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Contact Information:
Department of Environmental Management
235 Promenade Street
Providence, RI 02908-5767
(401) 222-2808
Or view the Department's
Website
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RHODE ISLAND
Latest News
Rhode Island Finalizes Output Based Regulations for CHP (5/2007)
The Rhode Island Department of Environmental Management’s Office of Air Resources has adopted final regulations for Regulation No. 43 - General Permits for Smaller-Scale Electric Generation Facilities and Regulation No. 9 - Air Pollution Control Permits. These regulations are set to become effective on May 15, 2007. Regulation No. 43 applies output based emission standards and provides credit for CHP applications. More information on these new regulations can be found here.
Rhode Island's Proposed DG/CHP Regulations (9/13/05)
Rhode Island has completed a draft of their CHP/DG rule,
entitled, "General Permits for Smaller-Scale Electric
Generation Facilities." The draft has been sent to stakeholders for comments,
which will be accepted until early October. Then the Department of Environmental Management plans
on going through the process for adoption of these new regulations. The draft rule is basically
the same as the RAP Model Rule, including credit for CHP.
Summary of Key Points
Applicability: The rule applies to generators that have a heat input capacity of 350,00 Btus or more per hour.
Emergency generators can operate for up to 500 hours per year.
CHP installations must meet the following requirements:
1) The power-to-heat ratio must be between 4.0 and 0.15.
2) The design system efficiency must be at least 55%.
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. 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.
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 grater than 50 tons per year but less than 10 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 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.
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.
There are no exit fees for DG in the state of Rhode Island. (See below)
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.
Rhode Island State Building Codes
Provides a list of the currently adopted state building codes.
Rhode Island Fire Safety Code Board of Appeal and Review
The Fire Safety Code Board of Appeal and Review is charged with the development and administrative review
of a comprehensive fire code covering the state of Rhode Island. The Board sits as an adjudicatory body
by providing both the review of code enforcement decisions made by the State Fire Marshal's Office and
granting variances from strict compliance with the code in cases of structural hardship.
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.
Narragansett Electric
|
General C&I Back-Up Service Rate (B-02) |
Back-Up Service |
Supplemental Service |
| Load Size |
< 200 kW |
< 200 kW |
| Customer Charge |
$103.41 per month |
N/A |
| Distribution Demand Charge per kW in excess 10 kW |
$2.91 |
$2.91 |
| Transmission Demand Charge per kW in excess 10 kW |
$1.40 |
$1.40 |
| Transmission Adjustment Factor |
$0.00042 per kWh |
$0.00042 per kWh |
| Distribution Energy Charge |
$0.00992 per kWh |
$0.00992 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 |
|
200 kW Back-Up Service Rate (B-32) |
Back-Up Service |
Supplemental Service |
| Load Size |
> 200 kW and < 3,000 kW |
> 200 kW and < 3,000 kW |
| Customer Charge |
$236.43 per month |
N/A |
| Transmission Demand Charge |
$1.27 per kW |
$1.27 per kW |
| Distribution Demand Charge |
$1.56 per kW |
$1.56 per kW |
| Transmission Adjustment Factor |
$0.00042 per kWh |
$0.00042 per kWh |
| Distribution Energy Charge |
$0.0101 per kWh |
$0.0101 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 |
|
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 |
$0.75 |
$0.75 |
| Transmission Demand Charge |
$1.39 |
$1.39 |
| 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 |
|
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 |
****Special Note: These are the Standby Rates in effect at the time of the creation of this database. For the most
current utility standby rates, click on the utility's name in the box named "Major Utilities" in the upper left-hand corner of this page.
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