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Contact Information:
Division of Air Resources
625 Broadway
2nd Floor
Albany, NY 12233-3250
(518) 402-8403
Or view the Department's
Website
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NEW YORK
(5/08)
New York plans on publishing their DG proposal, Part 222, in the state register on June 2, 2008. Then the proposal is
scheduled to go before the New York Environmental Board on September 16, 2008, and is expected to become effective on December 19, 2008.
Key adoption dates can be found here.
(11/07)
The latest version of NYDEC's DG rule, part 222 has been released. The DEC is finalizing some related
documents and plans on submitting the full rulemaking package to the Governor's Office of Regulatory Reform sometime before
the end of 2007.
The DEC did propose a couple of changes in the latest version of the state's DG rule. The first proposed change is a NOx emissions limit for new economic dispatch sources, which are DG sources that are not demand response or emergency
sources. The second change applies to existing DG units, and would require simple cycle and combined cycle turbines used as economic dispatch sources to meet separate NOx emission limits. A copy of the most recent version of New York's DG rule, part 222 can be
accessed here.
(09/06)
The New York Department of Environmental Conservation (DEC) submitted their rulemaking package for Part 222, the state's DG rule, to the Governor's Office of Regulatory Reform on September 14, 2006. A copy of the submitted rule can be found here.
(06/06)
New York is currently working on implementing emission standards for new distributed generation (DG) sources.
New York released its most recent draft of Part 222 in June 2006. The New York Department of Environmental Control (DEC) plans on
adopting the EPA's recently released New Source Performance Standards (NSPS) that would apply to the following types of DG:
- 40 CFR 60, Subpart IIII (compression ignition engines)
- 40 CFR 60, Subpart JJJJ (spark ignition engines)
- 40 CFR 60, Subpart KKKK (turbines)
Subpart 222-2 of the draft rule sets alternative emission standards in case one or more
of the NSPS rules are not finalized. A stakeholder's meeting was held on June 29, 2006. The DEC plans to send the rulemaking
package to the Governor's Office of Regulatory Reform sometime in July 2006. The current draft rule can be found here.
More information can be found here.
| Air Quality Status |
The state is located in the Ozone Transport Region (OTR). For the 1-hour ozone standard there are 10 marginal ozone nonattainment areas,
3 moderate ozone nonattainment areas, and 10 severe ozone nonattainment areas. Regarding the 8-hour ozone standard, there are
16 areas under subpart I, and 13 moderate nonattainment areas. There are 10 areas under nonattainment for PM-2.5, and one area in moderate
nonattainment for PM-10.
EPA's Nonattainment Areas |
| Major Source Threshold |
In the OTR a potential to emit 50 tpy or more of VOC's or 100 tpy of NOx. In severe nonattainment areas
a potential to emit 25 tpy or more of NOx or VOC's. For CO, in moderate nonattainment areas a potential to
emit 50 tpy or more per year. For PM-10, in moderate nonattainment areas, a potential to emit 100 tpy classifies
a source as major. |
| Minor Source Permitting Exemption |
Based on size and fuel type. In general, emissions of any criteria pollutants from major stationary
sources less than 2.5 tpy are exempt from obtaining a permit. Engines 200 hp and less are also exempt. |
| Minor Source Treatment |
Opacity, PM-10 and sulfur limits |
| Emergency Generating Limits |
A unit can operate for up to 500 hours per year during emergencies, routine maintenance, and routine
exercising. |
DE MINIMIS EXEMPTIONS:
To be exempted from permitting a source must be an engine that is smaller than 200 bhp in severe ozone nonattainment areas
and 400 hp in all other areas. Stationary or portable combustion equipment less than 10 MMBtu/hr burning fossil fuels other than coal and coal and
wood fired stationary combustion units with a maximum heat input less than 1 MMBtu/hr are also exempted. Gas turbines with
a heat input at peak load less than 10 MMBtu/hr. Combustion equipment that commenced
operation prior to 6/9/1989 with a maximum heat input of than 20 MMBtu/hr, burning fossil fuels other than
coal are exempt as well. State notification is not required to take this exemption, however operating
and emissions records must be kept.
MINOR SOURCE PERMITTING:
If a source wishes to avoid major source permitting it must take a limit that includes a fuel or hourly operating
limit to ensure the source stays minor. Sources that cap emissions at less than 50% of major source thresholds
can obtain a Registration Certificate, which requires a one page application and does not require specific conditions.
The unit must maintain emission records and the certificate is valid until emissions exceed 50% or the unit is
modified. Sources that limit emissions to below the major source threshold, but above 50% of that threshold obtain
a State-facility permit. The permit will limit hourly operation or annual emissions, but no other controls will
be required. All sources (regardless of permit type) will be subject to an opacity limit of 20%, a PM limit of
0.1 lb/MMBtu and a fuel sulfur limit ranging from 0.2%-1% depending on the source's location. In addition, it is
likely that source's will have to complete an environmental impact assessment of some kind.
There is a 30-day public comment period for sources that are taking limits to stay minor. The whole process
can take a very long time depending on the number of agencies involved and any hearings that are required. State
officials were not willing to estimate a more specific time frame.
MAJOR NSR/PSD PERMITTING:
A potential to emit 250 tons per year of a criteria pollutant triggers PSD, however the state is located in the
OTR which means that only 100 tons of NOx or 50 tpy of VOC's triggers NSR. In the severe nonattainment areas a potential to emit
25 tons of NOx or VOCs triggers NSR.
TREATMENT OF EMERGENCY ENGINES:
A unit can operate for up to 500 hours per year during emergencies, routine maintenance, and
routine exercising.
Article X expired on January 1, 2003. This Article outlined application procedures for units with a
capacity of 80 MW or more. Now owners of EGU's must obtain all appropriate local
and state permits and approvals. System owner must also undergo environmental review subject to the State Environmental Quality Review Act (Article 8
of the Environmental Conservation Law). If system owners are part of an electric corporation then they
must obtain a certificate of public convenience and necessity (CPCN), pursuant to Section 68 of the Public Service Law.
Assembly Bill 4961 , was finalized and committed to the state rules on 6/24/05. This bill calls for the establishment
of a state energy planning board to compose a state energy plan. Bill 4961 sets up a process for the siting
of major EGU's. A similar bill, Assembly Bill 5717 was submitted to the NY Committee on Rules on 6/15/05. Bill 5717
also sets up a state energy planning board to create an energy plan. In addition, the bill establishes a process
for the siting of major and non-major EGU's along with repowering projects.
A single utility (Niagara Mohawk)
in the state of New York has been given authority by the PSC to assess an exit
fee upon customers who exit the grid. (See below)
There was no formal state legislation that brought about restructuring of the electric industry. The State PSC
implemented rules that led to restructuring and in the comments on these rules the PSC states that exit fees
would be prohibited. However, an exception was made for Niagara Mohawk to discourage total bypass of the
Company's retail distribution services and charges where such bypass is not economic from society's standpoint
and to prevent the shifting of the Company's Transition Costs to other stakeholders that would occur in such
circumstances. The exit fee does not apply if a self-generating customer completely isolates itself from the
Niagara Mohawk system or if its electricity is supplied by an on-site third party that installed its generating
capacity after January 1, 2000 and serves only a single customer. If a third party elects to be connected to
Niagara Mohawk's system, they must deliver excess energy to the grid in addition to entering into an agreement
under S.C. No. 7, Niagara Mohawk's standby tariff for retail service. A third party's failure to pay the standby
tariff will result in the collection of a lump sum payment of transition costs.
Rule 1.48: ELECTRICALLY ISOLATE
Separation of electrical points of contact where interconnection may occur, if (a) such separation is at least
100 feet from any other interconnected electrical service of such customer, or (b) the disconnected isolated
service is not within the same building structure as any other interconnected electrical service of such customer
and not housed within a common enclosure with other interconnected breakers and/or fuses of such customer.
P.S.C. No. 207 Rule 52. LUMP SUM PAYMENT OF TRANSITION COSTS BY CUSTOMERS TOTALLY BYPASSING THE COMPANY'S RETAIL
DISTRIBUTION SYSTEM
52.3 APPLICABILITY
The Lump Sum Recovery of Transition Costs authorized by this Rule 52 shall apply to customers and locations
in the Company's service territory served under Schedules P.S.C. No. 207 Electricity and P.S.C. No. 214
Electricity on or after April 6, 1998 which thereafter receive electric service which bypasses the Company's
retail distribution system and Municipal Utilities that serve such customers and locations as set forth
below. This Rule 52 is not applicable to any customer that electrically isolates its load(s) from the
transmission and distribution systems of the Company and all other electric utilities and independent
power producers (other than the customer itself) as specified in Rule 1.48. Rule 52 shall not apply to
a customer's premises which is disconnected from the Niagara Mohawk system when the customer's electricity
is either supplied by the customer or by a third party who is also disconnected from Niagara Mohawk's system
with all of its generating capacity installed after January 1, 2002, located on or immediately adjacent to
the customer's premises and used exclusively to serve that single customer, even if the customer's premises
is located within 100 feet of the Niagara Mohawk system.
Rule 52 shall not apply when the customer disconnects from the Niagara Mohawk system and is connected to a
third party owning generation located on or immediately adjacent to the customer's premises who is
connected to the Niagara Mohawk system with all of its generating capacity installed after January 1, 2002
and whose generating capacity is used to serve only one retail customer at that location with any excess
electricity being delivered over Niagara Mohawk's system, even if that customer's premises is located within
100 feet of the Niagara Mohawk system, as long as the third party generator pays the charges under S.C.No.
7, Niagara Mohawk's standby tariff for retail service. In the event that the third party generator fails to
agree to pay the standby tariff the Lump Sum Contribution towards the Company's Transition Costs will be
assessed as follows.
52.4 LUMP SUM TRANSITION COST CALCULATION METHODOLOGY
The Company shall use a "revenues lost" methodology similar to that proposed by the FERC in Order No. 888 to
determine the Lump Sum Contribution towards the Company's Transition Costs to be made by a customer or a
Municipal Utility. This amount will be calculated on a one-time basis. Adjustments or Credits to reflect
the acquisition by sale or condemnation of the Company's facilities, avoided property taxes and avoided
operation and maintenance expenses, if applicable will be developed by the Company on a case by case basis.
The Company shall entertain levelized annual payments or other options that may be negotiated between the
Company and the customer or the Municipal utility subject to adequate security.
The "revenue lost" formula is equal to the net present value (at the Company's weighted average cost of
capital) over Y years of: (R-E)
R shall be the annual estimated revenue from the customer or, in the case of a Municipal Utility, all of the
customers formerly served by the Company to be served by the Municipal Utility using the bundled price
designs contained in the Settlement agreement. There shall be no credit for transmission related revenues,
as proposed in FERC Order No. 888, unless the customer (s) will continue to use the Company's transmission
system.
E is the Company's estimate of the annual revenues that it can receive by selling or releasing capacity and
associated energy formerly supplied to the customer(s). Consistent with the FERC's Order 888, the
customer(s) shall have the option to market a portion of the released capacity and associated energy.
Y is the number of years required for the Company to recover its full strandable costs. Since Y is dependent
upon a number of factors, including the timing of the departure, the Company will address Y on a
case-by-case basis.
New York City Building Code Division
New York City is governed by its own independent rules governing building and fire codes.
New York State Division of Code Enforcement and Administration
The Codes Division provides a variety of services related to New York's Uniform Fire Prevention and
Building Code and State Energy Conservation Construction Code. The Division provides technical
assistance, administers variances, delivers educational courses, oversees the enforcement practices of
local governments and serves as secretariat to the State Fire Prevention and Building Code Council.
International Code Council State Adoption Information Page
Provides an easy to use US map to locate state and local adoption of the International Code Council's model codes.
US DOE's Office of Building Technology, State and Community Programs, Building Codes Database
The US DOE's database provides a comprehensive look at a state's building code implementation and enforcement
process.
On January 23, 2004, the PSC mandated that Consolidated Edison (Con Ed), New York State Electric & Gas Corporation
(NYSEG), Orange and Rockland Utilities (O&R), Rochester Gas & Electric Corporation (RG&E) and Central Hudson Gas & Electric (Central Hudson)
modify their standby service tariffs. This was in response to a July 2003 order that required these five utilities
to offer existing on-site generation customers the option of a phase-in to full standby service rates or possible exemption
from these rates. CHP units that intimate service prior to May 31, 2006 and that have 60% annual fuel efficiency as well as at least 20% thermal
output are eligible for this exemption.
INTERCONNECTION STANDARDS:
The State has the following requirements:
Applicable Technologies: Solar Thermal Electric, Photovoltaics, Landfill Gas, Wind, Biomass, Hydroelectric, Geothermal Electric, Fuel Cells, Municipal Solid Waste, CHP/Cogeneration, Microturbines, Other Distributed Generation Technologies
Net Metering Rules: Yes
Size Requirements: 2 MW
Interconnection Agreement:Yes, the most recent Revised Standard Interconnection Requirements went into effect in 2004
Additional Insurance:Yes, amount not specified
External Disconnect Necessary:
Yes
New York State Energy Research And Development Authority (NYSERDA)
NYSERDA was as a public benefit
corporation by law in 1975. It funds research into energy supply and efficiency, as well as energy-related
environmental issues, important to the well-being of New Yorkers. There are a number of ongoing economic incentives
programs for DG. A description of current funding opportunities can be accessed by clicking
here.
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