EEA Database on Distributed Generation

WHAT'S NEW:

No recent state activity has been identified.

Engines that are smaller than 1,500 hp or 1,118 kW and gas turbines with a heat input of less than 10 MMBtu/hr are exempted from minor source permitting. No state notification is required for these units; documentation in the site’s internal records is recommended.

Combustion units are exempted if they are below the following size limits:

Units that fire natural gas, propane or LPG with a rated heat input capacity of less than 2.5 MMBtu/hr

Units that fire only oil or oil in combination with only natural gas, propane, or LPG with a rated input capacity of less than 1.0 MMBtu/hr

MINOR SOURCE PERMITTING

Minor permits typically have a limit on either hours of operation or fuel use. The opacity limit is 30%. If the unit burns liquid fuel, there is a limit of 0.1 lb/MMBtu. If the unit is burning oil or liquid fuel there is a restriction of 0.3 lb/MMBtu for SO2.

There is a 30 day public comment period for minor sources if the state determines there is a public interest. A hearing could take up to 75 days if requested. The state has a maximum of 90 days to issue the permit if no public notice is required and 180 days with public notice.

MAJOR NSR/PSD PERMITTING

A potential to emit 250 tons (100 for listed sources) per year of a criteria pollutant triggers PSD in attainment areas. The areas that are in “moderate” nonattainment for ozone trigger NSR for 100 tons per year of NOx or VOCs. The state also has a VOC trading program that applies to Title V sources in the Chicago area

TREATMENT OF EMERGENCY ENGINES

A unit up to 1,500 hp is exempted from permitting and may operate only during emergencies and for maintenance. This exemption is different from the de minimis exemption listed above because these units may use 500 hrs/year to calculate their potential to emit (for PSD purposes). Sources must document their hours of operation. There is no limit on maintenance hours, but if a unit operates more than 500 hours in a single year it can no longer qualify as an emergency unit.

SITING REQUIREMENTS FOR NON-UTILITY GENERATORS:

The Illinois Public Act 90-561, effective December 1997, deregulated electric generation and removed the Illinois Commerce Commission's plant siting authority. The only remaining plant siting authorities in Illinois are the zoning boards of local communities. Proposed generation facilities must also comply with Illinois Environmental Protection Agency rules.

(220 ILCS 5/16-102) Sec. 16-102.

Definitions. For the purposes of this Article the following terms shall be defined as set forth in this Section:

"Alternative retail electric supplier" means every person, cooperative, corporation, municipal corporation, company, association, joint stock company or association, firm, partnership, individual, or other entity, their lessees, trustees, or receivers appointed by any court whatsoever, that offers electric power or energy for sale, lease or in exchange for other value received to one or more retail customers, or that engages in the delivery or furnishing of electric power or energy to such retail customers, and shall include, without limitation, resellers, aggregators and power marketers, but shall not include

(i) electric utilities (or any agent of the electric utility to the extent the electric utility provides tariffed services to retail customers through that agent),

(ii) any electric cooperative or municipal system as defined in Section 17-100 to the extent that the electric cooperative or municipal system is serving retail customers within any area in which it is or would be entitled to provide service under the law in effect immediately prior to the effective date of this amendatory Act of 1997,

(iii) a public utility that is owned and operated by any public institution of higher education of this State, or a public utility that is owned by such public institution of higher education and operated by any of its lessees or operating agents, within any area in which it is or would be entitled to provide service under the law in effect immediately prior to the effective date of this amendatory Act of 1997,

(iv) a retail customer to the extent that the customer obtains its electric power and energy from that customer's own cogeneration or self-generation facilities,

(v) an entity that owns, operates, sells, or arranges for the installation of a customer's own cogeneration or self-generation facilities, but only to the extent that the entity is engaged in owning, selling or arranging for the installation of such facility, or operating the facility on behalf of such customer, provided however that any such third-party owner or operator of a facility built after January 1, 1999, complies with the labor provisions of Section 16-128(a) as though such third party were an alternative retail electric supplier, or

(vi) an industrial or manufacturing customer that owns its own distribution facilities, to the extent that the customer provides service from that distribution system to a third-party contractor located on the customer's premises that is integrally and predominantly engaged in the customer's industrial or manufacturing process; provided, that if the industrial or manufacturing customer has elected delivery services, the customer shall pay transition charges applicable to the electric power and energy consumed by the third-party contractor unless such charges are otherwise paid by the third party contractor, which shall be calculated based on the usage of, and the base rates or the contract rates applicable to, the third-party contractor in accordance with Section 16-102.

(220 ILCs 5/16-108) Sec. 16-108

(f) An electric utility shall be entitled but not required to implement transition charges in conjunction with the offering of delivery services pursuant to Section 16-104. If an electric utility implements transition charges, it shall implement such charges for all delivery services customers and for all customers described in subsection

(h), but shall not implement transition charges for power and energy that a retail customer takes from cogeneration or self-generation facilities located on that retail customer's premises, if such facilities meet the following criteria:

(i) the cogeneration or self-generation facilities serve a single retail customer and are located on that retail customer's premises (for purposes of this subparagraph and subparagraph (ii), an industrial or manufacturing retail customer and a third party contractor that is served by such industrial or manufacturing customer through such retail customer's own electrical distribution facilities under the circumstances described in subsection vi) of the definition of "alternative retail electric supplier" set forth in Section 16-102, shall be considered a single retail customer);

(ii) the cogeneration or self-generation facilities either (A) are sized pursuant to generally accepted engineering standards for the retail customer's electrical load at that premises (taking into account standby or other reliability considerations related to that retail customer's operations at that site) or (B) if the facility is a cogeneration facility located on the retail customer's premises, the retail customer is the thermal host for that facility and the facility has been designed to meet that retail customer's thermal energy requirements resulting in electrical output beyond that retail customer's electrical demand at that premises, and comply with the operating and efficiency standards applicable to "qualifying facilities" specified in title 18 Code of Federal Regulations Section 292.205 as in effect on the effective date of this amendatory Act of 1999;

(iii) the retail customer on whose premises the facilities are located either has an exclusive right to receive, and corresponding obligation to pay for, all of the electrical capacity of the facility, or in the case of a cogeneration facility that has been designed to meet the retail customer's thermal energy requirements at that premises, an identified amount of the electrical capacity of the facility, over a minimum 5-year period; and;

(iv) if the cogeneration facility is sized for the retail customer's thermal load at that premises but exceeds the electrical load, any sales of excess power or energy are made only at wholesale, are subject to the jurisdiction of the Federal Energy Regulatory Commission, and are not for the purpose of circumventing the provisions of this subsection (f).

If a generation facility located at a retail customer's premises does not meet the above criteria, an electric utility implementing transition charges shall implement a transition charge until December 31, 2006 for any power and energy taken by such retail customer from such facility as if such power and energy had been delivered by the electric utility. Provided, however, that an industrial retail customer that is taking power from a generation facility that does not meet the above criteria but that is located on such customer's premises will not be subject to a transition charge for the power and energy taken by such retail customer from such generation facility if the facility does not serve any other retail customer and either was installed on behalf of the customer and for its own use prior to January 1, 1997, or is both predominantly fueled by byproducts of such customer's manufacturing process at such premises and sells or offers an average of 300 megawatts or more of electricity produced from such generation facility into the wholesale market. Such charges shall be calculated as provided in Section 16-102, and shall be collected on each kilowatt-hour delivered under a delivery services tariff to a retail customer from the date the customer first takes delivery services until December 31, 2006 except as provided in subsection (h) of this Section. Provided, however, that an electric utility, other than an electric utility providing service to at least 1,000,000 customers in this State on January 1, 1999, shall be entitled to petition for entry of an order by the Commission authorizing the electric utility to implement transition charges for an additional period ending no later than December 31, 2008. The electric utility shall file its petition with supporting evidence no earlier than 16 months, and no later than 12 months, prior to December 31, 2006. The Commission shall hold a hearing on the electric utility's petition and shall enter its order no later than 8 months after the petition is filed. The Commission shall determine whether and to what extent the electric utility shall be authorized to implement transition charges for an additional period. The Commission may authorize the electric utility to implement transition charges for some or all of the additional period, and shall determine the mitigation factors to be used in implementing such transition charges; provided, that the Commission shall not authorize mitigation factors less than 110% of those in effect during the 12 months ended December 31, 2006. In making its determination, the Commission shall consider the following factors: the necessity to implement transition charges for an additional period in order to maintain the financial integrity of the electric utility; the prudence of the electric utility's actions in reducing its costs since the effective date of this amendatory Act of 1997; the ability of the electric utility to provide safe, adequate and reliable service to retail customers in its service area; and the impact on competition of allowing the electric utility to implement transition charges for the additional period.

(h) An electric utility shall also be entitled to file tariffs that allow it to collect transition charges from retail customers in the electric utility's service area that do not take delivery services but that take electric power or energy from an alternative retail electric supplier or from an electric utility other than the electric utility in whose service area the customer is located. Such charges shall be calculated, in accordance with the definition of transition charges in Section 16-102, for the period of time that the customer would be obligated to pay transition charges if it were taking delivery services, except that no deduction for delivery services revenues shall be made in such calculation, and usage data from the customer's class shall be used where historical usage data is not available for the individual customer. The customer shall be obligated to pay such charges on a lump sum basis on or before the date on which the customer commences to take service from the alternative retail electric supplier or other electric utility, provided, that the electric utility in whose service area the customer is located shall offer the customer the option of signing a contract pursuant to which the customer pays such charges ratably over the period in which the charges would otherwise have applied.

BUILDING, ZONING AND FIRE CODES:

Building Codes: Illinois does not appear to have a statewide model building code. Jurisdictions develop their own codes. Legislation in development recommends the enforcement of the 2006 IBC as a minimum for communities without their own building codes beginning in Jan., 2010.

Capital Development Board

Energy Codes: Illinois requires statewide enforcement of the 2006 IECC for commercial buildings, without amendments. [1][2]

Illinois Energy Page

Fire Codes: Each jurisdiction enacts its own fire code. Check with each jurisdiction regarding their fire codes.

Illinois State Fire Marshall

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:

In August 2007, Illinois enacted legislation (S.B. 680) requiring the Illinois Commerce Commission (ICC) to establish standards for net metering and interconnection for renewable energy systems by April 1, 2008. The final interconnection standards, 83 Ill. Adm. Code, Part 466, were adopted by the ICC in August 2008.

For a project to meet interconnection requirements it must meet the requirements for one of four classification tiers. The requirements for each level are usually based on system capacity, whether the systems components are certified by a nationally recognized testing laboratory (NRTL), and whether the system is connected to an area network or a radial distribution circuit. The four tiers are summarized as follows: Tier 1: Certified, inverter-based systems with a capacity rating of 10 kilowatts (kW) or less. Tier 2: Certified systems with a capacity rating of 2 MW or less, connected to a radial distribution network or a spot network serving one customer. Tier 3: Certified systems with a capacity rating of 50 kW or less connected to an area network and from which power will not be exported; or certified, non-power-exporting systems with a capacity rating of 10 MW or less connected to a radial distribution network. Tier 4: Systems with a capacity of 10 MW or less that do not meet the criteria for inclusion in a lower tier, including all systems using non-certified components and those that require additional construction by the utility in order to accommodate the facility.

Generators with a capacity larger than 1 MW must carry liability insurance with coverage of at least $2 million per occurrence and $4 million in aggregate. Standardized interconnection agreements are available for all four tiers. The Tier 1 agreement is a simplified version of that used for projects requiring higher levels of review. This information is a basic summary, and interested parties should consult the rule or the Illinois Commerce Commission for more detailed information.

Illinois Commerce Commission
Office of Public Affairs
527 East Capitol
P.O. Box 19280
Springfield, IL 62794-9280
Phone: (217) 782-5793
Fax: (217) 524-0674

EXIT FEES:

Exit fees are no longer allowed to be assessed in Illinois. They were allowed for some DG installations up to Dec. 31, 2006 but are no longer applicable under legislation 220 ILCS 5/.

UTILITY STANDBY RATES:

Illinois does not have a statewide policy on standby rates. Information about the two largest utility rate policies is included below.

Commonwealth Edison Co (Exelon) - Rate 18 - Standby service is provided at a high demand rate with a steep declining block on demand charges. Billing demand is based on the average of the three maximum 30 minute demand periods of the month. More detailed rate information is available at: http://www.exeloncorp.com/ourcompanies/comed/comedbiz/energy_rates/our_rates_and_prices.htm

Illinois Power Co (Ameren) - Standby service is entirely provided by real-time energy prices that are available to customers each day. More rate information is available at: https://www2.ameren.com/business/rates/ratesPost2006AMCIPS.aspx

Illinois

WHAT'S NEW:

AIR EMISSIONS REGULATIONS:

BUILDING, ZONING AND FIRE CODES:

EXIT FEES: