| Contact Information:
The Department of |
Relevant State Sites: Connecticut DPUC Connecticut SitingCouncil Connecticut Emissions Regulations Northeast CHP Application Center |
Major Utilities: Connecticut Light and Power (CL&P) United Illuminating Company (UL) |
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WHAT'S NEW:
No recent state activity has been identified.AIR EMISSIONS REGULATIONS:
There are 8 areas in moderate nonattainment for 8-hr ozone, and 2 areas in nonattainment for PM 2.5. Connecticut is also in the Ozone Transport Region (OTR). |
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100 tons of NOx or VOCs in moderate nonattainment areas or 250 tons of any other criteria pollutant in attainment areas. 25 tons of NOx or VOCs in severe nonattainment areas. 100 tons of PM in nonattainment area. |
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None |
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State BACT and opacity requirements |
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500 hours per year or fuel limit (general permit) |
DG SPECIFIC REGULATIONS:
The state's DG rule Section 22a-174-42 went into effect on January 1, 2005. The rule classifies DG as any new or existing generator with a nameplate capacity less than 15 MW that generates electricity for other than emergency use. Electricity generated may be used either onsite or for sale under an agreement with a utility, other market participant or system operator. Such a generator may also generate electricity for use during an emergency but is not defined as an emergency generator.
The rule initially contained a limit on ammonia emissions of 2.0 ppm. However, the limit was removed at the urging of the Engine Manufacturers Association. In order to demonstrate compliance with the emissions limitation detailed below, an owner or operator shall either obtain a certification from the DG technology manufacturer or conduct a performance test and submit the results to the state DEP.
Emissions Standards for Existing DG
NO x (lbs/MWh) |
PM (lbs/MWh)* |
CO (lbs/MWh) |
CO 2 (lbs/MWh) |
4.0 |
0.7 |
10 |
1,900 |
* The particulate matter standards shall apply only to a distributed generator with a reciprocating engines using liquid fuel.
Emissions Standards for New DG
Date of Installation |
NO x (lbs/MWh) |
PM (lbs/MWh) |
CO (lbs/MWh) |
CO 2 (lbs/MWh) |
On or after 01/01/05 |
0.6 |
0.7 |
10 |
1,900 |
On or after 05/01/08 |
0.3 |
0.07 |
2 |
1,900 |
On or after 05/01/12 |
0.15 |
0.03 |
1 |
1,650 |
There is credit for CHP application; which follows the RAP Model Rule language. None. Sources will be required to complete a state BACT analysis for potential emissions of 15 tons or more per year of any individual air pollutant, from each new emissions unit or from a modification to an existing unit. The state does not have specific cost thresholds. There are state opacity and particulate requirements and modeling may be required.
There is a 30 day public comment required for new permits. The entire permitting process takes approximately 6 months. The permitting process for systems that are eligible for general permits may be significantly less.
Most of the state is in moderate nonattainment for ozone which means 100 tons of NOx or VOC triggers NSR. 250 tons of any other criteria pollutant triggers PSD. There are two areas in nonattainment for PM and 100 tons of PM triggers NSR in this area.
TREATMENT OF EMERGENCY ENGINES
Sources may elect to conform with a general permit for emergency generators or operate under an emergency generator exemption. The unit may take this exemption by meeting one of the following limits:
- Unit must have less than 300 hour of operation per year and operate only during emergencies and for maintenance. The unit must also have a fuel sulfur content that meets the requirements for motor diesel fuel. Motor diesel vehicle fuel is defined as on-road diesel fuel that meets the sulfur limits of has a diesel fuel sulfur limit of 0.05 percent by weight. 80.520 applies to motor vehicle diesel fuel and applies a sulfur limit of 15 ppm maximum.
- Unit may take a fuel limit of 3.36 million cubic feet of gaseous fuel, 21,000 gallons of distillate fuel, or 100,000 gallons of propane. No state notification is required for the exemption, but record keeping is required.
A general permit option applies to new or existing distributed generation resources. General permit guidelines for these DG systems were last issued on January 9, 2008 and can be accessed from, http://www.ct.gov/dep/lib/dep/Permits_and_Licenses/Air_Emissions_Permits/dgr_gp.pdf.
Option 1: General Permit to Construct and/or Operate a New or Existing Distributed Generation Engine
The general permit applies to an engine that meets the following requirements – (1) is rated at no more than 2 MW of electricity; (2) has received approval from the Department of Public Utility Control (DPUC) to participate in the markets administered by the regional independent system operator in accordance with Section 103 of the , which establishes a pilot program to allow generation sources to run more often on an economic and reliability dispatch basis, to reduce emissions through load shifting, and energy conservation, and for other purposes; and is not considered a major modification or major stationary source (defined as having the potential to emit 25 tons per year of NOx or VOCs for modifications or severe ozone nonattainment areas, and 50 tons per year in serious ozone nonattainment areas). The permit is effective from the date it is issued until December 31, 2010 or ninety days after the energizing of the Middletown-Norwalk 345 kv transmission line. A registration fee of $5,000 applies to any person other than a municipality, or $2,500 for any municipality and must be submitted with the registration form. Engines are permitted to operate up to 500 total hours per year, demand response operation is limited to 200 hours per year and emergency response is limited to 300 hours. Some general emission guidelines are as follows -
Example Limits for Connecticut General Permit
Pollutant |
Emissions Limit |
SO2 |
Max fuel content of 0.0015% by weight, or 15 ppmv sulfur |
NOx |
SCR or equivalent NOx controls with a design efficiency of at least 90% must be installed. |
PM |
0.01 gr/bhp-hr for new/existing units, unless existing units have particulate matter controls with at least an 85% efficiency |
Opacity |
No more than 10% for any 6-minute block average or 40% reduced to a one-minute block average. |
Units may only peak shave when called upon by the ISO-NE. Emergency operation may occur during an interruption of electrical power, a deviation in the voltage supplied or to minimize damage from fire, flood waters, or other catastrophic event, natural or man-made.
No routine maintenance or testing may be performed on days when the air quality index is forecasted to be “unhealthy for sensitive groups,” “unhealthy,” “very unhealthy,” or “hazardous.” Units may only burn liquid fuel with an API gravity greater than 30 or a gaseous fuel, however gasoline may not be used. CEMS are required if multiple sources are supplied by one fuel tank or if one source has multiple tanks.
SITING REQUIREMENTS FOR NON-UTILITY GENERATORS:
Connecticut has some of the most difficult siting regulations of any state. The Connecticut Siting Council exempts from need of a Certificate of Environmental Compatibility and Public Need, renewable energy sources less then 1 MW, cogeneration sources less than 25 MW, or if the Council determines that the facility qualifies as a small power producer under PURPA and is primarily for the producer's own use. At least 60 days prior to submitting an application to the Commission a proposed generation facility must consult with local municipal authorities. A filling fee must accompany the application determined by the following schedule: Construction costs up to $5,000,000, 0.05% or $1,000 whichever is greater and over $5,000,000, 0.10% or $25,000. In addition, the proposed generation facility must meet fairly stringent air and environmental regulations.
Sec. 16-50i. Definitions. As used in this chapter:
(a) "Facility" means:
(3) any electric generating or storage facility using any fuel, including nuclear materials, including associated equipment for furnishing electricity but not including an emergency generating device, as defined in subsection (f) of this section or a facility
(i) owned and operated by a private power producer, as defined in section 16-243b,
(ii) which is a qualifying small power production facility or a qualifying cogeneration facility under the Public Utility Regulatory Policies Act of 1978, as amended, or a facility determined by the council to be primarily for a producer's own use and
(iii) which has, in the case of a facility utilizing renewable energy sources, a generating capacity of one megawatt of electricity or less and, in the case of a facility utilizing cogeneration technology, a generating capacity of twenty-five megawatts of electricity or less;
(f) "Emergency generating device" means an electric generating device with a generating capacity of five megawatts or less, installed primarily for the purpose of producing emergency backup electrical power for not more than five hundred hours per year, and that (1) does not have a substantial adverse environmental effect, as determined by the council, or (2) is owned and operated by an entity other than an electric, electric distribution or gas company or (3) is under construction or in operation prior to May 2, 1989.
(3) "Private power producer" means
(A) a subsidiary of a gas public service company which is not affiliated with an electric public service company, or a subsidiary of a holding company controlling, directly or indirectly, a gas public service company but not an electric public service company, which generates electricity solely through ownership of fifty per cent or less of a private power production facility or, with the approval of the Department of Public Utility Control, through ownership of one hundred per cent of a private power production facility which
(i) uses a source of energy other than gas as the primary energy source of the facility or
(ii) uses gas as the primary energy source of the facility and uses an improved and innovative technology which furthers the state energy policy as set forth in section 16a-35k, (B) a subsidiary of any other public service company or a subsidiary of a holding company controlling, directly or indirectly, such a public service company, which generates electricity solely through ownership of fifty per cent or less of a private power production facility or (C) the state, a political subdivision of the state or any other person, firm or corporation other than a public service company or any corporation which was a public service company, prior to July 1, 1981, and which consents to be regulated as a public service company or a holding company for a public service company, which generates electricity solely through ownership of one hundred per cent or less of a private power production facility or (D) any combination thereof;
(Source: Connecticut Statute 227-a Public Utility Environmental Standards Act)
The Siting Council's maintains on its website a Siting Application Guide.
BUILDING, ZONING AND FIRE CODES:
Building Codes: Connecticut enforces mandatory statewide codes in the form of its 2005 State Building Code (SBC). Localities may not adopt their own codes. The code references the 2003 IBC along with the 2005 Connecticut Supplement. Updated codes are expected during the 3 rd quarter of 2008, estimated to come into effect in March 2009. [1]
Energy Codes: The SBC also mandates the 2003 IECC. This initiative is managed by the Office of the State Building Inspector. This will be updated to the 2006 IECC upon passing of the 2008 amendments to the SBC. [2]
Fire Codes: Connecticut enforces the 2003 IFC with some amendments. Updated codes are expected during the 3 rd quarter of 2008, estimated to come into effect in March 2009. [3]
Zoning: For the most part, Connecticut counties and municipalities have primary authority on zoning. Consult each community for zoning requirements in the locality.
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
The Connecticut Department of Public Utility Control (DPUC) was ordered by the state legislature to investigate interconnection standards within the state. The commission opened Docket No. 03-01-15 which was finalized in the Spring of 2004 and recently interconnection guidelines were in 2007. Interconnection guidelines apply to the state’s two investor owned utilities - Connecticut Light and Power (CL&P) and United Illuminating Company (UL). These utilities played a large role along with other stakeholders in the development of the final Guidelines for Generator Interconnection.Connecticut’s interconnection guidelines are modeled off of the for small generators. There are three levels of interconnection: (1) Certified, inverter-based systems no larger than 10 kilowatts (kW) in capacity; (2) Certified systems no larger than 2 megawatts (MW) in capacity; and (3) All other systems no larger than 20 MW in capacity. Note that the guidelines include "additional process steps" for generators greater than 5 MW.
Connecticut Light & Power Category 1 (up to 10 kw) Interconnection Agreement
Connecticut Light and Power’s Interconnection Information
United Illuminating Company 2008 Interconnection Guidelines
United Illuminating Company Category up to 20 MW (excluding inverter based projects 10 kW or less) Interconnection Agreement
The first step in DG interconnection planning is to contact one's transmission and distribution utility to discuss the process. Contact information is summarized in the table below.
Utility |
Contact Info |
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The table below details each utility's fee for pre-interconnection studies of DG.
Interconnection Fees |
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Category |
Nameplate Rating |
Application |
Each Study Fee |
Fast Track |
0-2 MW, unless Generating Facility does not qualify for the Fast Track process |
$500 |
Actual Cost Based |
Study |
(1) is larger than 2 MW but no larger than 20 MW, (2) is 2 MW or less and is not certified, or (3) is 2 MW or less and is certified but did not pass the Fast Track Process or the 10 kW Inverter Process.
|
$1000 |
Actual Cost Based |
A generator is also required to carry insurance at the rates in the table below.
Liability Insurance Requirements |
|
Nameplate Rating |
Minimum Liability Insurance Required |
100 kW or less Generating Facility |
$300,000 |
Greater than 100 kW to 1 MW |
$1,000,000 |
Greater than 1 MW to 5 MW |
$2,000,000 |
Greater than 5 MW |
$5,000,000 |
EXIT FEES:
There are exit fees outlined in (http://www.cga.ct.gov/olr/ba2000/2000HB-05753-R000149-BA.htm) and apply to "most entities that began generating electricity for their own use on or after July 1, 1998." Exit fees will be calculated as the net present value of the competitive transition assessment (CTA) and the systems benefit charge (SBC) that would have been paid if the customer had continued to get all of its electricity from the distribution system, minus the CTA and SBC collected for providing backup or standby service. The exit fee will run for either the life of the applicable CTA or the life of the self-generation facility. Exit fees do not apply to facilities that are - owned or operated by a distribution company (CL&P or UL) or a DUPC-licensed electric supplier; used to serve 1 to 4 residences; or installed in conjunction with expansion of an industrial plant that started operation before 7/1/1998.
984 Supplemental Power Service |
|
Load Size |
<= 350 kW |
Basic Charge |
$24.52/month |
Metering Service |
n/a |
Back-up/Standby/Emergency |
Demand Charge > 2 kW: $6.54/kW |
Supplementary/Auxillary |
Demand Charge > 2 kW: $6.54/kW |
Maintenance |
Demand Charge > 2 kW: $6.54/kW |
Net-Metering |
n/a |
Company Power Purchase |
n/a |
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|
Load Size |
Not more than 65 MW |
Basic Charge |
n/a |
Metering Service |
n/a |
Back-up/Standby/Emergency |
n/a |
Supplementary/Auxillary |
n/a |
Maintenance |
n/a |
Net-Metering |
Energy compensated at either a time differentiated or non-time differentiated ISO-NE Wholesale Electric Market Real Time Locational Market Price (RT-LMP). |
Company Power Purchase |
n/a |
|
|
Load Size |
n/a |
Basic Charge |
$3.00 |
Metering Service |
If the Company owns the metering equipment , the monthly customer charge will be capitalized cost of the metering equipment times 2.5% plus the basic charge listed above. |
Back-up/Standby/Emergency |
n/a |
Supplementary/Auxillary |
n/a |
Maintenance |
n/a |
Net-Metering |
n/a |
Company Power Purchase |
Energy compensated at either a time differentiated or non-time differentiated ISO-NE Wholesale Electric Market Real Time Locational Market Price (RT-LMP). |
United Illuminating Company
| Last Resort Service (this rate will be effective until January 1, 2010) | |
Load Size |
Not specified |
Basic Charge |
Basic Service Charge of Applicable Rate Schedule for Supplemental Service
|
Metering Service |
n/a |
Generation Charge |
Generation Charges On-Peak Off-Peak July 15.72¢/kWhr 15.72¢/kWhr August 15.83¢/kWhr 15.83¢/kWhr September 14.05¢/kWhr 14.05¢/kWhr
|
Delivery Charge and other charges |
Delivery Charges Systems Benefits Charge (SBC) 0.1973¢/kWhr **Conservation Charge 0.3000¢/kWhr **Renewable Energy Charge 0.1000¢/kWhr Non-Bypassable FMCC* 2.1612¢/kWhr *Federally Mandated Congestion Costs
**Competitive Transition Assessment (CTA) Energy Charge per kWhr 1.5222¢/kWhr Transmission Charge 12.6900¢/kWhr
|
Maintenance |
$ 101.18 |
Net-Metering |
n/a |
Company Power Purchase |
n/a |
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