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Contact Information:
California Air Resources Board
1001 I Street
P.O. Box 2815
Sacramento, CA 95812
(916) 322-2990
Or view the Department's
Website
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CALIFORNIA
LATEST NEWS:
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.
A summary of amendments is located here.
CARB Adds to Certified DG Technology (09/14/04)
The California Air Resources Board (CARB) has issued an Executive
Order (EO) for Distributed Generation Certification to
FuelCell Energy Inc. for its 1 MW fuel cell, model number
DFC1500.
ARB 2005 DG Technology Review (09/14/04)
CARB's Distributed Generation
Certification regulation requires ARB staff to conduct an electrical
generation technology review and report its findings to the
Board by July 2005. The ARB staff held the last DG workgroup
meeting on January 13, 2005. The
workgroup meeting notice
has been added to the DG webpage and includes information
on how to participate via teleconference. More information can be found on the
Latest News page.
SCAQMD DG BACT Guideline Changes (04/23/04)
It is proposed that a new equipment category entitled "Distributed Generation" be created to
encompass all DG projects greater than or equal to 1.5 MW, regardless of the DG technology that is chosen
by the applicant. The guideline will require that the project meet the CARB 2007 standards for NOx, CO and
VOC. AQMD's Clean Fuels Policy will be referenced as the guideline for SOx and PM. Ammonia emission
guidelines for gas turbines and I.C. engines will be referenced as the guideline for inorganic emissions.
This would constrain ammonia emissions in case an applicant chooses to meet the CARB 2007 NOx limit by
using SCR technology. These changes would take effect on acceptance by the board and are applicable to all sources
except for those utilizing digester or landfill gas. The next Board Meeting will take place on August 6, 2004. More information can be found on the
Latest News page.
DE MINIMIS EXEMPTIONS:
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. A BACT guidance document was also published in 2002 (the accompanying
appendices are available at http://www.arb.ca.gov/energy/dg/dg.htm).
The certification program is to be implemented in two phases. The first set of standards
is effective January 1, 2003 to December 31, 2006. A second phase will take effect January 1, 2007. CARB has been holding workgroup meetings
to amend the DG Certification Regulation. The staff's most recent proposed amendments to the DG Certification Regulations were approved by the Air Resources Board (ARB) at a public
hearing on October 19, 2006 and are described below. The October amendments have not yet received final approval.
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
| Pollutant |
DG unit not Integrated with CHP(lbs/MWh) |
DG unit Integrated with CHP(lbs/MWh) |
| Oxides of Nitrogen |
0.5 |
0.7 |
| Carbon Monoxide |
6.0 |
6.0 |
| Volatile Organic Compound |
1.0 |
1.0 |
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
| Pollutant |
lbs/MWh |
| NOx |
0.07 |
| CO |
0.1 |
| VOCs |
0.02 |
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
| Pollutant |
Emission Standard (lbs/MWh) |
|
On or after January 1, 2008 |
On or after January 1, 2013 |
| NOx |
0.5 |
0.07 |
| CO |
6.0 |
0.1 |
| VOCs |
1.0 |
0.02 |
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.
| Company Name
|
Technology
|
Standards Certified to
|
Executive Order Number
|
Expiration Date
|
| United Technologies Corporation Fuel Cells |
200 kw phosphoric acid fuel cell |
2007 |
DG-001
|
01/29/2007
|
| Capstone Turbine Corporation |
60 kw, C60 MicroTurbine |
2003 |
DG-002
|
12/31/2006
|
| FuelCell Energy, Inc. |
250 kw, DFC300A fuel cell |
2007 |
DG-003
|
05/07/2007
|
| Ingersoll-Rand Energy Systems |
70 kw, 70LM Microturbine, version C |
2003
|
DG-004-A
|
12/31/2006
|
| Ingersoll-Rand Energy Systems |
70 kw, 70LM Microturbine, version WD |
2003 with CHP
|
DG-005
|
12/31/2006
|
| Plug Power Inc. |
5 kw, GenSys 5C Fuel Cell |
2007
|
DG-006
|
07/16/2008
|
| FuelCell Energy, Inc |
1 MW, DFC1500 Fuel Cell |
2007 |
DG-007 |
09/13/2008 |
| Turbec AB |
100 kW, T100 Microturbine CHP System |
2003 |
DG-008 |
12/31/2006 |
| Ingersoll-Rand Energy Systems |
250 kW, 250SM Microturbine |
2007 |
DG-009 |
10/21/2009 |
| FuelCell Energy, Inc. |
250 kW, DFC300MA Fuel Cell |
2007 |
DG-010 |
12/16/2006 |
MINOR SOURCE PERMITTING:
Projects that are not exempted but are below 50 MW are permitted by the air district where the project is located.
In addition, sources with a potential to emit above the levels listed below will have to offset emissions:
| Pollutant |
Tons per Year (TPY) |
| VOC: |
10 |
| NOx: |
10 |
| PM-10: |
15 |
| SOx: |
27 |
| CO: |
100 |
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:
MAJOR NSR/PSD PERMITTING:
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.
TREATMENT OF EMERGENCY ENGINES:
The current regulations allow emergency generation for up to 200 hours per year.
However, there are proposed Emergency Engine Requirements that will most likely be finalized by August 2005. These regulations are entitled, The Airborne Toxic Control Measure for Stationary Compression Engines and are listed as follows.
Airborne Toxic Control Measure
| Engine |
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 (current); 0.10 g/bhp-hr (2008-on) |
|
| 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 the off-road compression ignition engine standards (title 13, CCR, section 2423 |
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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 new 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
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:
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
3) Costs associated with procurement of power by the California Department of Water Resources (DWR), 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 non-CHP (42.5% or more efficient)
or zero emission DG projects first online on or after May 1, 2001.
| Tail CTC (SCE) |
Tail CTC (SDG&E) |
Tail CTC (PG&E) |
| 0.6 ¢ kW/hr |
0.42 ¢ kW/hr |
1.0 ¢ kW/hr |
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:
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.
See matrix for a complete breakdown of all charges.
*****************************************************************
Special Note:
(01/10/04)
On his first day in office, Governor Arnold Schwarzenegger ordered a halt to all pending regulations, and
a review of these and the last five year's worth of regulations. This puts the status of a decision (03-04-030)
by the California Public utility Commission (CPUC) in question. Under the governor's executive order, proposed rules
will be stalled for up to six months, and some may be frozen indefinitely.
The California Energy Commission sent a letter to the state's Office of Administrative Law requesting that the
exit fee exemptions be reinstated. They have made the case that the freezing of the regulation places too much
uncertainty in the DG market. The Director of Finance should make a ruling sometime soon.
******************************************************************
California Building Standards Commission
The California Building Standards Commission is responsible for adopting and enforcing building codes within the
state.
Instructions on how to view the California codes can be viewed by clicking on
California Code of Regulations (CCR), Title 24
California State Fire Marshal
California Energy Commission DG Permitting Information
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.
On March 27, 2001 the California PUC announced new incentive programs to
encourage residential and commercial customers to install grid connected renewables and clean DG resources.
The Self-Generation Incentive Program provides incentives to encourage customers to produce energy
using microturbines, small gas turbines, wind turbines, photovoltaics, fuel cells, and internal
combustion engines. The incentives include payments of $1 - $4.50/Watt, depending on the technology used,
and will be funded through the end of 2007. In October 2003, the Governor signed
AB 1685 which extended the program expiration date from
12/31/04 to 1/1/08, as well as providing funding of approximately $500 million. The bill also expands
some program requirements, including the definition of ultra clean and low emission DG.
The program has 4 incentive levels:
|
Level #1 |
Level #2 |
Level #3N |
Level #3R |
| Technologies: |
Photovoltaic, Fuel Cells*Wind Turbines |
Fuel Cells** |
Microturbines*Internal combustion engines and small gas turbines* |
Microturbines**, ***Internal combustion engines and small gas turbines**, **** |
| Rebate: |
Lesser of $4.50/W or 50% of project cost |
Lesser of $2.50/W or 40% of project cost |
Lesser of $1.00/W or 30% of project cost |
Lesser of $1.50/W or 40% of project cost |
| System Size: |
30 kW minimum to 1.5 MW maximum! |
No minimum, maximum up to 1.5 MW! |
No minimum, maximum up to 1.5 MW! |
No minimum, maximum up to 1.5 MW! |
* Operating on renewable fuel.
** Operating on non-renewable fuel.
*** Using sufficient waste heat recovery and meeting reliability criteria.
**** Both utilizing sufficient waste heat recovery and meeting reliability criteria.
! Maximum system size is 1.5 MW, however, output capacity above the first 1.0 MW is not eligible for incentives.
Customers of PG&E, SDG&E, Edison and SoCal Gas may contact their program administrator for an application,
program handbook, and additional eligibility information. PG&E, SCE, and SoCal Gas will administer
the incentive program in their service territories; San Diego Regional Energy Office will administer
the program in SDG&E's territory.
More information can be found at the
California Energy Commission DG Incentive Website
| 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 |
None |
| Additional Information |
California's interconnection standard is known as Rule 21. Rule 21 applies to all DG 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).
For larger DG units up to 10 MW the utility must perform a 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. |
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