required in order for a small business or local government to comply with the emission standards incorporated into Part 222 are readily available and are proven technologies. Three-way catalyst systems for rich-burn engines and selective catalytic reduction systems are used today in a wide-range of applications.

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1 CHP is a subset of distributed generation sources in which energy is recovered from exhaust gases to provide heat or hot water.
2 "NYSERDA's CHP Program: Moving the Market Forward", Dana Levy and Brian Platt. Presentation at the NYSDPS CHP Technical Conference, May 13, 2013.
3 Demand response payments are not the primary source of income for DR source owners or operators.
4 "Semi-Annual Compliance Report on Demand Response Programs", NYISO, June 1, 2011.
5 E-mail from Joe Suchecki (Truck & Engine Manufacturers Association) to John Barnes (DEC) dated November 8, 2013.
6 Replacement costs as well as the costs for pollution control systems could be higher than the costs presented in this section in cases where there are space limitations or building or fire code requirements that must be met.
7 "NOx Control for Stationary Gas Engines", Wilson Chu (Johnson-Matthey), Advances in Air Pollution Control Technology, MARAMA Workshop, May 19, 2011.
8 Sources: CARB 2010. Regulatory Analysis for Revisions to Stationary Diesel Engine Air Toxic Control Measure. Appendix B. Analysis of Technical Feasibility and Costs of After-treatment Controls on New Emergency Diesel Engines; and (2) Producer Price Index, U.S. Department of Labor, Bureau of Labor Statistics.
9 Testing costs include NOx and PM tests (diesel engines). For natural gas-fired engines, the estimated cost is $8,000 for NOx tests only.
10 "NOx Control for Stationary Gas Engines", Wilson Chu (Johnson-Matthey), Advances in Air Pollution Control Technology, MARAMA Workshop, May 19, 2011.
11 Emissions tests for NOx only since the PM standard does not apply to natural gas engines.
12 E-mail from Wilson Chu (Johnson Matthey) to John Barnes (DEC) dated January 24, 2008.
13 Sources: CARB 2010. Regulatory Analysis for Revisions to Stationary Diesel Engine Air Toxic Control Measure. Appendix B. Analysis of Technical Feasibility and Costs of After-treatment Controls on Emergency Diesel Engines; and (2) Producer Price Index, U.S. Department of Labor, Bureau of Labor Statistics.
14 Stack testing costs are based upon an informal Department survey of several stack testing companies.


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