WHAT'S NEW:

No recent state activity has been identified.

AIR EMISSIONS REGULATIONS:

Air Quality Status	The whole state is in moderate nonattainment for ozone EPA's Nonattainment Areas
Major Source Threshold	50 tons of NOx or VOCs triggers NSR. 100 tons of any other criteria pollutant triggers NSR.
Minor Source Permitting Exemption	Based on size and fuel
Minor Source Treatment	BACT
Emergency Generating Limits	PTE based on 500 hours

DE MINIMIS EXEMPTIONS

Projects that meet the following specifications are exempt from permitting:

• Units burning residual oil, solid fossil fuels or alternative fuels, including wood chips, hazardous wastes or waste oil with a heat input below 1 MMBtu/hr
• Units burning all other liquid fuels with a heat input below 5 MMBtu/hr
• Units burning gaseous fuel with a heat input below 10 MMBtu/hr
  
  No state notification is required, but it is strongly recommended.

MINOR SOURCE PERMITTING

BACT is required for all criteria and hazardous pollutants that the unit has a potential to emit. A modification must apply BACT for each pollutant for which there would be a net emissions increase at the stationary source. Any project that exceeds the exemption levels (listed above) and does not trigger Title V is subject to minor source permitting. Sources subject to minor permit requirements can apply for a general permit, which is a pre-approved minor source permit. Regulation No. 43, which becomes effective on May 15, 2007 outlines general permit requirements for smaller sources. DG, CHP, and other smaller EGU's may be eligible under the general permit if they meet certain conditions. To be eligible for a general permit, DG units must meet certain NOx, CO, CO2, PM, sulfur and opacity limits, which are described in the table and text below. Also, DG systems can receive credit (emissions that were or would have been produced through flaring can be deducted from the actual emissions of the distributed generator) for the use of fuels that otherwise would be flared. If the actual emissions from flaring cannot be documented then a default value of 0.1 lbs/MMBtu will be used for NOx, 0.7 lbs/MMBtu for carbon monoxide, and 117 lb/MMBtu for CO2.

CHP units under the general permit system are eligible to receive emissions credits related to thermal output if they have a power-to-heat ratio between 4.0 and 0.15, have an efficiency of at least 55% and meet certain emission requirements. More information on how CHP is treated under the general permit can be found here.

Date of Installation	NO x (lbs/MWh)	PM (lbs/MWh)	CO (lbs/MWh)	CO 2 (lbs/MWh)
On or after 05/15/07	0.6	0.7	10	1,900
On or after 01/01/09	0.3	0.07	2	1,900
On or after 01/01/12	0.15	0.03	1	1,650

Additionally, to be eligible for the general permit, the sulfur content of any liquid fuel burned in the distributed generation (DG) unit cannot exceed 15 ppm by weight. The sulfur content of any gaseous fuel burned cannot exceed 10 grains per total sulfur per 100 dry standard cubic feet. Visible emissions from the DG system cannot exceed 10% opacity except for a period or periods aggregating no more than three minutes in any one-hour.

MAJOR NSR/PSD PERMITTING

LAER is required for large projects. For NOx and VOC, 50 tons per year triggers NSR. All other criteria pollutants trigger NSR at 100 tons per year. For major modifications to existing resources which have a potential to emit greater than 50 tons per year but less than 100 tons per year of VOCs or NOx, the source must apply BACT instead of LAER. For major modifications to a stationary source which has the potential to emit great than 100 tpy for VOCs or NOx the source must meet an emissions limit considered to be the lowest achievable emission rate unless internal offsets of such volatile organic compounds or nitrogen oxides are obtained at a ratio of at least 1.3 to 1, then the source can apply BACT instead of LAER. Major Source permitting requirements are located in Regulation No. 9.

TREATMENT OF EMERGENCY ENGINES

Emergency engine requirements are outlined in Air Pollution Control Regulation No. 43, http://www.dem.ri.gov/pubs/regs/regs/air/air43_07.pdf. Emergency engines can operate up to 500 hrs/year. A BACT analysis is not required, but units have to meet the emission standards set by the US EPA for nonroad engines (40 CFR 89). Also, emergency generators must meet a CO2 standard of 1,900 lbs/MWh if installed on or after 5/15/07 and a limit of 1,650 lbs/MWh if installed on or after 1/1/12. The sulfur content of any liquid fuel burned in the emergency generator must not exceed 15 ppm by weight and for gaseous fuel not more than 10 grains of sulfur per 100 dry standard cubic feet. Visible emissions from emergency generators may not exceed 10%. Units can only operate during maintenance, testing, and emergencies.

SITING REQUIREMENTS FOR NON-UTILITY GENERATORS:

Any electrical generation facility greater than 40 MW must receive approval from the Rhode Island Energy Facility Siting Board.

Energy Facility Siting Board Rules

The Board is the licensing and permitting authority for all licenses, which under any statute of the state or ordinance of any political subdivision of the state, would be required for siting, construction or alteration of a major energy facility in Rhode Island, except for licenses, issued by the Department of Environmental Management under the delegated authority of federal law of Chapter 2- 1 of the Rhode Island General Laws, or licenses issued by the Coastal Resources Management Council under Chapter 46-23 of the Rhode Island General Laws.

p) "Major Energy Facility" means any facility for the extraction, production, conversion and processing of coal; any facility for the generation of electricity capable of operating at a gross capacity of 40 megawatts or more; any transmission line with a design rating of 69 kV or over; facilities for the conversion, gasification, treatment, transfer or storage of liquefied natural and liquefied petroleum gases; any facility for the processing, enrichment, storage or disposal of nuclear fuels and nuclear byproducts; any facility for the refining of oil, gas or other petroleum products; any facility of 10 megawatts or greater capacity for the generation of electricity by water power; any facility associated with the transfer of oil, gas or coal via pipeline and any energy facility project of the Rhode Island Port Authority and Economic Development Corporation.

BUILDING, ZONING AND FIRE CODES:

Building Codes: Rhode Island has adopted the Rhode Island State Building Code, which is enforced statewide. It is based on the 2006 IBC and includes state-specific amendments.

• Building and Fire Codes Website

Energy Codes : Pennsylvania has adopted the 2006 IECC with some amendments.

• Office of Energy Resources

Fire Codes: Rhode Island has adopted the Rhode Island Uniform Fire Code, which is enforced statewide. It is based on the 2003 NFPA 1: Uniform Fire Code, and includes state-specific amendments.

• Office of the State Fire Marshal

Zoning: Zoning and planning happens at the local level. Check with each jurisdiction regarding their zoning codes.

Resources (information may not be as current as provided above)

A general overview of each state’s enacted codes can be found HERE.

The International Code Council Adoption page gives state-by-state adoption status of specific ICC codes, as well as information about code adoption by some municipal governments within that state.

Information about energy codes can be found at the DOE’s Building Codes for Energy Efficiency page or at the Building Codes Assistance Project.

INTERCONNECTION REQUIREMENTS:

Rhode Island does not have statewide interconnection standards.

Narragansett Electric Co (National Grid), IOU -has interconnection standards for net-metered systems and for larger DG units that are not net-metered. There is a streamlined one-page interconnection form. Additional insurance and an external disconnect are not required.

Interconnection information can be found here.

EXIT FEES:

According to the PUC there are no exit fees in the state of Rhode Island. The only exception is if a customer (large industrial) had an existing agreement with a utility that built additional generating capacity specifically for that customer. The fees of termination would be stipulated in the initial agreement.

UTILITY STANDBY RATES:

Narragansett Electric

200 kW Back-Up Service Rate (B-32)	Back-Up Service	Supplemental Service
Load Size	> 25 kW and < 3,000 kW	> 25 kW and < 3,000 kW
Customer Charge	$236.43 per month	N/A
Transmission Demand Charge	N/A	$1.27 per kW
Distribution Demand Charge	$5.12 per kW	$2.00 per kW
Transmission Adjustment Factor	N/A	$0.00541 per kWh
Distribution Energy Charge	N/A	$0.00889 per kWh
Non-bypassable Transition Charge	N/A	$0.00322 per kWh
C&LM Adjustment	N/A	$0.00230 per kWh
Generation: Standard Offer	N/A	per standard offer service tariff

 

3,000 kW Back-Up Service Rate (B-62)	Back-Up Service	Supplemental Service
Load Size	> 3,000 kW	> 3,000 kW
Customer Charge	$17,118.72 per month	N/A
Distribution Demand Charge	$2.24	$2.24
Transmission Demand Charge	N/A	$1.39
Transmission Adjustment Factor	N/A	$0.00541 per kWh
Distribution Energy Charge	N/A	N/A
Non-bypassable Transition Charge	N/A	$0.00322 per kWh
C&LM Adjustment	N/A	$0.00230 per kWh
Generation: Standard Offer	N/A	per standard offer service tariff

 

High Voltage Back-Up Service Rate (B-72)	Back-Up Service	Supplemental Service
Load Size	High Voltage	High Voltage
Customer Charge	$63.75 per month	N/A
Distribution Demand Charge	$0.35 per kW	$0.35 per kW
Transmission Demand Charge	$1.34	$1.34
Transmission Adjustment Factor	$0.00042 per kWh	$0.00042 per kWh
Distribution Energy Charge	$0.00396 per kWh	$0.00396 per kWh
Non-bypassable Transition Charge	N/A	$0.00855 per kWh
C&LM Adjustment	N/A	$0.00230 per kWh
Generation: Standard Offer	N/A	$0.0059 per kWh