Contact Information:

California Air Resources Board
1001 I Street
P.O. Box 2815
Sacramento, CA 95812

(916) 322-2990

Or view the Department's


Relevant State Sites:

California Public Utilities Commission

California Energy Commission

California BACT Clearinghouse Database

CARB Distributed Generation Program

CEC DG Costs and Benefits Issue Paper (08/04)

Pacific Region CHP Application Center


Major Utilities:

Pacific Gas & Electric

Southern California Gas Company (SoCalGas)

Southwest Gas Company (SWGas)

Southern California Edison Company

Sierra Pacific Power Company

Pacificorp (Pacific Power & Light)

San Diego Gas Electric Company


Specific Issues:













CARB Revises the DG Certification Regulation (9/2007)

The California Air Resources Board amended their Distributed Generation Certification Regulation. The amendments became effective on September 7, 2007. The final regulation can be found here. The new requirements are discussed in the DG certification section below.


Air Quality Status

Numerous areas are in nonattainment, click below for details.
EPA's Nonattainment Areas in the state of California

Major Source Threshold

Air quality district dependent, see below for details

Minor Source Permitting Exemption

Air quality district dependent, see below for details

Minor Source Treatment

Air quality district dependent, see below for details

Emergency Generating Limits

There is an Airborne Toxic Control Measure for Stationary Compression Engines that designates specific limits for emergency generators



In California, the 35 local air quality districts permit projects below 50 MW. Very small projects are exempted from permitting by the individual districts. The size threshold for permitting exemption varies from district to district (see link below for specific levels). The threshold is as low as 37 kW in some districts but includes all gas-fired reciprocating engines in some districts. In 2000, the state of California passed Senate Bill (SB) 1298 requiring the California Air Resource Board (CARB) to set new standards and provide guidance for permitting new DG projects.

SB 1298 called for the CARB to establish an emission certification program by 2003 for the small projects that are exempt from permitting. The certification standards reflect the best performance achieved in practice by existing technologies that are currently exempted from district permit requirements. By the earliest practicable date, the standards shall be made equivalent to the level that the ARB determines to be the best available control technology (BACT) for permitted central station power plants in California in lb/MWh. The final regulation was passed in 2002, which was more recently amended in 2006 and 2007?. A BACT guidance document was also published in 2002 (the accompanying appendices are available at

The certification program has been implemented in phases. The first set of standards was effective January 1, 2003 to December 31, 2006 and applies to DG units integrated with or without combined heat and power technologies. A second phase took effect January 1, 2007 and applies to any DG unit fueled by a fossil fuel. Separate emissions standards for any DG units fueled by digester gas, landfill gas, or oil-field waste gas took effect in 2008, and then become more stringent in 2013 The most recent DG certification standards (effective September 7, 2007) are described below. Table 1 summarizes the emission certification standards for 2003. The first column applies to electricity-only technologies. Based on these emission standards for 2003, fuel cells, some microturbines, and well-controlled natural gas reciprocating engines (rich burn with three-way catalyst or lean burn with SCR) are expected to be certifiable. The second column applies if a DG unit is integrated with combined heat and power (CHP). A DG unit qualifies for this certification only if the DG unit is sold with CHP technology integrated into a standardized package by a manufacturer and if it can achieve a minimum efficiency of 60 percent. If one of the two conditions is not met, the unit does not qualify for this certification.

Table 1
2003 DG Certification Standards


DG unit not Integrated with CHP(lbs/MWh)

DG unit Integrated with CHP(lbs/MWh)

Oxides of Nitrogen



Carbon Monoxide



Volatile Organic Compound



There are also PM limits, which apply –

  • For DG units without CHP, an emission limit corresponding to natural gas with sulfur content of no more than 1 grain/100 scf.
  • For DG units with CHP, an emissions limit corresponding to natural gas with fuel sulfur content of no more than 1 grain/100 scf.

In addition, DG units that are sold with a zero emission technology integrated into a standardized package may have the electric power output of the zero emission technology added to the electrical power output of the DG unit to meet the emission standards. Starting January 1, 2007 all DG units subject to the regulation fueled by a fossil fuel must be certified under the emission standards shown in Table 2:

Table 2
2007 Fossil Fuel Emission Standards









DG units in Phase II that use CHP can take a credit of 1 MWh for each 3.4 MMBtu of heat recovered in the CHP system if the CHP system is an integrated package with the DG system and if the overall system has an efficiency of at least 60 percent. Based on current technology, only fuel cells will be able to achieve the 2007 DG certification.

Additionally, any DG unit subject to this regulation and fueled by digester gas, landfill gas, or oil-field waste gas must meet the emission standards in Table 3 below:

Table 3
Waste Gas Emission Standards


Emission Standard (lbs/MWh)


On or after January 1, 2008

On or after January 1, 2013










The regulation also specifies appropriate testing, testing parameters, labeling and record keeping requirements along with information about the equipment to be submitted by the manufacturer for certification. The Executive officer or an authorized representative will periodically inspect manufacturer, distributors, and retailers selling or leasing DG in California to ensure compliance with the regulations. Failure of the inspection may lead to denial, suspension, or revocation of certification. The equipment must be guaranteed to meet the certification for 15,000 hours of operation.

The systems certified to date are listed below:

Company Name


Standards Certified to

Executive Order Number

Expiration Date

United Technologies Corporation Fuel Cells

200 kw phosphoric acid fuel cell




Capstone Turbine Corporation

60 kw, C60 MicroTurbine




FuelCell Energy, Inc.

250 kw, DFC300A fuel cell




Ingersoll-Rand Energy Systems

70 kw, 70LM Microturbine, version C




Ingersoll-Rand Energy Systems

70 kw, 70LM Microturbine, version WD

2003 with CHP



Plug Power Inc.

5 kw, GenSys 5C Fuel Cell




FuelCell Energy, Inc

1 MW, DFC1500 Fuel Cell




Turbec AB

100 kW, T100 Microturbine CHP System




Ingersoll-Rand Energy Systems

250 kW, 250SM Microturbine




FuelCell Energy, Inc.

250 kW, DFC300MA Fuel Cell





Projects that are not exempted, but are below 50 MW are permitted by the air district where the project is located. See the CARB New Source Review Permitting Programs webpage for more information.

In addition, sources with a potential to emit above 10 tons per year of any criteria pollutants in severe nonattainment areas and 25 tons per year in moderate nonattainment areas will have to offset emissions.

The permitting process takes up to 30 days for the APCO to determine if an application is complete and then up to an additional 180 days for a final decision.

A summary of requirements for each air district is available by clicking on the appropriate district below:


Amador County Air Pollution Control District
Antelope Valley Air Quality Management District
Bay Area Air Quality Management District
Butte County Air Quality Management District
Calaveras County Air Pollution Control District
Colusa County Air Pollution Control District
El Dorado County Air Pollution Control District
Feather River Air Quality Management District
Glenn County Air Pollution Control District
Great Basin Unified Air Pollution Control District
Imperial County Air Pollution Control District
Kern County Air Pollution Control District
Lake County Air Quality Management District
Lassen County Air Pollution Control District
Mariposa County Air Pollution Control District
Mendocino County Air Quality Management District
Modoc County Air Pollution Control District
Mojave Desert Air Quality Management District

Monterey Bay Unified Air Pollution Control District
North Coast Unified Air Quality Management District
Northern Sierra Air Quality Management District
Northern Sonoma County Air Pollution Control District
Placer County Air Pollution Control District
Sacramento Metropolitan Air Quality Management District
San Diego County Air Pollution Control District
San Joaquin Valley Unified Air Pollution Control District
San Luis Obispo County Air Pollution Control District
Santa Barbara County Air Pollution Control District
Shasta County Air Quality Management District
Siskiyou County Air Pollution Control District
South Coast Air Quality Management District
Tehama County Air Pollution Control District
Tuolumne County Air Pollution Control District
Ventura County Air Pollution Control District
Yolo-Solano Air Quality Management District


A potential to emit 250 tons per year of a criteria pollutant triggers PSD. In the nonattainment areas a potential to emit 100 tons per year of CO or PM triggers NSR. However, the state of California has a variety of standards depending on the location of the source. In general these standards are much more stringent than the federal standards. More detail is available by clicking on the individual air districts above.


There are Emergency Engine Requirements that were finalized in September 2005. These regulations are entitled, The Airborne Toxic Control Measure for Stationary Compression Engines and are listed as follows.

Airborne Toxic Control Measure


Bhp Rating and Emission Limits

Maintenance and Testing Limits

New Emergency Standby Diesel-Fueled CI Engines (> 50 bhp)

Diesel PM Limit: 0.15 g/bhp-hr (meet the diesel PM standard, title 13 CCR, section 2423);


New Direct-Drive Emergency Standby Fire Pump Engine

Must follow the tier emission standards


In-Use Emergency Standby Diesel-Fueled CI Engine

Diesel PM limit: 0.40 g/bhp-hr for 20 hrs/yr or less

30 hrs/yr with some exemptions based on PM emissions and bhp rating

New Stationary Diesel-Fueled CI Engines, less than or Equal to 50 bhp

Must meet a standard of 0.01g/bhp-hr or the off-road compression ignition engine standards (title 13, CCR, section 2423



The California Energy Commission has the statutory authority to site and license thermal power plants that are rated at 50 MW and larger. The California Energy Security and Reliability Act of 2000 serves to expedite power plant proposals that present no significant impact on the environment or electrical system. This Act also establishes a four-month siting process to provide a three-year operating permit for simple cycle plants that provide no significant adverse environmental impact, and are equipped with the best available air emission control technology. These plants are required to convert to a cleaner and more efficient combined cycle within three years of licensing. Under the law, the commission must complete its review of an application within 45 days; if complete, the application is accepted as of that date and the proceedings for reaching a final decision within six month begin. If incomplete, the application is accepted for the final decision within 12 months.

More information can be found out the California Energy Commission Energy Facilities Siting Webpage


Distributed Generation Permitting: Highlights of the permitting process can be found HERE.

Building Codes: California enforces the 2007 California Building Standards Code, known as “Title 24.” Section 2 of Title 24 describes the California Building Code, which references the 2006 IBC with state amendments. Codes are updated annually.

Energy Codes: California enforces the California Energy Codes (CEC), as Section 6 of Title 24. These mandatory codes apply to all mechanically heated/cooled buildings. The 2005 Building Energy Efficiency Standards presents the CEC. Local jurisdictions may amend them to be more stringent. These standards exceed ASHRAE/IESNA 90.1-2004. Currently in 2008 these codes are under review for possible updating.

Fire Codes: California enforces the 2007 California Fire Code, which references the 2006 IFC with state amendments, and is Section 9 of Title 24.

Zoning: California has enacted bare minimum zoning standards (CA Gov’t Code 65800) that affect all counties and non-charter cities. However, all charter cities and almost all counties and other cities have created their own, specific zoning codes.[1] 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


Summary Requirements


Eligible Technologies

Solar Thermal Electric, Photovoltaics, Landfill Gas, Wind, Biomass, Hydroelectric, Geothermal Electric, Fuel Cells, Municipal Solid Waste, CHP/Cogeneration, Microturbines, Other Distributed Generation Technologies

Size Limitations

Up to 10 MW for DG units, up to 10 kW for simplified rules, overall enrollment is limited to 0.5% of utility peak

External Disconnect Requirements

Yes for units greater than 1 kW

Insurance Requirements


Additional Information

California 's interconnection standard is known as Rule 21. Rule 21 applies to all DG, combined heat and power, and renewable systems under 10 MW. This rule is a tariff on utilities and therefore each utility in the state has their own tariff filed with the California Public Utilities Commission (CPUC), although each tariff is essentially the same.

For larger DG units up to 10 MW the utility must perform an Initial Review Process (IRP). If the system meets all of the requirements of the IRP then it qualifies for Simplified Interconnection. Otherwise, the unit must undergo a Supplemental Review Process (SRP). After the SRP some systems may go through Simplified Interconnection with a few extra requirements or may be required to go through a formal Interconnection Study. Photovoltaics and wind units that are under 10 kW qualify for a simplified interconnection procedure that bypasses the review and interconnection study phase of the process.


More information can be found in the California Energy Commission California Interconnection Guidebook.



The first step in establishing interconnection is to contact the CPUC or your electricity generation and transmission utility.

California Public Utilities Commission



Nicolas Chaset
State Building
505 Van Ness Avenue
San Francisco, CA 94102
Phone: (415) 703-1184
Phone 2: (800) 649-7570


Pacific Gas and Electric



1 Market Street
San Francisco , CA 94105
Residential: 1-800-PGE-5000 or 1-800-743-5000
Business: 1-800-468-4743


San Diego Gas and Electric


P.O. Box 129831
San Diego , Ca 92112-9831 Phone: 1-800-411-SDGE (7343)


Southern California Edison


P.O. Box 800
Rosemead, CA 91770
Residential: 1-800-655-4555
Business: 1-800-990-7788



There are exit fees for certain applications of DG in the state of California. (See below)

There are three different kinds of exit fees in California, which apply to customers of Pacific Gas and Electric (PG&E), Southern California Edison (SCE), and San Diego Gas and Electric (SDG&E) that self-generate to meet all or part of their load (see D.03-04-030 for more information). All of these charges are considered to be part of the Customer Generation Cost Responsibility Surcharge (CRS). All charges under the CRS are capped at 2.7 cents per kWh (as of July 2004). The component charges are as follows:

1) "Tail" Competition Transition Charges pursuant to Public Utilities Code Section 367(a).

2) Costs associated with the Historic Procurement Charge "HPC" (applicable to the SCE service territory only) pursuant to Decision (D.) 02-07-032, as modified by D.03-02-035; and the Regulatory Asset Charge per D.04-02-062 in PG&E’s territory.

3) Costs associated with procurement of power by the California Department of Water Resources (DWR), see docket D.03-07-030 with separate charges for:

a) Historic shortfalls financed through a Bond Charge; and

b) Forward costs associated with the ongoing power charges

California suffered significant problems with its attempt to implement deregulation of the state's electric utility industry. The resulting power crisis resulted in lawmakers passing numerous energy bills in addition to rulings issued by the PUC. As with many states' electric restructuring laws, California created a CTC for utilities to recover their stranded costs as part of the initial legislation. These costs relate to what are commonly called "tail" competition charges pursuant to legislation enacted in AB 1890. The thought at the time was that these fees would allow for complete cost recovery by March 2002. However, the electricity crisis created a significant disparity for these projections and thus a delay in their cessation. The three major utilities still charge CTCs for departing load. Departing load is defined as that portion of an IOU’s customer’s electric load for which the customer, on or after December 20, 1995 discontinues or reduces its purchase of electricity supply and delivery services from that utility. Zero-emitting renewables, load that is eligible for net metering under PUC code sections 2827-2827.10, and most CHP that meets PUC Code exemptions in Section 372 and 374 do not have to pay the tail CTC. 2008 CTC charges for SCE, SDG&E, and PG&E can be found in the following rate schedules:

The Historical Procurement Charge is customer specific and only applies to customers in SCE's service territory, but will be zero for customers departing after July 1, 2003. The calculation of the charge compares the generation revenue received since May 2000 with costs incurred to serve the customer's documented consumption. The customer's cost responsibility will be determined by multiplying the customer's cumulative under-collection as of August 31, 2002, by the ratio of the starting balance of the costs in SCE's PROACT. The HPC to be assessed upon a customer's departure will equal the difference between the customer-specific HPC obligation at the start of the recovery period and the customer's total contributions to PROACT. The charge is only applicable to DG applications greater than 1 MW that do not meet CARB 2007 emission standards.

The last exit fee is to recover payment for energy that was bought by the California Department of Water and Resources (DWR) when the three major utilities could not afford to purchase power for their customers at the height of the crisis. The California Public Utilities Commission has exempted many types of small, renewable, and clean self-generation from these extra power surcharges. Customers of Pacific Gas and Electric Company, Southern California Edison, and San Diego Gas and Electric Company who installed their own power generation before January 17, 2001-when the California Department of Water Resources began contracting for electricity-are exempt from most surcharges, as are customer generation systems that meet certain environmental criteria. The CPUC created the exceptions to the surcharges to promote economic incentives for alternative generation and to comply with legislative and commission policy.

The CPUC provides the following exceptions from all CRS charges:

1) Systems smaller than 1 MW that are net-metered and/or eligible for CPUC or California Energy Commission (CEC) incentives for being clean and super-clean are fully exempt from any surcharge. This includes many solar and wind systems as well as fuel cells.

2) Ultra-clean and low-emission systems (such as solar) that are 1 MW or greater that meet Senate Bill 1038 requirements to comply with CARB 2007 air emission standards will pay 100% of the bond charge but no future DWR charges or utility under-collection surcharges.

3) All other self-generation customers will pay all components of the surcharge except the DWR ongoing power charges.

When the combined total installed generation reaches 3,000 MW or when generation in the third category reaches periodic lower caps set by the CPUC, any additional customer generation installed will pay all surcharges. The cap is based on the 10-year forecast of departing load that DWR relied on when negotiating its contracts, and, therefore, any self-generation installed under that cap does not result in shifting costs to other customers. The caps on non-renewable self-generation are to ensure that priority is given to renewable and ultra-clean generation sources. The surcharge includes costs related to financing bonds that were sold to cover revenue shortfalls in 2001, ongoing power costs, and transition costs (recovery of generation-related costs to enable utilities to transition to a competitive market). State law, through Assembly Bill 117, requires the DWR be fully reimbursed for its purchases, but it leaves the determination of each customer's fair share of those costs to the CPUC's discretion. Most customers who install self-generation still remain utility customers and therefore still contribute to DWR and transition costs.

The following table provides an overview of “exit fee” related exemptions for customer generation.

Customer Generation (CG) Type

Exception (the following charges do not apply)

Departed prior to Feb 1, 2001

DWR Bond and Power Charges

Met certain California Environmental Quality Act (CEQA) and departure deadlines

DWR Power Charge

Biogas digesters

All CRS Charges

Systems sized up to 1 MW that are eligible for either net metering or a CEC/CPUC program

All CRS Charges

Systems sized over 1 MW but ultra-clean

DWR Power Charge and HPC

CG other than that defined in Op 4-7

DWR Power Charge

Further Resources - CA Exit Fees

More information on the state’s exit fee policies can be found here,

Please also see CPUC Resolution E-3831 issued on July 8, 2004. This Resolution authorizes IOU’s to collect CRS charges.

CG that departed Prior to Feb 1, 2001 (OP 4); CG that met certain CEQA and specified departure dates (OP 5 as corrected in D.03-04-041); Biogas digester CG (OP 6); and CG systems sized up to 1 MW and eligible for either net metering or a CEC/CPUC program (OP 7).



There is a statewide policy concerning standby rates in California. According to Decision 01-07-027 standby rates must 1) provide for fair cost allocation among customers; 2) allow the utility adequate cost recovery while minimizing costs to customers; 3) facilitate customer-side distributed generation deployment; and 4) send proper price signals to prospective purchasers of distributed generation.

Southern California Edison - Schedule S: Standby service is provided to customers that contract with the utility for a specific amount of standby capacity. A moderate demand based reservation charge is assessed every month. Actual usage is billed through a high demand charge and a moderate energy charge. Billing demand is based on the maximum 15 minute demand of the month. Rates are available at:

Pacific Gas & Electric - Schedule S: Standby service is provided to customers that contract with the utility for a specific amount of standby capacity. A moderate demand based reservation charge and a customer charge is assessed every month. Actual usage is billed through a high energy charge. Rate available at:

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