AB 1637: Energy: greenhouse gas reduction.
- Session Year: 2015-2016
- House: Assembly
- Latest Version Date: 2016-09-26
(1)Under existing law, the Public Utilities Commission (PUC) has regulatory authority over public utilities. Existing law requires the PUC to require the administration, until January 1, 2021, of a self-generation incentive program for distributed generation resources and energy storage technologies. Existing law authorizes the PUC, in consultation with the State Energy Resources Conservation and Development Commission, to authorize the annual collection of not more than the amount authorized for the program in the 2008 calendar year.
This bill would increase the maximum annual collection the PUC may authorize for the program to double the amount authorized for the program in the 2008 calendar year.
(2)Existing law requires an electrical corporation to file with the PUC a standard tariff providing for net energy meeting for eligible fuel cell customer-generators and make the tariff available, on a first-come-first-served basis, until the total cumulative rated generating capacity of the eligible fuel cell electrical generating facilities receiving service pursuant to the tariff reaches a level equal to the electrical corporations proportionate share of a statewide limitation of 500 megawatts cumulative rated generation capacity served (program cap). Existing law requires the eligible fuel cell customer-generator to meet certain requirements, including requirements that the customer-generator uses: (A) a fuel cell electrical generation facility with a capacity of not more than one megawatt and (B) technology the PUC has determined will achieve certain reductions in emissions of greenhouse gases. Existing law provides that fuel cell electrical generation facilities are not eligible for the tariff unless the facilities commence operation prior to January 1, 2017.
This bill would increase the program cap by authorizing 500 megawatts in addition to the total installed capacity as of January 1, 2017. The bill would increase to 5 megawatts the maximum amount of generation capacity for a fuel cell electrical generation facility in the program. The bill would require, by March 31, 2017, the State Air Resources Board, in consultation with the Energy Commission, to establish a schedule of annual greenhouse gas emissions reduction standards, as specified, for fuel cell electrical generation resources and would require the PUC to determine if the technology used by the eligible fuel cell customer-generator will achieve those standards. The bill would require the fuel cell electrical generation resource to comply with emission standards adopted by the State Air Resources Board under the distributed generation certification program.
This bill would provide that fuel cell electrical generation facilities are not eligible for the tariff unless the facilities commence operation on or before December 31, 2021.
(1)Under existing law, the Public Utilities Commission (PUC) has regulatory authority over public utilities. Existing law requires the PUC to require the administration, until January 1, 2021, of a self-generation incentive program for distributed generation resources and energy storage technologies. Existing law authorizes the PUC, in consultation with the State Energy Resources Conservation and Development Commission, to authorize the annual collection of not more than the amount authorized for the program in the 2008 calendar year.
This bill would increase the maximum annual collection the PUC may authorize for the program to double the amount authorized for the program in the 2008 calendar year.
(2)Existing law requires an electrical corporation to file with the PUC a standard tariff providing for net energy meeting for eligible fuel cell customer-generators and make the tariff available, on a first-come-first-served basis, until the total cumulative rated generating capacity of the eligible fuel cell electrical generating facilities receiving service pursuant to the tariff reaches a level equal to the electrical corporations proportionate share of a statewide limitation of 500 megawatts cumulative rated generation capacity served (program cap). Existing law requires the eligible fuel cell customer-generator to meet certain requirements, including requirements that the customer-generator uses: (A) a fuel cell electrical generation facility with a capacity of not more than one megawatt and (B) technology the PUC has determined will achieve certain reductions in emissions of greenhouse gases. Existing law provides that fuel cell electrical generation facilities are not eligible for the tariff unless the facilities commence operation prior to January 1, 2017.
This bill would increase the program cap by authorizing 500 megawatts in addition to the total installed capacity as of January 1, 2017. The bill would increase to 5 megawatts the maximum amount of generation capacity for a fuel cell electrical generation facility in the program. The bill would require, by March 31, 2017, the State Air Resources Board, in consultation with the Energy Commission, to establish a schedule of annual greenhouse gas emissions reduction standards, as specified, for fuel cell electrical generation resources and would require the PUC to determine if the technology used by the eligible fuel cell customer-generator will achieve those standards. The bill would require the fuel cell electrical generation resource to comply with emission standards adopted by the State Air Resources Board under the distributed generation certification program.
This bill would provide that fuel cell electrical generation facilities are not eligible for the tariff unless the facilities commence operation on or before December 31, 2021.
(1)Under existing law, the Public Utilities Commission (PUC) has regulatory authority over public utilities. Existing law requires the PUC to require the administration, until January 1, 2021, of a self-generation incentive program for distributed generation resources and energy storage technologies. Existing law authorizes the PUC, in consultation with the State Energy Resources Conservation and Development Commission, to authorize the annual collection of not more than the amount authorized for the program in the 2008 calendar year.
This bill would increase the maximum annual collection the PUC may authorize for the program to double the amount authorized for the program in the 2008 calendar year.
(2)Existing law requires an electrical corporation to file with the PUC a standard tariff providing for net energy meeting for eligible fuel cell customer-generators and make the tariff available, on a first-come-first-served basis, until the total cumulative rated generating capacity of the eligible fuel cell electrical generating facilities receiving service pursuant to the tariff reaches a level equal to the electrical corporations proportionate share of a statewide limitation of 500 megawatts cumulative rated generation capacity served (program cap). Existing law requires the eligible fuel cell customer-generator to meet certain requirements, including requirements that the customer-generator uses: (A) a fuel cell electrical generation facility with a capacity of not more than one megawatt and (B) technology the PUC has determined will achieve certain reductions in emissions of greenhouse gases. Existing law provides that fuel cell electrical generation facilities are not eligible for the tariff unless the facilities commence operation prior to January 1, 2017.
This bill would increase the program cap by authorizing 500 megawatts in addition to the total installed capacity as of January 1, 2017. The bill would increase to 5 megawatts the maximum amount of generation capacity for a fuel cell electrical generation facility in the program. The bill would require, by March 31, 2017, the State Air Resources Board, in consultation with the Energy Commission, to establish a schedule of annual greenhouse gas emissions reduction standards, as specified, for fuel cell electrical generation resources and would require the PUC to determine if the technology used by the eligible fuel cell customer-generator will achieve those standards. The bill would require the fuel cell electrical generation resource to comply with emission standards adopted by the State Air Resources Board under the distributed generation certification program.
This bill would provide that fuel cell electrical generation facilities are not eligible for the tariff unless the facilities commence operation on or before December 31, 2021.
This bill would express the intent of the Legislature to enact statutory changes relating to the Budget Act of 2016.
This bill would express the intent of the Legislature to enact statutory changes relating to the Budget Act of 2016.
This bill would express the intent of the Legislature to enact statutory changes relating to the Budget Act of 2016.
(a)(1)It is the intent of the Legislature that the self-generation incentive program increase deployment of distributed generation and energy storage systems to facilitate the integration of those resources into the electrical grid, improve efficiency and reliability of the distribution and transmission system, and reduce emissions of greenhouse gases, peak demand, and ratepayer costs. It is the further intent of the Legislature that the commission, in future proceedings, provide for an equitable distribution of the costs and benefits of the program.
(2)The commission, in consultation with the Energy Commission, may authorize the annual collection of not more than double the amount authorized for the self-generation incentive program in the 2008 calendar year, through December 31, 2019. The commission shall require the administration of the program for distributed energy resources originally established pursuant to Chapter 329 of the Statutes of 2000 until January 1, 2021. On January 1, 2021, the commission shall provide repayment of all unallocated funds collected pursuant to this section to reduce ratepayer costs.
(3)The commission shall administer solar technologies separately, pursuant to the California Solar Initiative adopted by the commission in Decisions 05-12-044 and 06-01-024, as modified by Article 1 (commencing with Section 2851) of Chapter 9 of Part 2 of Division 1 of this code and Chapter 8.8 (commencing with Section 25780) of Division 15 of the Public Resources Code.
(b)(1)Eligibility for incentives under the self-generation incentive program shall be limited to distributed energy resources that the commission, in consultation with the State Air Resources Board, determines will achieve reductions in emissions of greenhouse gases pursuant to the California Global Warming Solutions Act of 2006 (Division 25.5 (commencing with Section 38500) of the Health and Safety Code).
(2)On or before July 1, 2015, the commission shall update the factor for avoided greenhouse gas emissions based on the most recent data available to the State Air Resources Board for greenhouse gas emissions from electricity sales in the self-generation incentive program administrators service areas as well as current estimates of greenhouse gas emissions over the useful life of the distributed energy resource, including consideration of the effects of the California Renewables Portfolio Standard.
(c)Eligibility for the funding of any combustion-operated distributed generation projects using fossil fuel is subject to all of the following conditions:
(1)An oxides of nitrogen (NOx) emissions rate standard of 0.07 pounds per megawatthour and a minimum efficiency of 60 percent, or any other NOx emissions rate and minimum efficiency standard adopted by the State Air Resources Board. A minimum efficiency of 60 percent shall be measured as useful energy output divided by fuel input. The efficiency determination shall be based on 100 percent load.
(2)Combined heat and power units that meet the 60-percent efficiency standard may take a credit to meet the applicable NOx emissions standard of 0.07 pounds per megawatthour. Credit shall be at the rate of one megawatthour for each 3,400,000 British thermal units (Btus) of heat recovered.
(3)The customer receiving incentives shall adequately maintain and service the combined heat and power units so that during operation the system continues to meet or exceed the efficiency and emissions standards established pursuant to paragraphs (1) and (2).
(4)Notwithstanding paragraph (1), a project that does not meet the applicable NOx emissions standard is eligible if it meets both of the following requirements:
(A)The project operates solely on waste gas. The commission shall require a customer that applies for an incentive pursuant to this paragraph to provide an affidavit or other form of proof that specifies that the project shall be operated solely on waste gas. Incentives awarded pursuant to this paragraph shall be subject to refund and shall be refunded by the recipient to the extent the project does not operate on waste gas. As used in this paragraph, waste gas means natural gas that is generated as a byproduct of petroleum production operations and is not eligible for delivery to the utility pipeline system.
(B)The air quality management district or air pollution control district, in issuing a permit to operate the project, determines that operation of the project will produce an onsite net air emissions benefit compared to permitted onsite emissions if the project does not operate. The commission shall require the customer to secure the permit prior to receiving incentives.
(d)In determining the eligibility for the self-generation incentive program, minimum system efficiency shall be determined either by calculating electrical and process heat efficiency as set forth in Section 216.6, or by calculating overall electrical efficiency.
(e)Eligibility for incentives under the program shall be limited to distributed energy resource technologies that the commission determines meet all of the following requirements:
(1)The distributed energy resource technology shifts onsite energy use to off-peak time periods or reduces demand from the grid by offsetting some or all of the customers onsite energy load, including, but not limited to, peak electric load.
(2)The distributed energy resource technology is commercially available.
(3)The distributed energy resource technology safely utilizes the existing transmission and distribution system.
(4)The distributed energy resource technology improves air quality by reducing criteria air pollutants.
(f)Recipients of the self-generation incentive program funds shall provide relevant data to the commission and the State Air Resources Board, upon request, and shall be subject to onsite inspection to verify equipment operation and performance, including capacity, thermal output, and usage to verify criteria air pollutant and greenhouse gas emissions performance.
(g)In administering the self-generation incentive program, the commission shall determine a capacity factor for each distributed generation system energy resource technology in the program.
(h)(1)In administering the self-generation incentive program, the commission may adjust the amount of rebates and evaluate other public policy interests, including, but not limited to, ratepayers, energy efficiency, peak load reduction, load management, and environmental interests.
(2)The commission shall consider the relative amount and the cost of greenhouse gas emissions reductions, peak demand reductions, system reliability benefits, and other measurable factors when allocating program funds between eligible technologies.
(i)The commission shall ensure that distributed generation resources are made available in the program for all ratepayers.
(j)In administering the self-generation incentive program, the commission shall provide an additional incentive of 20 percent from existing program funds for the installation of eligible distributed generation resources manufactured in California.
(k)The costs of the program adopted and implemented pursuant to this section shall not be recovered from customers participating in the California Alternate Rates for Energy (CARE) program.
(l)The commission shall evaluate the overall success and impact of the self-generation incentive program based on the following performance measures:
(1)The amount of reductions of emissions of greenhouse gases.
(2)The amount of reductions of emissions of criteria air pollutants measured in terms of avoided emissions and reductions of criteria air pollutants represented by emissions credits secured for project approval.
(3)The amount of energy reductions measured in energy value.
(4)The amount of reductions of customer peak demand.
(5)The ratio of the electricity generated by distributed energy resource generation projects receiving incentives from the program to the electricity capable of being produced by those projects, commonly known as a capacity factor.
(6)The value to the electrical transmission and distribution system measured in avoided costs of transmission and distribution upgrades and replacement.
(7)The ability to improve onsite electricity reliability as compared to onsite electricity reliability before the self-generation incentive program technology was placed in service.
SEC. 2.Section 2827.10 of the Public Utilities Code is amended to read:2827.10.(a)As used in this section, the following terms have the following meanings:
(1)Electrical corporation means an electrical corporation, as defined in Section 218.
(2)Eligible fuel cell electrical generating facility means a facility that includes the following:
(A)Integrated powerplant systems containing a stack, tubular array, or other functionally similar configuration used to electrochemically convert fuel to electricity.
(B)An inverter and fuel processing system where necessary.
(C)Other plant equipment, including heat recovery equipment, necessary to support the plants operation or its energy conversion.
(3)(A)Eligible fuel cell customer-generator means a customer of an electrical corporation that meets all the following criteria:
(i)Uses a fuel cell electrical generating facility with a generating capacity of not more than five megawatts that is located on or adjacent to the customers owned, leased, or rented premises, is interconnected and operates in parallel with the electrical grid while the grid is operational or in a grid independent mode when the grid is nonoperational, and is sized to offset part or all of the eligible fuel cell customer-generators own electrical requirements.
(ii)Is the recipient of local, state, or federal funds, or who self-finances projects designed to encourage the development of eligible fuel cell electrical generating facilities.
(iii)Uses technology the commission has determined will achieve reductions in emissions of greenhouse gases pursuant to subdivision (b).
(B)Complies with the emissions standards adopted by the State Air Resources Board pursuant to the distributed generation certification program requirements of Section 94203 of Title 17 of the California Code of Regulations, or any successor regulation.
(C)For purposes of this paragraph, a person or entity is a customer of the electrical corporation if the customer is physically located within the service territory of the electrical corporation and receives bundled service, distribution service, or transmission service from the electrical corporation.
(4)Net energy metering means measuring the difference between the electricity supplied through the electrical grid and the difference between the electricity generated by an eligible fuel cell electrical generating facility and fed back to the electrical grid over a 12-month period as described in subdivision (e). Net energy metering shall be accomplished using a time-of-use meter capable of registering the flow of electricity in two directions. If the existing electrical meter of an eligible fuel cell customer-generator is not capable of measuring the flow of electricity in two directions, the eligible fuel cell customer-generator shall be responsible for all expenses involved in purchasing and installing a meter that is able to measure electricity flow in two directions. If an additional meter or meters are installed, the net energy metering calculation shall yield a result identical to that of a time-of-use meter.
(b)(1)Not later than March 31, 2017, the State Air Resources Board, in consultation with the Energy Commission, shall establish a schedule of annual greenhouse gas emissions reduction standards for a fuel cell electrical generation resource for purposes of clause (iii) of subparagraph (A) of paragraph (3) of subdivision (a) and shall update the schedule every three years with applicable standards for each intervening year.
(2)The greenhouse gas emissions reduction standards shall ensure that each fuel cell electrical generation resource, for purposes of clause (iii) of subparagraph (A) of paragraph (3) of subdivision (a), reduces greenhouse gas emissions compared to the electrical grid resources, including renewable resources, that the fuel cell electrical generation resource displaces, accounting for both procurement and operation of the electrical grid.
(c)(1)Every electrical corporation, not later than March 1, 2004, shall file with the commission a standard tariff providing for net energy metering for eligible fuel cell customer-generators, consistent with this section. Subject to the limitation in subdivision (g), every electrical corporation shall make this tariff available to eligible fuel cell customer-generators upon request, on a first-come-first-served basis, until the total cumulative rated generating capacity of the eligible fuel cell electrical generating facilities receiving service pursuant to the tariff, in addition to the installed capacity as of January 1, 2017, reaches a level equal to its proportionate share of a statewide limitation of 500 megawatts cumulative rated generation capacity served under this section. The proportionate share shall be calculated based on the ratio of the electrical corporations peak demand compared to the total statewide peak demand.
(2)To continue the growth of the market for onsite electrical generation using fuel cells, the commission may review and incrementally raise the limitation established in paragraph (1) on the total cumulative rated generating capacity of the eligible fuel cell electrical generating facilities receiving service pursuant to the tariff in paragraph (1).
(d)In determining the eligibility for the cumulative rated generating capacity within an electrical corporations service territory, preference shall be given to facilities that, at the time of installation, are located in a community with significant exposure to air contaminants or localized air contaminants, or both, including, but not limited to, communities of minority populations or low-income populations, or both, based on the ambient air quality standards established pursuant to Division 26 (commencing with Section 39000) of the Health and Safety Code.
(e)(1)Each net energy metering contract or tariff shall be identical, with respect to rate structure, all retail rate components, and any monthly charges, to the contract or tariff to which the customer would be assigned if the customer was not an eligible fuel cell customer-generator. Any new or additional demand charge, standby charge, customer charge, minimum monthly charge, interconnection charge, or other charge that would increase an eligible fuel cell customer-generators costs beyond those of other customers in the rate class to which the eligible fuel cell customer-generator would otherwise be assigned are contrary to the intent of the Legislature in enacting this section, and shall not form a part of net energy metering tariffs.
(2)The commission shall authorize an electrical corporation to charge a fuel cell customer-generator a fee based on the cost to the utility associated with providing interconnection inspection services for that fuel cell customer-generator.
(f)The net metering calculation shall be made by measuring the difference between the electricity supplied to the eligible fuel cell customer-generator and the electricity generated by the eligible fuel cell customer-generator and fed back to the electrical grid over a 12-month period. The following rules shall apply to the annualized metering calculation:
(1)The eligible fuel cell customer-generator shall, at the end of each 12-month period following the date of final interconnection of the eligible fuel cell electrical generating facility with an electrical corporation, and at each anniversary date thereafter, be billed for electricity used during that period. The electrical corporation shall determine if the eligible fuel cell customer-generator was a net consumer or a net producer of electricity during that period. For purposes of determining if the eligible fuel cell customer-generator was a net consumer or a net producer of electricity during that period, the electrical corporation shall aggregate the electrical load of the meters located on the property where the eligible fuel cell electrical generating facility is located and on all property adjacent or contiguous to the property on which the facility is located, if those properties are solely owned, leased, or rented by the eligible fuel cell customer-generator. Each aggregated account shall be billed and measured according to a time-of-use rate schedule.
(2)At the end of each 12-month period, where the electricity supplied during the period by the electrical corporation exceeds the electricity generated by the eligible fuel cell customer-generator during that same period, the eligible fuel cell customer-generator is a net electricity consumer and the electrical corporation shall be owed compensation for the eligible fuel cell customer-generators net kilowatthour consumption over that same period. The compensation owed for the eligible fuel cell customer-generators consumption shall be calculated as follows:
(A)The generation charges for any net monthly consumption of electricity shall be calculated according to the terms of the tariff to which the same customer would be assigned to or be eligible for if the customer was not an eligible fuel cell customer-generator. When the eligible fuel cell customer-generator is a net generator during any discrete time-of-use period, the net kilowatthours produced shall be valued at the same price per kilowatthour as the electrical corporation would charge for retail kilowatthour sales for generation, exclusive of any surcharges, during that same time-of-use period. If the eligible fuel cell customer-generators time-of-use electrical meter is unable to measure the flow of electricity in two directions, paragraph (4) of subdivision (a) shall apply. All other charges, other than generation charges, shall be calculated in accordance with the eligible fuel cell customer-generators applicable tariff and based on the total kilowatthours delivered by the electrical corporation to the eligible fuel cell customer-generator. To the extent that charges for transmission and distribution services are recovered through demand charges in any particular month, no standby reservation charges shall apply in that monthly billing cycle.
(B)The net balance of moneys owed shall be paid in accordance with the electrical corporations normal billing cycle.
(3)At the end of each 12-month period, where the electricity generated by the eligible fuel cell customer-generator during the 12-month period exceeds the electricity supplied by the electrical corporation during that same period, the eligible fuel cell customer-generator is a net electricity producer and the electrical corporation shall retain any excess kilowatthours generated during the prior 12-month period. The eligible fuel cell customer-generator shall not be owed any compensation for those excess kilowatthours.
(4)If an eligible fuel cell customer-generator terminates service with the electrical corporation, the electrical corporation shall reconcile the eligible fuel cell customer-generators consumption and production of electricity during any 12-month period.
(g)A fuel cell electrical generating facility shall not be eligible for the tariff unless it commences operation on or before December 31, 2021, unless a later enacted statute, that is chaptered on or before December 31, 2021, extends this eligibility commencement date. The tariff shall remain in effect for an eligible fuel cell electrical generating facility that commences operation pursuant to the tariff on or before December 31, 2021. A fuel cell customer-generator shall be eligible for the tariff established pursuant to this section only for the operating life of the eligible fuel cell electrical generating facility.
(a)(1)It is the intent of the Legislature that the self-generation incentive program increase deployment of distributed generation and energy storage systems to facilitate the integration of those resources into the electrical grid, improve efficiency and reliability of the distribution and transmission system, and reduce emissions of greenhouse gases, peak demand, and ratepayer costs. It is the further intent of the Legislature that the commission, in future proceedings, provide for an equitable distribution of the costs and benefits of the program.
(2)The commission, in consultation with the Energy Commission, may authorize the annual collection of not more than double the amount authorized for the self-generation incentive program in the 2008 calendar year, through December 31, 2019. The commission shall require the administration of the program for distributed energy resources originally established pursuant to Chapter 329 of the Statutes of 2000 until January 1, 2021. On January 1, 2021, the commission shall provide repayment of all unallocated funds collected pursuant to this section to reduce ratepayer costs.
(3)The commission shall administer solar technologies separately, pursuant to the California Solar Initiative adopted by the commission in Decisions 05-12-044 and 06-01-024, as modified by Article 1 (commencing with Section 2851) of Chapter 9 of Part 2 of Division 1 of this code and Chapter 8.8 (commencing with Section 25780) of Division 15 of the Public Resources Code.
(b)(1)Eligibility for incentives under the self-generation incentive program shall be limited to distributed energy resources that the commission, in consultation with the State Air Resources Board, determines will achieve reductions in emissions of greenhouse gases pursuant to the California Global Warming Solutions Act of 2006 (Division 25.5 (commencing with Section 38500) of the Health and Safety Code).
(2)On or before July 1, 2015, the commission shall update the factor for avoided greenhouse gas emissions based on the most recent data available to the State Air Resources Board for greenhouse gas emissions from electricity sales in the self-generation incentive program administrators service areas as well as current estimates of greenhouse gas emissions over the useful life of the distributed energy resource, including consideration of the effects of the California Renewables Portfolio Standard.
(c)Eligibility for the funding of any combustion-operated distributed generation projects using fossil fuel is subject to all of the following conditions:
(1)An oxides of nitrogen (NOx) emissions rate standard of 0.07 pounds per megawatthour and a minimum efficiency of 60 percent, or any other NOx emissions rate and minimum efficiency standard adopted by the State Air Resources Board. A minimum efficiency of 60 percent shall be measured as useful energy output divided by fuel input. The efficiency determination shall be based on 100 percent load.
(2)Combined heat and power units that meet the 60-percent efficiency standard may take a credit to meet the applicable NOx emissions standard of 0.07 pounds per megawatthour. Credit shall be at the rate of one megawatthour for each 3,400,000 British thermal units (Btus) of heat recovered.
(3)The customer receiving incentives shall adequately maintain and service the combined heat and power units so that during operation the system continues to meet or exceed the efficiency and emissions standards established pursuant to paragraphs (1) and (2).
(4)Notwithstanding paragraph (1), a project that does not meet the applicable NOx emissions standard is eligible if it meets both of the following requirements:
(A)The project operates solely on waste gas. The commission shall require a customer that applies for an incentive pursuant to this paragraph to provide an affidavit or other form of proof that specifies that the project shall be operated solely on waste gas. Incentives awarded pursuant to this paragraph shall be subject to refund and shall be refunded by the recipient to the extent the project does not operate on waste gas. As used in this paragraph, waste gas means natural gas that is generated as a byproduct of petroleum production operations and is not eligible for delivery to the utility pipeline system.
(B)The air quality management district or air pollution control district, in issuing a permit to operate the project, determines that operation of the project will produce an onsite net air emissions benefit compared to permitted onsite emissions if the project does not operate. The commission shall require the customer to secure the permit prior to receiving incentives.
(d)In determining the eligibility for the self-generation incentive program, minimum system efficiency shall be determined either by calculating electrical and process heat efficiency as set forth in Section 216.6, or by calculating overall electrical efficiency.
(e)Eligibility for incentives under the program shall be limited to distributed energy resource technologies that the commission determines meet all of the following requirements:
(1)The distributed energy resource technology shifts onsite energy use to off-peak time periods or reduces demand from the grid by offsetting some or all of the customers onsite energy load, including, but not limited to, peak electric load.
(2)The distributed energy resource technology is commercially available.
(3)The distributed energy resource technology safely utilizes the existing transmission and distribution system.
(4)The distributed energy resource technology improves air quality by reducing criteria air pollutants.
(f)Recipients of the self-generation incentive program funds shall provide relevant data to the commission and the State Air Resources Board, upon request, and shall be subject to onsite inspection to verify equipment operation and performance, including capacity, thermal output, and usage to verify criteria air pollutant and greenhouse gas emissions performance.
(g)In administering the self-generation incentive program, the commission shall determine a capacity factor for each distributed generation system energy resource technology in the program.
(h)(1)In administering the self-generation incentive program, the commission may adjust the amount of rebates and evaluate other public policy interests, including, but not limited to, ratepayers, energy efficiency, peak load reduction, load management, and environmental interests.
(2)The commission shall consider the relative amount and the cost of greenhouse gas emissions reductions, peak demand reductions, system reliability benefits, and other measurable factors when allocating program funds between eligible technologies.
(i)The commission shall ensure that distributed generation resources are made available in the program for all ratepayers.
(j)In administering the self-generation incentive program, the commission shall provide an additional incentive of 20 percent from existing program funds for the installation of eligible distributed generation resources manufactured in California.
(k)The costs of the program adopted and implemented pursuant to this section shall not be recovered from customers participating in the California Alternate Rates for Energy (CARE) program.
(l)The commission shall evaluate the overall success and impact of the self-generation incentive program based on the following performance measures:
(1)The amount of reductions of emissions of greenhouse gases.
(2)The amount of reductions of emissions of criteria air pollutants measured in terms of avoided emissions and reductions of criteria air pollutants represented by emissions credits secured for project approval.
(3)The amount of energy reductions measured in energy value.
(4)The amount of reductions of customer peak demand.
(5)The ratio of the electricity generated by distributed energy resource generation projects receiving incentives from the program to the electricity capable of being produced by those projects, commonly known as a capacity factor.
(6)The value to the electrical transmission and distribution system measured in avoided costs of transmission and distribution upgrades and replacement.
(7)The ability to improve onsite electricity reliability as compared to onsite electricity reliability before the self-generation incentive program technology was placed in service.
SEC. 2.Section 2827.10 of the Public Utilities Code is amended to read:2827.10.(a)As used in this section, the following terms have the following meanings:
(1)Electrical corporation means an electrical corporation, as defined in Section 218.
(2)Eligible fuel cell electrical generating facility means a facility that includes the following:
(A)Integrated powerplant systems containing a stack, tubular array, or other functionally similar configuration used to electrochemically convert fuel to electricity.
(B)An inverter and fuel processing system where necessary.
(C)Other plant equipment, including heat recovery equipment, necessary to support the plants operation or its energy conversion.
(3)(A)Eligible fuel cell customer-generator means a customer of an electrical corporation that meets all the following criteria:
(i)Uses a fuel cell electrical generating facility with a generating capacity of not more than five megawatts that is located on or adjacent to the customers owned, leased, or rented premises, is interconnected and operates in parallel with the electrical grid while the grid is operational or in a grid independent mode when the grid is nonoperational, and is sized to offset part or all of the eligible fuel cell customer-generators own electrical requirements.
(ii)Is the recipient of local, state, or federal funds, or who self-finances projects designed to encourage the development of eligible fuel cell electrical generating facilities.
(iii)Uses technology the commission has determined will achieve reductions in emissions of greenhouse gases pursuant to subdivision (b).
(B)Complies with the emissions standards adopted by the State Air Resources Board pursuant to the distributed generation certification program requirements of Section 94203 of Title 17 of the California Code of Regulations, or any successor regulation.
(C)For purposes of this paragraph, a person or entity is a customer of the electrical corporation if the customer is physically located within the service territory of the electrical corporation and receives bundled service, distribution service, or transmission service from the electrical corporation.
(4)Net energy metering means measuring the difference between the electricity supplied through the electrical grid and the difference between the electricity generated by an eligible fuel cell electrical generating facility and fed back to the electrical grid over a 12-month period as described in subdivision (e). Net energy metering shall be accomplished using a time-of-use meter capable of registering the flow of electricity in two directions. If the existing electrical meter of an eligible fuel cell customer-generator is not capable of measuring the flow of electricity in two directions, the eligible fuel cell customer-generator shall be responsible for all expenses involved in purchasing and installing a meter that is able to measure electricity flow in two directions. If an additional meter or meters are installed, the net energy metering calculation shall yield a result identical to that of a time-of-use meter.
(b)(1)Not later than March 31, 2017, the State Air Resources Board, in consultation with the Energy Commission, shall establish a schedule of annual greenhouse gas emissions reduction standards for a fuel cell electrical generation resource for purposes of clause (iii) of subparagraph (A) of paragraph (3) of subdivision (a) and shall update the schedule every three years with applicable standards for each intervening year.
(2)The greenhouse gas emissions reduction standards shall ensure that each fuel cell electrical generation resource, for purposes of clause (iii) of subparagraph (A) of paragraph (3) of subdivision (a), reduces greenhouse gas emissions compared to the electrical grid resources, including renewable resources, that the fuel cell electrical generation resource displaces, accounting for both procurement and operation of the electrical grid.
(c)(1)Every electrical corporation, not later than March 1, 2004, shall file with the commission a standard tariff providing for net energy metering for eligible fuel cell customer-generators, consistent with this section. Subject to the limitation in subdivision (g), every electrical corporation shall make this tariff available to eligible fuel cell customer-generators upon request, on a first-come-first-served basis, until the total cumulative rated generating capacity of the eligible fuel cell electrical generating facilities receiving service pursuant to the tariff, in addition to the installed capacity as of January 1, 2017, reaches a level equal to its proportionate share of a statewide limitation of 500 megawatts cumulative rated generation capacity served under this section. The proportionate share shall be calculated based on the ratio of the electrical corporations peak demand compared to the total statewide peak demand.
(2)To continue the growth of the market for onsite electrical generation using fuel cells, the commission may review and incrementally raise the limitation established in paragraph (1) on the total cumulative rated generating capacity of the eligible fuel cell electrical generating facilities receiving service pursuant to the tariff in paragraph (1).
(d)In determining the eligibility for the cumulative rated generating capacity within an electrical corporations service territory, preference shall be given to facilities that, at the time of installation, are located in a community with significant exposure to air contaminants or localized air contaminants, or both, including, but not limited to, communities of minority populations or low-income populations, or both, based on the ambient air quality standards established pursuant to Division 26 (commencing with Section 39000) of the Health and Safety Code.
(e)(1)Each net energy metering contract or tariff shall be identical, with respect to rate structure, all retail rate components, and any monthly charges, to the contract or tariff to which the customer would be assigned if the customer was not an eligible fuel cell customer-generator. Any new or additional demand charge, standby charge, customer charge, minimum monthly charge, interconnection charge, or other charge that would increase an eligible fuel cell customer-generators costs beyond those of other customers in the rate class to which the eligible fuel cell customer-generator would otherwise be assigned are contrary to the intent of the Legislature in enacting this section, and shall not form a part of net energy metering tariffs.
(2)The commission shall authorize an electrical corporation to charge a fuel cell customer-generator a fee based on the cost to the utility associated with providing interconnection inspection services for that fuel cell customer-generator.
(f)The net metering calculation shall be made by measuring the difference between the electricity supplied to the eligible fuel cell customer-generator and the electricity generated by the eligible fuel cell customer-generator and fed back to the electrical grid over a 12-month period. The following rules shall apply to the annualized metering calculation:
(1)The eligible fuel cell customer-generator shall, at the end of each 12-month period following the date of final interconnection of the eligible fuel cell electrical generating facility with an electrical corporation, and at each anniversary date thereafter, be billed for electricity used during that period. The electrical corporation shall determine if the eligible fuel cell customer-generator was a net consumer or a net producer of electricity during that period. For purposes of determining if the eligible fuel cell customer-generator was a net consumer or a net producer of electricity during that period, the electrical corporation shall aggregate the electrical load of the meters located on the property where the eligible fuel cell electrical generating facility is located and on all property adjacent or contiguous to the property on which the facility is located, if those properties are solely owned, leased, or rented by the eligible fuel cell customer-generator. Each aggregated account shall be billed and measured according to a time-of-use rate schedule.
(2)At the end of each 12-month period, where the electricity supplied during the period by the electrical corporation exceeds the electricity generated by the eligible fuel cell customer-generator during that same period, the eligible fuel cell customer-generator is a net electricity consumer and the electrical corporation shall be owed compensation for the eligible fuel cell customer-generators net kilowatthour consumption over that same period. The compensation owed for the eligible fuel cell customer-generators consumption shall be calculated as follows:
(A)The generation charges for any net monthly consumption of electricity shall be calculated according to the terms of the tariff to which the same customer would be assigned to or be eligible for if the customer was not an eligible fuel cell customer-generator. When the eligible fuel cell customer-generator is a net generator during any discrete time-of-use period, the net kilowatthours produced shall be valued at the same price per kilowatthour as the electrical corporation would charge for retail kilowatthour sales for generation, exclusive of any surcharges, during that same time-of-use period. If the eligible fuel cell customer-generators time-of-use electrical meter is unable to measure the flow of electricity in two directions, paragraph (4) of subdivision (a) shall apply. All other charges, other than generation charges, shall be calculated in accordance with the eligible fuel cell customer-generators applicable tariff and based on the total kilowatthours delivered by the electrical corporation to the eligible fuel cell customer-generator. To the extent that charges for transmission and distribution services are recovered through demand charges in any particular month, no standby reservation charges shall apply in that monthly billing cycle.
(B)The net balance of moneys owed shall be paid in accordance with the electrical corporations normal billing cycle.
(3)At the end of each 12-month period, where the electricity generated by the eligible fuel cell customer-generator during the 12-month period exceeds the electricity supplied by the electrical corporation during that same period, the eligible fuel cell customer-generator is a net electricity producer and the electrical corporation shall retain any excess kilowatthours generated during the prior 12-month period. The eligible fuel cell customer-generator shall not be owed any compensation for those excess kilowatthours.
(4)If an eligible fuel cell customer-generator terminates service with the electrical corporation, the electrical corporation shall reconcile the eligible fuel cell customer-generators consumption and production of electricity during any 12-month period.
(g)A fuel cell electrical generating facility shall not be eligible for the tariff unless it commences operation on or before December 31, 2021, unless a later enacted statute, that is chaptered on or before December 31, 2021, extends this eligibility commencement date. The tariff shall remain in effect for an eligible fuel cell electrical generating facility that commences operation pursuant to the tariff on or before December 31, 2021. A fuel cell customer-generator shall be eligible for the tariff established pursuant to this section only for the operating life of the eligible fuel cell electrical generating facility.
(a)(1)It is the intent of the Legislature that the self-generation incentive program increase deployment of distributed generation and energy storage systems to facilitate the integration of those resources into the electrical grid, improve efficiency and reliability of the distribution and transmission system, and reduce emissions of greenhouse gases, peak demand, and ratepayer costs. It is the further intent of the Legislature that the commission, in future proceedings, provide for an equitable distribution of the costs and benefits of the program.
(2)The commission, in consultation with the Energy Commission, may authorize the annual collection of not more than double the amount authorized for the self-generation incentive program in the 2008 calendar year, through December 31, 2019. The commission shall require the administration of the program for distributed energy resources originally established pursuant to Chapter 329 of the Statutes of 2000 until January 1, 2021. On January 1, 2021, the commission shall provide repayment of all unallocated funds collected pursuant to this section to reduce ratepayer costs.
(3)The commission shall administer solar technologies separately, pursuant to the California Solar Initiative adopted by the commission in Decisions 05-12-044 and 06-01-024, as modified by Article 1 (commencing with Section 2851) of Chapter 9 of Part 2 of Division 1 of this code and Chapter 8.8 (commencing with Section 25780) of Division 15 of the Public Resources Code.
(b)(1)Eligibility for incentives under the self-generation incentive program shall be limited to distributed energy resources that the commission, in consultation with the State Air Resources Board, determines will achieve reductions in emissions of greenhouse gases pursuant to the California Global Warming Solutions Act of 2006 (Division 25.5 (commencing with Section 38500) of the Health and Safety Code).
(2)On or before July 1, 2015, the commission shall update the factor for avoided greenhouse gas emissions based on the most recent data available to the State Air Resources Board for greenhouse gas emissions from electricity sales in the self-generation incentive program administrators service areas as well as current estimates of greenhouse gas emissions over the useful life of the distributed energy resource, including consideration of the effects of the California Renewables Portfolio Standard.
(c)Eligibility for the funding of any combustion-operated distributed generation projects using fossil fuel is subject to all of the following conditions:
(1)An oxides of nitrogen (NOx) emissions rate standard of 0.07 pounds per megawatthour and a minimum efficiency of 60 percent, or any other NOx emissions rate and minimum efficiency standard adopted by the State Air Resources Board. A minimum efficiency of 60 percent shall be measured as useful energy output divided by fuel input. The efficiency determination shall be based on 100 percent load.
(2)Combined heat and power units that meet the 60-percent efficiency standard may take a credit to meet the applicable NOx emissions standard of 0.07 pounds per megawatthour. Credit shall be at the rate of one megawatthour for each 3,400,000 British thermal units (Btus) of heat recovered.
(3)The customer receiving incentives shall adequately maintain and service the combined heat and power units so that during operation the system continues to meet or exceed the efficiency and emissions standards established pursuant to paragraphs (1) and (2).
(4)Notwithstanding paragraph (1), a project that does not meet the applicable NOx emissions standard is eligible if it meets both of the following requirements:
(A)The project operates solely on waste gas. The commission shall require a customer that applies for an incentive pursuant to this paragraph to provide an affidavit or other form of proof that specifies that the project shall be operated solely on waste gas. Incentives awarded pursuant to this paragraph shall be subject to refund and shall be refunded by the recipient to the extent the project does not operate on waste gas. As used in this paragraph, waste gas means natural gas that is generated as a byproduct of petroleum production operations and is not eligible for delivery to the utility pipeline system.
(B)The air quality management district or air pollution control district, in issuing a permit to operate the project, determines that operation of the project will produce an onsite net air emissions benefit compared to permitted onsite emissions if the project does not operate. The commission shall require the customer to secure the permit prior to receiving incentives.
(d)In determining the eligibility for the self-generation incentive program, minimum system efficiency shall be determined either by calculating electrical and process heat efficiency as set forth in Section 216.6, or by calculating overall electrical efficiency.
(e)Eligibility for incentives under the program shall be limited to distributed energy resource technologies that the commission determines meet all of the following requirements:
(1)The distributed energy resource technology shifts onsite energy use to off-peak time periods or reduces demand from the grid by offsetting some or all of the customers onsite energy load, including, but not limited to, peak electric load.
(2)The distributed energy resource technology is commercially available.
(3)The distributed energy resource technology safely utilizes the existing transmission and distribution system.
(4)The distributed energy resource technology improves air quality by reducing criteria air pollutants.
(f)Recipients of the self-generation incentive program funds shall provide relevant data to the commission and the State Air Resources Board, upon request, and shall be subject to onsite inspection to verify equipment operation and performance, including capacity, thermal output, and usage to verify criteria air pollutant and greenhouse gas emissions performance.
(g)In administering the self-generation incentive program, the commission shall determine a capacity factor for each distributed generation system energy resource technology in the program.
(h)(1)In administering the self-generation incentive program, the commission may adjust the amount of rebates and evaluate other public policy interests, including, but not limited to, ratepayers, energy efficiency, peak load reduction, load management, and environmental interests.
(2)The commission shall consider the relative amount and the cost of greenhouse gas emissions reductions, peak demand reductions, system reliability benefits, and other measurable factors when allocating program funds between eligible technologies.
(i)The commission shall ensure that distributed generation resources are made available in the program for all ratepayers.
(j)In administering the self-generation incentive program, the commission shall provide an additional incentive of 20 percent from existing program funds for the installation of eligible distributed generation resources manufactured in California.
(k)The costs of the program adopted and implemented pursuant to this section shall not be recovered from customers participating in the California Alternate Rates for Energy (CARE) program.
(l)The commission shall evaluate the overall success and impact of the self-generation incentive program based on the following performance measures:
(1)The amount of reductions of emissions of greenhouse gases.
(2)The amount of reductions of emissions of criteria air pollutants measured in terms of avoided emissions and reductions of criteria air pollutants represented by emissions credits secured for project approval.
(3)The amount of energy reductions measured in energy value.
(4)The amount of reductions of customer peak demand.
(5)The ratio of the electricity generated by distributed energy resource generation projects receiving incentives from the program to the electricity capable of being produced by those projects, commonly known as a capacity factor.
(6)The value to the electrical transmission and distribution system measured in avoided costs of transmission and distribution upgrades and replacement.
(7)The ability to improve onsite electricity reliability as compared to onsite electricity reliability before the self-generation incentive program technology was placed in service.
SEC. 2.Section 2827.10 of the Public Utilities Code is amended to read:2827.10.(a)As used in this section, the following terms have the following meanings:
(1)Electrical corporation means an electrical corporation, as defined in Section 218.
(2)Eligible fuel cell electrical generating facility means a facility that includes the following:
(A)Integrated powerplant systems containing a stack, tubular array, or other functionally similar configuration used to electrochemically convert fuel to electricity.
(B)An inverter and fuel processing system where necessary.
(C)Other plant equipment, including heat recovery equipment, necessary to support the plants operation or its energy conversion.
(3)(A)Eligible fuel cell customer-generator means a customer of an electrical corporation that meets all the following criteria:
(i)Uses a fuel cell electrical generating facility with a generating capacity of not more than one megawatt five megawatts that is located on or adjacent to the customers owned, leased, or rented premises, is interconnected and operates in parallel with the electrical grid while the grid is operational or in a grid independent mode when the grid is nonoperational, and is sized to offset part or all of the eligible fuel cell customer-generators own electrical requirements.
(ii)Is the recipient of local, state, or federal funds, or who self-finances projects designed to encourage the development of eligible fuel cell electrical generating facilities.
(iii)Uses technology the commission has determined will achieve reductions in emissions of greenhouse gases pursuant to subdivision (b), and meets the emission requirements for eligibility for funding set forth in subdivision (c), of Section 379.6. (b).
(B)Complies with the emissions standards adopted by the State Air Resources Board pursuant to the distributed generation certification program requirements of Section 94203 of Title 17 of the California Code of Regulations, or any successor regulation.
(B)
(C)For purposes of this paragraph, a person or entity is a customer of the electrical corporation if the customer is physically located within the service territory of the electrical corporation and receives bundled service, distribution service, or transmission service from the electrical corporation.
(4)Net energy metering means measuring the difference between the electricity supplied through the electrical grid and the difference between the electricity generated by an eligible fuel cell electrical generating facility and fed back to the electrical grid over a 12-month period as described in subdivision (e). Net energy metering shall be accomplished using a time-of-use meter capable of registering the flow of electricity in two directions. If the existing electrical meter of an eligible fuel cell customer-generator is not capable of measuring the flow of electricity in two directions, the eligible fuel cell customer-generator shall be responsible for all expenses involved in purchasing and installing a meter that is able to measure electricity flow in two directions. If an additional meter or meters are installed, the net energy metering calculation shall yield a result identical to that of a time-of-use meter.
(b)(1)Not later than March 31, 2017, the State Air Resources Board, in consultation with the Energy Commission, shall establish a schedule of annual greenhouse gas emissions reduction standards for a fuel cell electrical generation resource for purposes of clause (iii) of subparagraph (A) of paragraph (3) of subdivision (a) and shall update the schedule every three years with applicable standards for each intervening year.
(2)The greenhouse gas emissions reduction standards shall ensure that each fuel cell electrical generation resource, for purposes of clause (iii) of subparagraph (A) of paragraph (3) of subdivision (a), reduces greenhouse gas emissions compared to the electrical grid resources, including renewable resources, that the fuel cell electrical generation resource displaces, accounting for both procurement and operation of the electrical grid.
(b)
(c)(1)Every electrical corporation, not later than March 1, 2004, shall file with the commission a standard tariff providing for net energy metering for eligible fuel cell customer-generators, consistent with this section. Subject to the limitation in subdivision (f), (g), every electrical corporation shall make this tariff available to eligible fuel cell customer-generators upon request, on a first-come-first-served basis, until the total cumulative rated generating capacity of the eligible fuel cell electrical generating facilities receiving service pursuant to the tariff tariff, in addition to the installed capacity as of January 1, 2017, reaches a level equal to its proportionate share of a statewide limitation of 500 megawatts cumulative rated generation capacity served under this section. The proportionate share shall be calculated based on the ratio of the electrical corporations peak demand compared to the total statewide peak demand.
(2)To continue the growth of the market for onsite electrical generation using fuel cells, the commission may review and incrementally raise the limitation established in paragraph (1) on the total cumulative rated generating capacity of the eligible fuel cell electrical generating facilities receiving service pursuant to the tariff in paragraph (1).
(c)
(d)In determining the eligibility for the cumulative rated generating capacity within an electrical corporations service territory, preference shall be given to facilities that, at the time of installation, are located in a community with significant exposure to air contaminants or localized air contaminants, or both, including, but not limited to, communities of minority populations or low-income populations, or both, based on the ambient air quality standards established pursuant to Division 26 (commencing with Section 39000) of the Health and Safety Code.
(d)
(e)(1)Each net energy metering contract or tariff shall be identical, with respect to rate structure, all retail rate components, and any monthly charges, to the contract or tariff to which the customer would be assigned if the customer was not an eligible fuel cell customer-generator. Any new or additional demand charge, standby charge, customer charge, minimum monthly charge, interconnection charge, or other charge that would increase an eligible fuel cell customer-generators costs beyond those of other customers in the rate class to which the eligible fuel cell customer-generator would otherwise be assigned are contrary to the intent of the Legislature in enacting this section, and shall not form a part of net energy metering tariffs.
(2)The commission shall authorize an electrical corporation to charge a fuel cell customer-generator a fee based on the cost to the utility associated with providing interconnection inspection services for that fuel cell customer-generator.
(e)
(f)The net metering calculation shall be made by measuring the difference between the electricity supplied to the eligible fuel cell customer-generator and the electricity generated by the eligible fuel cell customer-generator and fed back to the electrical grid over a 12-month period. The following rules shall apply to the annualized metering calculation:
(1)The eligible fuel cell customer-generator shall, at the end of each 12-month period following the date of final interconnection of the eligible fuel cell electrical generating facility with an electrical corporation, and at each anniversary date thereafter, be billed for electricity used during that period. The electrical corporation shall determine if the eligible fuel cell customer-generator was a net consumer or a net producer of electricity during that period. For purposes of determining if the eligible fuel cell customer-generator was a net consumer or a net producer of electricity during that period, the electrical corporation shall aggregate the electrical load of the meters located on the property where the eligible fuel cell electrical generating facility is located and on all property adjacent or contiguous to the property on which the facility is located, if those properties are solely owned, leased, or rented by the eligible fuel cell customer-generator. Each aggregated account shall be billed and measured according to a time-of-use rate schedule.
(2)At the end of each 12-month period, where the electricity supplied during the period by the electrical corporation exceeds the electricity generated by the eligible fuel cell customer-generator during that same period, the eligible fuel cell customer-generator is a net electricity consumer and the electrical corporation shall be owed compensation for the eligible fuel cell customer-generators net kilowatthour consumption over that same period. The compensation owed for the eligible fuel cell customer-generators consumption shall be calculated as follows:
(A)The generation charges for any net monthly consumption of electricity shall be calculated according to the terms of the tariff to which the same customer would be assigned to or be eligible for if the customer was not an eligible fuel cell customer-generator. When the eligible fuel cell customer-generator is a net generator during any discrete time-of-use period, the net kilowatthours produced shall be valued at the same price per kilowatthour as the electrical corporation would charge for retail kilowatthour sales for generation, exclusive of any surcharges, during that same time-of-use period. If the eligible fuel cell customer-generators time-of-use electrical meter is unable to measure the flow of electricity in two directions, paragraph (4) of subdivision (a) shall apply. All other charges, other than generation charges, shall be calculated in accordance with the eligible fuel cell customer-generators applicable tariff and based on the total kilowatthours delivered by the electrical corporation to the eligible fuel cell customer-generator. To the extent that charges for transmission and distribution services are recovered through demand charges in any particular month, no standby reservation charges shall apply in that monthly billing cycle.
(B)The net balance of moneys owed shall be paid in accordance with the electrical corporations normal billing cycle.
(3)At the end of each 12-month period, where the electricity generated by the eligible fuel cell customer-generator during the 12-month period exceeds the electricity supplied by the electrical corporation during that same period, the eligible fuel cell customer-generator is a net electricity producer and the electrical corporation shall retain any excess kilowatthours generated during the prior 12-month period. The eligible fuel cell customer-generator shall not be owed any compensation for those excess kilowatthours.
(4)If an eligible fuel cell customer-generator terminates service with the electrical corporation, the electrical corporation shall reconcile the eligible fuel cell customer-generators consumption and production of electricity during any 12-month period.
(f)
(g)A fuel cell electrical generating facility shall not be eligible for the tariff unless it commences operation prior to January 1, 2017, on or before December 31, 2021, unless a later enacted statute, that is chaptered before January 1, 2017, on or before December 31, 2021, extends this eligibility commencement date. The tariff shall remain in effect for an eligible fuel cell electrical generating facility that commences operation pursuant to the tariff prior to January 1, 2017. on or before December 31, 2021. A fuel cell customer-generator shall be eligible for the tariff established pursuant to this section only for the operating life of the eligible fuel cell electrical generating facility.
SECTION 1.It is the intent of the Legislature to enact statutory changes relating to the 2016 Budget Act.
HeadingLine 7.It is the intent of the Legislature to enact statutory changes relating to the Budget Act of 2016. 2016 Budget Act.
It is the intent of the Legislature to enact statutory changes relating to the Budget Act of 2016.
|
Date
|
Status
|
|---|---|
| Aug 29, 2016 | Joint Rule 62(a), file notice suspended. |
| Aug 19, 2016 | (Ayes 22. Noes 13.) |
| Aug 19, 2016 | Ordered to third reading. |
| Aug 19, 2016 | Withdrawn from committee. |
| Aug 22, 2016 | Read third time. Passed. Ordered to the Assembly. |
| Aug 22, 2016 | Read third time. Passed. Ordered to the Assembly. (Ayes 23. Noes 12. Page 5238.). |
| Aug 23, 2016 | In Assembly. Concurrence in Senate amendments pending. May be considered on or after August 25 pursuant to Assembly Rule 77. |
| Aug 23, 2016 | Measure version as amended on August 18 corrected. |
| Aug 25, 2016 | Re-referred to Coms. on NAT. RES. and APPR. pursuant to Assembly Rule 77.2. |
| Aug 19, 2016 | (Ayes 22. Noes 13. Page 5167.) |
| Aug 29, 2016 | Joint Rule 62(a), file notice suspended. (Page 6401.) |
| Aug 31, 2016 | Assembly Rule 63 suspended. |
| Aug 31, 2016 | From committee: That the Senate amendments be concurred in, but first be re-referred to Com. on APPR. (Ayes 5. Noes 3.) (August 30). Re-referred to Com. on APPR. |
| Aug 31, 2016 | From committee: That the Senate amendments be concurred in. (Ayes 16. Noes 0.) (August 31). |
| Aug 31, 2016 | Joint Rule 62(a), file notice suspended. |
| Aug 31, 2016 | Joint Rule 62(a), file notice suspended. (Page 6514.) |
| Aug 31, 2016 | Senate amendments concurred in. To Engrossing and Enrolling. |
| Sep 9, 2016 | Enrolled and presented to the Governor at 2:30 p.m. |
| Apr 28, 2016 | In Senate. Read first time. To Com. on RLS. for assignment. |
| Jan 8, 2016 | From printer. May be heard in committee February 7. |
| Feb 1, 2016 | Referred to Com. on BUDGET. |
| Apr 14, 2016 | From committee chair, with author's amendments: Amend, and re-refer to Com. on BUDGET. Read second time and amended. |
| Apr 18, 2016 | Re-referred to Com. on BUDGET. |
| Apr 25, 2016 | Assembly Rule 96 suspended. (Ayes 49. Noes 25. Page 4488.) |
| Apr 25, 2016 | Assembly Rule 96 suspended. (Ayes 49. Noes 25.) |
| Apr 25, 2016 | Ordered to third reading. |
| Apr 25, 2016 | Withdrawn from committee. |
| Jan 7, 2016 | Read first time. To print. |
| Apr 28, 2016 | Read third time. Passed. Ordered to the Senate. |
| Apr 28, 2016 | Read third time. Passed. Ordered to the Senate. (Ayes 51. Noes 26. Page 4588.) |
| Apr 28, 2016 | Read third time. Passed. Ordered to the Senate. (Ayes 51. Noes 26.) |
| May 5, 2016 | Referred to Com. on B. & F.R. |
| Aug 16, 2016 | Re-referred to Com. on RLS. |
| Aug 16, 2016 | Withdrawn from committee. |
| Aug 18, 2016 | From committee chair, with author's amendments: Amend, and re-refer to committee. Read second time, amended, and re-referred to Com. on RLS. |
| Aug 19, 2016 |
|
Date
|
Description
|
Location
|
Votes
|
|
|---|---|---|---|---|
| Aug 31, 2016 | AB 1637 LOW Concurrence in Senate Amendments | Assembly Floor |
Passed |
|
| Aug 31, 2016 | With recommendation: That Senate amendments be concurred in. | Assembly Standing Committee on Appropriations |
Passed |
|
| Aug 30, 2016 | With recommendation: That Senate amendments be concurred in, but first be re-referred to Com. on [Appropriations] | Assembly Standing Committee on Natural Resources |
Passed |
|
| Aug 22, 2016 | Assembly 3rd Reading AB1637 Low By Beall | Senate Floor |
Passed |
|
| Apr 28, 2016 | AB 1637 BUDGET Assembly Third Reading By TING | Assembly Floor |
Passed |
This list shows positions taken on this bill by organizations on the date displayed, which is linked to the original source.
Positions by individuals are not included.
|
Organization
|
Position
|
Date
|
|---|---|---|
| Adagen | * Against | Aug 31, 2016 |
| Advanced Energy Economy | ** Support | Aug 30, 2016 |
| Advanced Microgrid Solutions | ** Support | Aug 30, 2016 |
| Aidagen | * Against | Aug 30, 2016 |
| AMS | * Support | Aug 31, 2016 |
| Asian Pacific Environmental Network | ** Support | Aug 30, 2016 |
| Axiom Materials | ** Support | Aug 30, 2016 |
| Berkeley City College | ** Support | Aug 30, 2016 |
| Bloom Energy | * Support | Aug 30, 2016 |
| Brightline Defense Project | ** Support | Aug 30, 2016 |
| California Energy Storage Alliance | * Support | Aug 31, 2016 |
| California Energy Storage Association | * Support | Aug 30, 2016 |
| California Housing Partnership Corporation | ** Support | Aug 30, 2016 |
| California Manufacturers And Technology Association | * Against | Aug 30, 2016 |
| California Solar Energy Industries Association | ** Support | Aug 30, 2016 |
| Capstone Turbine Corporation | * Against | Aug 31, 2016 |
| Century Link | ** Support | Aug 30, 2016 |
| Clean Power Campaign | * Support | Aug 31, 2016 |
| College of Alameda | ** Support | Aug 30, 2016 |
| Core States Group | ** Support | Aug 30, 2016 |
| County of Santa Cruz | ** Support | Aug 30, 2016 |
| Cummins | ** Against | Aug 30, 2016 |
| DE Solutions | ** Against | Aug 30, 2016 |
| Doosan | ** Support | Aug 30, 2016 |
| Equinix | ** Support | Aug 30, 2016 |
| Etagen Inc. | ** Against | Aug 30, 2016 |
| Fuel Cell & Hydrogen Energy Association | ** Support | Aug 30, 2016 |
| Fuelcell Energy, Inc. | * Support | Aug 31, 2016 |
| Green Charge Networks | * Support | Aug 31, 2016 |
| GreenbergFarrow | ** Support | Aug 30, 2016 |
| I & D Consulting | ** Support | Aug 30, 2016 |
| Ice Energy | ** Support | Aug 30, 2016 |
| Inova Diagnostics | ** Support | Aug 30, 2016 |
| Jabil | ** Support | Aug 30, 2016 |
| Johnson Matthey Fuel Cells | ** Support | Aug 30, 2016 |
| Laney College | ** Support | Aug 30, 2016 |
| Lodi Unified School District | ** Support | Aug 30, 2016 |
| Merritt College | ** Support | Aug 30, 2016 |
| Monterey Peninsula Unified School District | ** Support | Aug 30, 2016 |
| NAT. RES. | ** Against | Aug 30, 2016 |
| National Fuel Cell Research Center | ** Support | Aug 30, 2016 |
| NLine Energy | * Support | Aug 30, 2016 |
| Oak Park Unified School District | * Support | Aug 30, 2016 |
| Primate Healthcare | ** Support | Aug 30, 2016 |
| School Energy Coalition | ** Support | Aug 30, 2016 |
| Sharp Laboratories of America | ** Support | Aug 30, 2016 |
| Sierra Club California | * Against | Aug 31, 2016 |
| Sierra Nevada | ** Support | Aug 30, 2016 |
| Silicon Valley Leadership Group | ** Support | Aug 30, 2016 |
| Solar City | * Support | Aug 31, 2016 |
| Solar Turbines | * Against | Aug 31, 2016 |
| Stand | * Support | Aug 30, 2016 |
| Stem Inc. | * Support | Aug 31, 2016 |
| SunPower Corporation | * Support | Aug 31, 2016 |
| Sunrun Inc. | * Support | Aug 31, 2016 |
| Technet | * Support | Aug 31, 2016 |
| Tecogen, Inc. | ** Against | Aug 30, 2016 |
| Tread Stone Technologies, Inc. | ** Support | Aug 30, 2016 |
| Walmart | * Support | Aug 30, 2016 |
| We O'Neil | ** Support | Aug 30, 2016 |
Date of Hearing: August 31, 2016
ASSEMBLY COMMITTEE ON APPROPRIATIONS
Lorena Gonzalez, Chair
ABPCA Bill Id:AB 1637
Author:(Low) – As Amended Ver:August 18, 2016
Policy Committee: | Natural Resources | Vote: | 5-3 |
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| ||
|
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Urgency: No State Mandated Local Program: No Reimbursable: No
SUMMARY:
This bill doubles the annual funding authorization for the Self-Generation Incentive Program (SGIP) and extends and revises the net energy metering program for fuel cells (NEMFC) for five years. Specifically, this bill:
- Doubles the funding authorized for SGIP for the program's remaining three years, which permits the Public Utilities Commission (PUC) to collect an additional $83 million per year from utility customers to fund payments to distributed energy resources (DER) until 2019 ($249 million total).
- Extends the NEMFC program for five years, including fuel cells that commence operation on or before December 31, 2021. Revises the NEMFC program as follows:
- Increases the individual project cap from one to five MW.
- Increases the statewide cap of 500MW by subtracting projects installed as of January 1, 2017 (approximately 76 MW).
- Requires eligible projects to comply with the Air Resources Board (ARB) distributed generation certification standards (establishing emission limits for oxides of nitrogen and other criteria pollutants).
- Requires ARB to establish and update greenhouse gas (GHG) standards applicable each year to assure that each eligible fuel cell reduces GHG emissions compared to the electrical grid. Fuel cells must continue to meet the applicable annual standard during operation to maintain eligibility for NEMFC.
FISCAL EFFECT:
- Up to $249 million in nonbypassable cost shifts among ratepayers to fund SGIP incentives.
- Potential unknown nonbypassable cost shifts among ratepayers to fund NEMFC.
Cost shifts for both programs may or may not be offset by electrical system benefits.
- Absorbable PUC administrative costs.
COMMENTS:
- Purpose. According to the author, continuing programs such as SGIP and NEMFC will help achieve the state's clean energy goals by reducing GHG emissions and supporting renewable energy integration and technological innovation.
- SGIP. The PUC is authorized to allow investor-owned electric utilities (IOUs) to collect up to $83 million per year, through 2019, from their customers through distribution rates to fund SGIP. Under SGIP, utilities provide ratepayer-funded incentives for eligible distributed energy resources (DER), including advanced energy storage and generation technologies that the PUC, in consultation with ARB, determines will achieve reductions in GHG emissions. Under a PUC decision adopted earlier this year, 75% of SGIP funds are allocated to storage technologies
- NEMFC. Each IOU is required, until January 1, 2017, to offer a NEM tariff for a customer who generates electricity using an onsite fuel cell electrical generating facility not greater than one MW until total installed fuel cell electrical generation resources reaches the IOU’s proportional share of 500 MW.
- Similar Legislation. AB 1530 (Levine) established a similar NEM tariff program for clean DER, however, this bill was technology neutral rather than focusing on fuel cells. This bill died in the Senate Environmental Quality Committee.
Analysis Prepared by: Jennifer Galehouse / APPR. / (916) 319-2081
(Without Reference to File)
CONCURRENCE IN SENATE AMENDMENTS
CSA2 Bill Id:AB 1637
Author:(Low)
As Amended Ver:August 18, 2016
Majority vote
ASSEMBLY: |
| (April 28, 2016) | SENATE: | 23-12 | (August 22, 2016) |
(vote not relevant)
COMMITTEE VOTE: | 5-3 | (August 30, 2016) | RECOMMENDATION: | concur |
(Nat. Res.)
COMMITTEE VOTE: | 16-0 | (August 31, 2016) | RECOMMENDATION: | concur |
(Appr.)
Original Committee Reference: NAT. RES.
SUMMARY: Doubles the annual funding authorization for the Self-Generation Incentive Program (SGIP), which permits the Public Utilities Commission (PUC) to collect an additional $83 million/year from utility customers to fund payments to distributed energy resources (DER) until 2019 ($249 million total).
Extends the net energy metering program for fuel cells (NEMFC) for five years, increases the individual project cap from one megawatt (MW) to five MW, increases the statewide cap of 500 MW by subtracting existing facilities, and updates emission standards applicable to each fuel cell participating in NEMFC.
The Senate amendments delete the Assembly version of the bill, and instead:
- Double the funding authorized for SGIP for the program's remaining three years.
- Extend the NEMFC program for five years, including fuel cells that commence operation on or before December 31, 2021.
- Increase the individual project cap from one to five MW.
- Increase the statewide cap of 500MW by subtracting projects installed as of January 1, 2017.
- Require eligible projects to comply with the Air Resources Board (ARB) distributed generation certification standards (establishing emission limits for oxides of nitrogen and other criteria pollutants).
- Require ARB to establish and update greenhouse gas (GHG) standards applicable each year to assure that each eligible fuel cell reduces GHG emissions compared to the electrical grid. Fuel cells must continue to meet the applicable annual standard during operation to maintain eligibility for NEMFC.
EXISTING LAW:
- Authorizes the PUC to authorize investor-owned electric utilities (IOUs) to collect up to $83 million per year from their customers through distribution rates through 2019 to fund SGIP. Under SGIP, utilities provide ratepayer-funded incentives for eligible DER, including advanced energy storage and generation technologies that the PUC, in consultation with ARB, determines will achieve reductions in GHG emissions. Under a PUC decision adopted earlier this year, 75% of SGIP funds are allocated to storage technologies.
- Requires each IOU, until January 1, 2017, to offer a NEM tariff for a customer who generates electricity using an onsite fuel cell electrical generating facility not greater than one MW until total installed fuel cell electrical generation resources reaches the IOU's proportional share of 500 MW.
FISCAL EFFECT: According to the Assembly Appropriations Committee, this bill has the following costs:
- Up to $249 million in nonbypassable cost shifts among ratepayers to fund SGIP incentives and potential unknown unbypassable cost shifts among ratepayers to fund NEMFC. Cost shifts for both programs may or may not be offset by electrical system benefits.
- Absorbable PUC administrative costs.
COMMENTS: For NEMFC, this bill establishes more stringent GHG standards to assure eligible projects remain cleaner than the grid each year of operation. The bill establishes a new GHG standard, established by ARB, rather than the existing PUC/SGIP standard, which is expected to be lower than the existing standard at the outset, and get progressively lower each year as the overall GHG emissions from the grid decrease due to implementation of a 50% Renewables Portfolio Standard, reduction of coal imports, and other factors. The bill's new GHG standard applies to existing installed fuel cells, as well as future installed fuel cells, requiring all NEMFC participants to meet annual GHG reduction standards, to be adopted by ARB, to remain eligible for NEMFC.
SGIP has been "reformed" pursuant to SB 861, a 2014 budget trailer bill. In 2015, the PUC adopted more stringent GHG standards required by SB 861, as follows:
- 350 kilograms (kg)/Megawatts per hour (MWh) (down from 379 kg/MWh, the prior standard) as the maximum level of CO2 emissions allowed for technologies participating in SGIP in 2016.
- Decreased GHG emission factors for each successive program year to reflect the increasing renewable energy targets imposed by SB 350 (De León), Chapter 547, Statutes of 2015, with a final GHG threshold of 337 kg/MWh in 2020.
In June 2016, the PUC adopted additional changes to the program, including the following:
- Beginning in 2017, generation projects must use 10% biogas – this escalates up to 100% by 2020.
- Storage is allocated 75% of funds (15% carved out for residential projects). Generating technologies are allocated the remaining 25% (40% carved out for renewable generation).
- A lottery will replace the first-come first-served system, with lottery done by budget category. Energy storage projects paired with renewables or located in an Aliso Canyon-affected area will be given priority in the lottery.
- A 20% developer cap replaces the previous 40% manufacturer cap.
As promising as these changes may be, they have yet to be fully implemented, much less evaluated. In addition, the recent round of SGIP funding (February 2016) was subject to allegations of "hacking" and misconduct on the part of an applicant who manipulated the online application process. Finally, some aspects of the program design, including the percentage allocation to storage and generation technologies and the developer cap, are based on the current level of funding. Doubling funding requires these elements of program design be reevaluated.
The lack of publicly-available in-use data on SGIP-funded projects makes determining their actual reliability and emissions performance difficult. Since emissions performance is essential to determine eligibility and measure the programs' performance, it is critical that each eligible customer report in-use emissions data to the PUC and ARB on a regular basis, and be subject to on-site inspection to verify equipment operations and performance, including capacity, thermal output, and usage, in order to verify criteria pollutant and GHG emissions performance. This bill lacks provisions to assure that each eligible customer has an obligation to report emissions data to ARB which was included in the language previously approved by this committee, which was later amended into AB 1530 (Levine) of the current legislative session.
Analysis Prepared by: Lawrence Lingbloom / NAT. RES. / (916) 319-2092 FN: 0005029
Date of Hearing: August 30, 2016
ASSEMBLY COMMITTEE ON NATURAL RESOURCES
Das Williams, Chair
ABPCA Bill Id:AB 1637 (
Author:Low) – As Amended Ver:August 18, 2016
SUBJECT: Energy: greenhouse gas reduction
SUMMARY: Doubles the annual funding authorization for the Self-Generation Incentive Program (SGIP), which permits the Public Utilities Commission (PUC) to collect an additional $83 million/year from utility customers to fund payments to distributed energy resources (DER) until 2019 ($249 million total).
Extends the net energy metering program for fuel cells (NEMFC) for five years, increases the individual project cap from one megawatt (MW) to five MW, increases the statewide cap of 500 MW by subtracting existing facilities, and updates emission standards applicable to each fuel cell participating in NEMFC.
Specifically, this bill:
- Doubles the funding authorized for SGIP for the program's remaining three years.
- Extends the NEMFC program for five years, including fuel cells that commence operation on or before December 31, 2021.
- Increases the individual project cap from one to five MW.
- Increases the statewide cap of 500MW by subtracting projects installed as of January 1, 2017.
- Requires eligible projects to comply with the Air Resources Board (ARB) distributed generation certification standards (establishing emission limits for oxides of nitrogen and other criteria pollutants).
- Requires ARB to establish and update greenhouse gas (GHG) standards applicable each year to assure that each eligible fuel cell reduces GHG emissions compared to the electrical grid. Fuel cells must continue to meet the applicable annual standard during operation to maintain eligibility for NEMFC.
EXISTING LAW:
- Authorizes the PUC to authorize investor-owned electric utilities (IOUs) to collect up to $83 million per year from their customers through distribution rates through 2019 to fund SGIP. Under SGIP, utilities provide ratepayer-funded incentives for eligible DER, including advanced energy storage and generation technologies that the PUC, in consultation with ARB, determines will achieve reductions in GHG emissions. Under a PUC decision adopted earlier this year, 75% of SGIP funds are allocated to storage technologies.
- Requires each IOU, until January 1, 2017, to offer a NEM tariff for a customer who generates electricity using an onsite fuel cell electrical generating facility not greater than one MW until total installed fuel cell electrical generation resources reaches the IOU’s proportional share of 500 MW.
FISCAL EFFECT: Unknown
COMMENTS:
- Author's statement:
In 2001, the Legislature created SGIP as a peak load reduction program in response to the energy crisis. Since then, the program has undergone several revisions and is now an essential market development tool for customer sited clean-energy technologies like energy storage and wind energy. The SGIP provides incentives for installation of distributed energy resources that are located at a customer’s site and sized no larger than what is needed to meet on-site energy needs. The SGIP program has been recently (in June of this year) reformed and will be much more effective and accountable to ratepayers. Most of the incentives under the SGIP program will now be provided to energy storage systems which are crucial to managing our integration of electric vehicles and clean energy into the power grid. AB 1637 would double the amount of money the PUC is authorized to require the IOUs to collect from ratepayers through program’s sunset in 2019.
In 2003, the Legislature created the NEMFC program out of recognition of the benefits associated with the increased deployment of advanced fuel cell technology for clean distributed energy generation. This existing policy is set to expire at the end of 2016. AB 1637 extends the 2016 sunset date for FC NEM by 5 years and expands the law to enable larger fuel cell projects to be installed at customer facilities while ensuring that stringent GHG reduction requirements are met.
Continuing policies such as SGIP and NEMFC help achieve the State’s ambitious clean energy goals by reducing GHG emissions and supporting renewable energy integration and technological innovation. The state’s continued investment in these technologies will complement the rest of the state’s suite of policies that drive clean energy investments, create jobs, and protect our environment.
- Each eligible fuel cell must reduce GHG emissions compared to electrical grid. For NEMFC, this bill establishes more stringent GHG standards to assure eligible projects remain cleaner than the grid each year of operation. The bill establishes a new GHG standard, established by ARB, rather than the existing PUC/SGIP standard, which is expected to be lower than the existing standard at the outset, and get progressively lower each year as the overall GHG emissions from the grid decrease due to implementation of a 50% Renewables Portfolio Standard, reduction of coal imports, and other factors. The bill's new GHG standard applies to existing installed fuel cells, as well as future installed fuel cells, requiring all NEMFC participants to meet annual GHG reduction standards, to be adopted by ARB, to remain eligible for NEMFC.
- Has SGIP been reformed enough to justify doubling its budget? As the author notes, SGIP has been "reformed" pursuant to SB 861, a 2014 budget trailer bill. In 2015, the PUC adopted more stringent GHG standards required by SB 861, as follows:
- 350 kilograms (kg)/Megawatts per hour (MWh) (down from 379 kg/MWh, the prior standard) as the maximum level of CO2 emissions allowed for technologies participating in SGIP in 2016.
- Decreased GHG emission factors for each successive program year to reflect the increasing renewable energy targets imposed by SB 350, with a final GHG threshold of 337 kg/MWh in 2020.
In June 2016, the PUC adopted additional changes to the program, including the following:
- Beginning in 2017, generation projects must use 10% biogas – this escalates up to 100% by 2020.
- Storage is allocated 75% of funds (15% carved out for residential projects). Generating technologies are allocated the remaining 25% (40% carved out for renewable generation).
- A lottery will replace the first-come first-served system, with lottery done by budget category. Energy storage projects paired with renewables or located in an Aliso Canyon-affected area will be given priority in the lottery.
- A 20% developer cap replaces the previous 40% manufacturer cap.
As promising as these changes may be, they have yet to be fully implemented, much less evaluated. In addition, the recent round of SGIP funding (February 2016) was subject to allegations of "hacking" and misconduct on the part of an applicant who manipulated the online application process. Finally, some aspects of the program design, including the percentage allocation to storage and generation technologies and the developer cap, are based on the current level of funding. Doubling funding requires these elements of program design be reevaluated.
- Greater data transparency is necessary for evaluation of SGIP and NEMFC emissions performance. The lack of publicly-available in-use data on SGIP-funded projects makes determining their actual reliability and emissions performance difficult. Since emissions performance is essential to determine eligibility and measure the programs' performance, it is critical that each eligible customer report in-use emissions data to the PUC and ARB on a regular basis, and be subject to on-site inspection to verify equipment operations and performance, including capacity, thermal output, and usage, in order to verify criteria pollutant and GHG emissions performance. This bill lacks provisions to assure that each eligible customer has an obligation to report emissions data to ARB which was included in the language previously approved by this committee, which was later amended into AB 1530 (Levine).
REGISTERED SUPPORT / OPPOSITION:
Support
Advanced Energy Economy
Advanced Microgrid Solutions
Asian Pacific Environmental Network
Axiom Materials
Berkeley City College
Bloom Energy
Brightline Defense Project
California Energy Storage Alliance
California Housing Partnership Corporation
California Solar Energy Industries Association
Century Link
Clean Power Campaign
College of Alameda
Core States Group
County of Santa Cruz
Doosan
Equinix
E2
Fuel Cell & Hydrogen Energy Association
Fuel Cell Energy
GreenbergFarrow
Green Charge Networks
I & D Consulting
Ice Energy
Inova Diagnostics
Jabil
Johnson Matthey Fuel Cells
Laney College
LG
Lodi Unified School District
Merritt College
Monterey Peninsula Unified School District
National Fuel Cell Research Center
NLine Energy
Oak Park Unified School District
Plug Power
Primate Healthcare
School Energy Coalition
Sharp Laboratories of America
Sierra Nevada
Silicon Valley Leadership Group
Solar City
Stem
Sunpower
Tech Net
Tread Stone Technologies, Inc.
We O’Neil
Opposition
Capstone Turbine Corporation
Caterpillar, Inc.
Cummins
DE Solutions
ETAGEN
Solar Turbines
Tecogen, Inc.
Analysis Prepared by: Lawrence Lingbloom / NAT. RES. / (916) 319-2092
CONCURRENCE IN SENATE AMENDMENTS
CSA1 Bill Id:AB 1637
Author:(Low)
As Amended Ver:August 18, 2016
Majority vote
ASSEMBLY: |
| (April 28, 2016) | SENATE: | 23-12 | (August 22, 2016) |
(vote not relevant)
Original Committee Reference: BUDGET
SUMMARY: Increases and extend subsidies on energy programs. Specifically, this bill:
- Doubles, from $80 million to $160 million annually, the amount of ratepayer subsidy paid to customers who install certain energy storage systems as part of the Self-Generation Incentive Program, ask known as SGIP. These subsidies are intended to increase in energy storage and to provide both customers and energy storage manufacturers with incentives to purchase and install the systems.
- Extends and expands the Net Energy Metering for Fuel Cells (NEM FC) program in the following ways:
- Extends the sunset from January 1, 2017, to December 31, 2021, for the NEM FC program;
- Increases the overall megawatt cap on the program from one megawatt to five megawatts;
- Increases the amount of megawatts eligible for ratepayer subsidy by 500 megawatts over capacity on January 1, 2017; and
- Requires the Public Utilities Commission to adopt annual greenhouse gas reduction standards for fuel cell electric generation by March 1, 2017.
The Senate amendments delete the previous contents of the bill and replaces it with the current language.
Analysis Prepared by: Christian Griffith / BUDGET / (916)319-2099 FN: 0004833
Office of Senate Floor Analyses (916) 651-1520 Fax: (916) 327-4478 | AB |
THIRD READING
Bill No: AB 1637
:
PRIOR VOTES NOT RELEVANT
DIGEST: This bill expands and extends the fuel-cell net energy metering program (FC NEM) and doubles the budget of the self-generation incentive program (SGIP).
- Establishes the California Public Utilities Commission (CPUC) and authorizes it to fix the rates of public utilities, such as investor-owned electric utilities (IOUs) that provide electricity service. (California Constitution Article 12)
- Establishes certain costs of IOUs to be recoverable on a nonbypassable basis. (Public Resources Code §366.1(d)(1) and Public Utilities Code §367 and §379)
- Makes certain exemptions to the requirement to pay nonbypassable charges (NBCs). (Public Utilities Code §374)
- Directs the CPUC to require each IOU to identify a separate nonbypassable rate component to collect the revenues to fund several public purpose programs – energy efficiency; public-interest research and development; and programs provided to low-income customers, such as targeted energy efficiency services and the California Alternative Rates for Energy (CARE) program. (Public Utilities Code §381)
Specific to net energy metering.
- Requires, generally, every electric utility to offer a NEM tariff to a customer-generator using an onsite renewable energy generation facility of no greater than one Megawatts (MW) until the total generating capacity used by eligible customer-generators exceeds five percent of the electric utility’s aggregate customer peak demand or until July 1, 2017, whichever is earlier. (Public Utilities Code §2827)
- Requires the CPUC, by December 31, 2015, to develop a successor program to the NEM program, which the IOUs must offer to customer-generators using an onsite renewable energy generation facility (Public Utilities Code §2827.1)
- Requires each IOU, until January 1, 2017, to offer a NEM tariff for a customer who generates electricity using an onsite fuel cell electrical generating facility not greater than one MW until total installed fuel cell electrical generation resources reaches the IOU’s proportional share of 500 MW. This is known as FC-NEM. (Public Utilities Code Section 2827.10)
- Requires each IOU, by July 1, 2015, to submit to the CPUC a distribution resources plan proposal to identify optimal locations for the deployment of distributed resources. (Public Utilities Code §769)
- Directs the Air Resources Board (ARB) to adopt a certification program and uniform emission standards for electrical generation technologies, such as distributed generation systems, that are exempt from local air district permitting requirements. (Health and Safety Code §41514.9)
Specific to the Self-Generation Incentive Program.
- States the intent of the Legislature that SGIP deployment of distributed generation and energy storage systems facilitate the integration of those resources into the electrical grid, improve efficiency and reliability of the distribution and transmission system, and reduce emissions of greenhouse gases (GHGs), peak demand, and ratepayer costs.
- Authorizes the CPUC to require the IOUs to collect funds, up to $83 million annually, from ratepayers, through December 31, 2019, to be used to provide incentives, under SGIP, for distributed energy resources the CPUC, in consultation with ARB, determines will achieve reductions in emissions of GHGs.
- Authorizes CPUC to set the amount of SGIP incentives and requires the CPUC to provide an additional incentive of 20 percent from existing program funds for the installation of eligible distributed generation resources manufactured in California.
- Requires the CPUC to ensure distributed energy resources in SGIP are made available to all ratepayers.
- Prohibits recovery of SGIP costs from customers who participate in the CARE program.
- Excludes solar technologies from eligibility for SGIP incentives and further limits eligibility to resources the CPUC determines to meet following criteria:
- Shifts onsite energy use to off-peak time periods or reduces demand from the grid by offsetting some or all of the customer’s onsite energy load, including, but not limited to, peak electric load.
- Is commercially available.
- Safely utilizes the existing transmission and distribution system.
- Improves air quality by reducing criteria air pollutants.
- Requires the CPUC, on or before July 1, 2015, to update the factor for avoided GHGs for distributed energy resources based on the most recent data available to the ARB for GHGs from electricity sales in the SGIP administrators’ service areas as well as current estimates of GHGs over the useful life of the distributed energy resource, including consideration of the effects of the California Renewables Portfolio Standard.
(Public Utilities Code §379.6)
This bill:
- Expands, from one MW to five MW, the size limit applicable to a fuel cell electrical generation resource eligible for the existing FC-NEM.
- Extends, from July 1, 2017, to December 31, 2021, the sunset on the existing FC-NEM program.
- Requires ARB, in consultation with the California Energy Commission (CEC), by March 31, 2017, and updated every three years thereafter, to establish an annual GHG emission reduction standard for a fuel cell electrical generation resource. The standard is to ensure each fuel cell electrical generation resource eligible for the FC-NEM program reduce GHG emissions compared to electrical grid resources, including renewable resources, that the fuel cell electrical generation resource displaces.
- Limits eligibility for the FC-NEM program to customers who use fuel cell technology that meets (a) ARB’s annual GHG emission reduction standard as described in the preceding paragraph and (b) ARB regulations for distributed generation authorized by existing law.
- Doubles, from $83 million to $160 million, the amount the CPUC is authorized to require to be collected annually for SGIP, through December 31, 2019.
Background
CPUC levies NBCs to recover costs shared by all IOU customers. To provide electric service to their customers, the IOUs face certain fixed costs and program costs. These costs include:
- Power purchase costs that occurred prior to energy deregulation in 1996.
- Bonds issued to finance a portion of the historic cost of power purchased by the Department of Water Resources (DWR) to serve electric customers.
- Electricity generation acquired prior to 2003, as well as the costs of all generation resources acquired by the utilities since they resumed procurement for their customers in 2003.
- Funds required for site restoration when the IOUs’ nuclear power plants are removed from service.
- Statutorily mandated low-income, energy efficiency and renewable generation programs.
Following the energy market crisis early in this century, some IOU customers were able to receive all, or a portion, of their electric service from a source other than the IOU. Generally, those alternative sources of electricity were either “Electric Service Providers” – a nonutility entity that provides electric service using the IOU’s transmission infrastructure – or an electric generation facility installed on the customer’s premises, the output to be used by the customer. This situation resulted in concerns over “cost shifting,” that is, the ability of customers who receive electricity service from a provider or source other than the IOU to avoid paying fixed and program costs for which all IOU customers had been responsible.
To avoid this cost shifting, the CPUC, acting according to statutory authority, has authorized the IOUs to recover certain fixed and program costs through a number of “nonbypassable” charges (NBCs), meaning charges that are paid by all customers in an IOU service territory, regardless of the source of a given customer’s electricity. The NBCs approved by the CPUC are:
- Ongoing Competition Transition Charge: Recovers the cost of qualifying facilities and power purchase agreements executed prior to 1996 that are in excess of a market benchmark determined by the CPUC.
- DWR Bond Charge: Recovers the cost of bonds issued to finance a portion of the historic cost of power purchased by DWR to serve electric customers.
- Power Charge Indifference Adjustment (PCIA): Either a charge or credit, intended to ensure that customers who purchase electricity from nonutility suppliers pay their share of cost for generation acquired prior to 2003, as well as costs of all generation resources acquired by the utilities since they resumed procurement for their customers in January of 2003.
- Nuclear Decommissioning Charge: Provides the funds required for site restoration when the IOU’s nuclear power plants are removed from service.
- Public Purpose Program Charge: The source of funds for low income, energy efficiency and renewable generation programs.
It is therefore well-established state policy to require all IOU customers, including customers who install onsite electric generation facilities, to pay IOU fixed and program costs through NBCs. But, no matter how well established the policy, there are exceptions, the state’s NEM programs among them.
NEM programs encourage installation of onsite electricity generation. NEM programs allow a customer who has installed an on-site electricity generation facility to receive a payment at a prearranged price for the electricity produced by the customer. California law has established two types of NEM programs, one for facilities that use technologies eligible for the state’s Renewable Procurement Standard (RPS) program, and another program for fuel-cell facilities.
The renewable NEM program (open to many technologies, though, in practice, mainly solar photovoltaic systems) offers a qualifying customer credit for electricity generated on-site equal to the rate that the customer would have paid for energy consumption, according to their otherwise applicable rate structure. In other words, the monthly NEM credit for excess electricity generated by onsite RPS-eligible technologies is equal to the retail rate of electricity, which includes the cost of generation, as well as a variety of other costs, such as fixed costs and NBCs.
In contrast, FC-NEM offers a less generous financial credit than does the renewable NEM program. Customers of FC-NEM receive for the electricity they produce the wholesale rate the IOU would have paid; that is, the cost only to generate the electricity, but not the fixed costs or NBCs. Perhaps this rate of compensation explains the lack of customer participation to date in the FC-NEM. (According to the CPUC, customers of the three largest IOUs have installed only 76MW of FC-NEM-eligible generation resources, out of a program cap of 500MW.)
Whether retail or wholesale, the rate of compensation for net-excess electricity supplied to the grid is likely a relatively minor financial inducement to the installation of onsite electricity generation. This is because the NEM programs require participating customers to size their onsite electricity generation facility to meet load. This requirement has the effect of limiting generation by a NEM customer that is exported to the grid for compensation.
Payments for electricity generation aside, NEM customers of all types receive another financial benefit: NEM customers do not pay NBCs on the electricity they generate onsite. For FC-NEM customers in particular, the value of this exemption from NBCs is likely greater than the value of the compensation they receive for electricity generation.
Of course, the costs represented in NBCs do not disappear simply because NEM participants do not pay them on the electricity they generate. Fixed costs must be paid; research and low-income customer support must be funded. To the extent these NBCs are not paid by NEM customers they must be paid by the IOU’s other customers who do not participate in a NEM program. This phenomenon is sometimes referred to as a “cost shift.”
So, why would the state establish programs that shift costs from one group of IOU customers to another? Proponents justify the cost shift by contending that the benefits of small distributed electricity generation facilities participating in the NEM programs outweigh the costs imposed on other customers. In theory, all distributed generation can benefit the electric system. Those benefits come in the form of reduced need for generation during peak periods of demand. In addition, distributed generation may provide locational benefits, such as relief of congestion or diminished need to build transmission, though CEC staff, while not denying the potential for such locational benefits, caution that distributed generation installed at some locations may add costs to the electric system and note that the CPUC is undertaking a proceeding to better identify and quantify the locational benefits of distributed generation.
In addition, NEM distributed generation can help to reduce the emission of traditional air pollutants and GHGs. This air quality benefit is easy to see with NEM customers using renewable technologies. Such technologies generally produce no or very few emissions, so the electricity generation they displace is almost certainly considerably dirtier than the electricity produced by the renewable technology.
The air quality benefits are less obvious when considering the electricity generation of FC-NEM customers. This is because fuel-cells use conventional natural gas to produce electricity through a chemical reaction. (A fuel-cell might use renewable biogas to produce electricity, thereby potentially qualifying it as an RPS-eligible renewable resource. However, a NEM customer using biogas in a fuel cell could participate in the relatively more-generous renewable NEM program.) However, the emissions profile of typical natural-gas-using fuel cell is substantially cleaner than the average emission profile of the electric grid, which includes a variety of generation resources, including new and old natural gas powerplants, coal-fired powerplants, nuclear power, hydroelectric power and an increasing amount of RPS-eligible renewable energy facilities.
This bill goes one better than the generic emissions profile described above. First, it requires that any fuel cell electricity generating facility must comply with ARB’s regulatory requirements for distributed generation facilities. Second, it requires a facility to meet or exceed the GHG emissions reduction standards established by ARB, pursuant to this bill. To establish that GHG emissions reduction standard, this bill directs ARB, in consultation with the CEC, to ensure a fuel cell electrical generation resource reduces GHGs compared to electrical grid resources, including renewable resources, that the fuel cell displaces, accounting for both procurement and operation of the electrical grid. ARB is to complete this work by March 31, 2017, and update the schedule every three years, with standards for each intervening year.
So, fuel cells in the FC-NEM program will be cleaner than the grid, and stay cleaner than the grid, which itself is getting cleaner by the year (or, by RPS compliance period, at least). The primary policy question for the Legislature, then, is whether the benefits of FC-NEM, which, absent legislative action would expire at year’s end, are sufficient to justify burdening other customers with the cost of IOU investments and public purpose programs.
It is difficult to estimate the magnitude of the cost shift this bill would create, though it is likely to be minimal for any given customer. A customer participating in FC-NEM would pay no NBCs on the electricity generated by the fuel cell electrical generating resources. Each of the NBCs is a fraction of a penny per kilowatt hour. (For example, the NBCs levied by PG&E on its customers range from $0.00049 for the Nuclear Decommissioning charge to $0.013 for the Public Purpose Program charge.) Yet, for a large individual customer, the NBCs may total a significant dollar amount. Escaping the NBCs, especially in concert with other subsidies provided by IOU customers, such as those given by the SGIP program, may prove a powerful incentive to customers considering installation of on-site fuel cell electrical generation resources.
Self-Generation Incentive Program.
The SGIP provides incentives for installation of distributed energy resources that are located at a customer's site and sized no larger than what is needed to meet on-site energy needs. Current law authorizes the CPUC to require the IOUs to collect $83 million per year from ratepayers through distribution rates through 2019 to fund SGIP and to administer the program through 2020. This bill would double the amount of money the CPUC is authorized to require the IOUs to collect from ratepayers, through 2019.
Recent legislation (SB 861, Committee on Budget and Fiscal Review, Chapter 35, Statutes of 2014 and AB 1478, Committee on Budget, Chapter 664, Statutes of 2014) extended the SGIP program by several years, corresponding to the dates in the preceding paragraph. In addition, the bills each directed the CPUC to modify the SGIP program in response to concerns with the program’s past performance. Recently, the CPUC adopted the program changes. (See CPUC decisions D.16-05-06-055 and D.15‑11‑027.) In short, the program changes refocused the program on energy storage, lowered the program GHG emissions threshold, and modified the monetary incentives so that incentive amounts decrease as distributed generation resources are installed. More specifically, the CPUC SGIP program changes as follows:
- Tighter GHG standard. Set 350 kilograms (kg)/Megawatts per hour (MWh) (down from 379 kg/MWh, the current standard) as the maximum level of CO2 emissions allowed for technologies participating in SGIP in year 2016.
- And increasingly tighter. Decreases the GHG threshold for each successive program year to reflect the increasing renewables targets imposed by SB 350, with a final GHG threshold of 337 kg/MWh in 2020.
- Biogas, and more biogas, a must. Beginning in 2017, generation projects must use 10 percent biogas – this escalates up to 100 percent by 2020.
- Mainly storage. Storage is allocated 75 percent of funds (15 percent carved out for residential projects). Generating technologies are allocated the remaining 25 percent (40 percent carved out for renewable generation).
- Different requirements for different sizes of storage. Large storage will address grid benefits through requirement to dispatch two hours a day, five days a week for six months of the year (260 hours); small storage only two hours a week for 12 months (104 hours).
- First-come is no longer first served. A lottery will replace first-come first-served system, with lottery done by budget category. Energy storage projects paired with renewables or located in an Aliso Canyon affected area will be given priority in the lottery.
- No one big winner. A 20-percent developer cap replaces the previous 40-percent manufacturer cap.
- Californian? Prove it. California supplier adder remains, but now requires third-party certification to show that 50 percent of value addition is done in California.
- Greater oversight of program administrators. Program administrators are directed to host quarterly meetings and undergo audits of their administrations and budgets.
In addition, program incentives will now be structured on a declining stair step, similar to incentives for the California Solar Initiative. The new SGIP incentive structure is shown below:
SGIP Incentives for Generation Technologies (25 percent of program budget) | ||||||||||
Step 1 | Step 2 | Step 3 | ||||||||
Max Rebate w/ biogas | Max Rebate w/ biogas | Max Rebate w/ biogas | ||||||||
Wind | $0.90 | n/a | $0.80 | n/a | $0.70 | n/a | ||||
Waste heat to power | $0.60 | n/a | $0.50 | n/a | $0.40 | n/a | ||||
Pressure reduction turbine | $0.60 | $1.20 | $0.50 | $1.10 | $0.40 | $1 | ||||
ICE CHP | $0.60 | $1.20 | $0.50 | $1.10 | $0.40 | $1 | ||||
Microturbine CHP | $0.60 | $1.20 | $0.50 | $1.10 | $0.40 | $1 | ||||
Microturbine | $0.60 | $1.20 | $0.50 | $1.10 | $0.40 | $1 | ||||
Gas turbine CHP | $0.60 | $1.20 | $0.50 | $1.10 | $0.40 | $1 | ||||
Fuel cell CHP | $0.60 | $1.20 | $0.50 | $1.10 | $0.40 | $1 | ||||
Fuel cell electric only | $0.60 | $1.20 | $0.50 | $1.10 | $0.40 | $1 | ||||
SGIP Incentives for Storage Technologies (75 percent of program budget) | ||||||||||
Large Scale - 10 kW | Step 1 | Step 2 | Step 3 | Step 4 | Step 5 | |||||
Without Investment Tax Credit (ITC) | $0.50/Wh | $0.45/Wh | $0.40/Wh | $0.35/Wh | $0.30/Wh | |||||
With ITC | $0.36/Wh | $0.31/Wh | $0.26/Wh | $0.21/Wh | $0.16/Wh | |||||
Small Scale - <10 kW | ||||||||||
Energy storage | $0.50/Wh | $0.45/Wh | $0.40/Wh | $0.35/Wh | $0.30/Wh | |||||
Prior/Related Legislation
AB 1530 (Levine, 2016) excuses from nonbypassable, otherwise levied against all electricity used by customers of an electrical corporation, the electricity used by customers who use certain onsite generation technologies to produce that electricity. The bill passed the Senate Committee on Energy, Utilities and Communications and is pending consideration in the Senate Committee on Environmental Quality.
SB 861 (Committee on Budget and Fiscal Review, Chapter 35, Statutes of 2014) extended SGIP annual collections of $83 million per year through December 31, 2019.
AB 1478 (Committee on Budget, Chapter 664, Statutes of 2014) modifies eligibility requirements for incentives under SGIP to clarify eligibility for technologies that shift electricity load off peak and make technical changes that clarify performance measures under the program.
AB 427 (Mullin, 2013) would have exempted bottoming cycle combined heat and power from NBCs. The bill failed to pass the Assembly Committee on Utilities and Commerce.
AB 365 (Mullin, 2013) was similar to AB 1530. The bill passed this committee on a vote of 7-2 but was held in Senate Committee on Appropriations.
AB 327 (Perea, Chapter 611, Statutes of 2013) required IOUs to submit plans for deploying distributed energy resources to the CPUC.
AB 2165 (Hill, Chapter 603, Statutes of 2012) raised the statewide and IOU-specific caps for FC-NEM.
AB 1150 (Pérez, Chapter 310, Statutes of 2011) extended SGIP funding through 2014, authorized CPUC to adjust incentive amounts, and added additional program interests, including ratepayer relief, energy efficiency, peak-load reduction, load management and environmental characteristics.
SB 412 (Kehoe, Chapter 182, Statutes of 2009) extended SGIP through 2015, defined eligible technologies as those the CPUC determined will reduce GHG emissions, set the annual program budget at $83 million, and added bonus incentive for California suppliers.
AB 970 (Ducheny, Chapter 329, Statutes of 2000) established the SGIP program in response to the energy crisis.
FISCAL EFFECT: Appropriation: Fiscal Com.: Local:
Unknown with recent amendments.
None received
OPPOSITION: (Verified 8/19/16)
None received
ASSEMBLY FLOOR: 51-26, 4/28/16
AYES: Alejo, Arambula, Atkins, Bloom, Bonilla, Bonta, Brown, Burke, Calderon, Campos, Chau, Chiu, Chu, Cooley, Cooper, Dababneh, Dodd, Eggman, Frazier, Cristina Garcia, Eduardo Garcia, Gatto, Gipson, Gomez, Gonzalez, Gordon, Gray, Roger Hernández, Holden, Irwin, Jones-Sawyer, Levine, Lopez, Low, McCarty, Medina, Mullin, Nazarian, O'Donnell, Quirk, Ridley-Thomas, Rodriguez, Salas, Santiago, Mark Stone, Thurmond, Ting, Weber, Williams, Wood, Rendon
NOES: Achadjian, Travis Allen, Baker, Bigelow, Brough, Chang, Chávez, Dahle, Beth Gaines, Gallagher, Grove, Harper, Jones, Kim, Lackey, Linder, Maienschein, Mayes, Melendez, Obernolte, Olsen, Patterson, Steinorth, Wagner, Waldron, Wilk
NO VOTE RECORDED: Daly, Hadley, Mathis
8/22/16 10:03:57
**** END ****
Discussed in Hearing
15MIN
Assembly Standing Committee on Appropriations
19MIN
Assembly Floor
21MIN
Assembly Standing Committee on Natural Resources
10MIN
Senate Floor
Bill Author
