BILL ANALYSIS                                                                                                                                                                                                    Ó






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          |SENATE RULES COMMITTEE            |                       AB 1637|
          |Office of Senate Floor Analyses   |                              |
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          |327-4478                          |                              |
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                                   THIRD READING 


          Bill No:  AB 1637
          Author:   Low (D) 
          Amended:  8/18/16 in Senate
          Vote:     21 

           PRIOR VOTES NOT RELEVANT

           SUBJECT:   Energy:  greenhouse gas reduction


          SOURCE:    Author

          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).


          ANALYSIS:  


          Existing law:


           1) 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) 


           2) 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)








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           3) Makes certain exemptions to the requirement to pay  
             nonbypassable charges (NBCs).  (Public Utilities Code §374)


           4) 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. 


           5) 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)


           6) 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)


           7) 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) 


           8) Requires each IOU, by July 1, 2015, to submit to the CPUC a  
             distribution resources plan proposal to identify optimal  







                                                                    AB 1637  
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             locations for the deployment of distributed resources.   
             (Public Utilities Code §769)


           9) 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.


           10)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. 


           11)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.


           12)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.


           13)Requires the CPUC to ensure distributed energy resources in  
             SGIP are made available to all ratepayers.


           14)Prohibits recovery of SGIP costs from customers who  
             participate in the CARE program.









                                                                    AB 1637  
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           15)Excludes solar technologies from eligibility for SGIP  
             incentives and further limits eligibility to resources the  
             CPUC determines to meet following criteria:


              a)    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.
              b)    Is commercially available.
              c)    Safely utilizes the existing transmission and  
                distribution system. 
              d)    Improves air quality by reducing criteria air  
                pollutants.


           16)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:


           1) Expands, from one MW to five MW, the size limit applicable  
             to a fuel cell electrical generation resource eligible for  
             the existing FC-NEM.


           2) Extends, from July 1, 2017, to December 31, 2021, the sunset  
             on the existing FC-NEM program.


           3) 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  







                                                                    AB 1637  
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             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.


           4) 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.


           5) 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  







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          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. 









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          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  







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          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  







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          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  







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          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  







                                                                    AB 1637  
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          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.







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           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   |              |Max Rebate w/ |              |Max Rebate w/ |
          |              |              |  w/ biogas   |              |   biogas     |              |   biogas     |
          |--------------+--------------+--------------+--------------+--------------+--------------+--------------|
          |Wind          |    $0.90     |     n/a      |    $0.80     |     n/a      |    $0.70     |     n/a      |
          |--------------+--------------+--------------+--------------+--------------+--------------+--------------|
          |Waste heat to |    $0.60     |     n/a      |    $0.50     |     n/a      |    $0.40     |     n/a      |
          |power         |              |              |              |              |              |              |
          |--------------+--------------+--------------+--------------+--------------+--------------+--------------|
          |Pressure      |    $0.60     |    $1.20     |    $0.50     |    $1.10     |    $0.40     |      $1      |
          |reduction     |              |              |              |              |              |              |
          |turbine       |              |              |              |              |              |              |
          |--------------+--------------+--------------+--------------+--------------+--------------+--------------|
          |ICE CHP       |    $0.60     |    $1.20     |    $0.50     |    $1.10     |    $0.40     |      $1      |
          |--------------+--------------+--------------+--------------+--------------+--------------+--------------|
          |Microturbine  |    $0.60     |    $1.20     |    $0.50     |    $1.10     |    $0.40     |      $1      |
          |CHP           |              |              |              |              |              |              |
          |--------------+--------------+--------------+--------------+--------------+--------------+--------------|
          |Microturbine  |    $0.60     |    $1.20     |    $0.50     |    $1.10     |    $0.40     |      $1      |
          |--------------+--------------+--------------+--------------+--------------+--------------+--------------|
          |Gas turbine   |    $0.60     |    $1.20     |    $0.50     |    $1.10     |    $0.40     |      $1      |
          |CHP           |              |              |              |              |              |              |
          |--------------+--------------+--------------+--------------+--------------+--------------+--------------|
          |Fuel cell CHP |    $0.60     |    $1.20     |    $0.50     |    $1.10     |    $0.40     |      $1      |
          |--------------+--------------+--------------+--------------+--------------+--------------+--------------|







                                                                    AB 1637  
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          |Fuel cell     |    $0.60     |    $1.20     |    $0.50     |    $1.10     |    $0.40     |   $1         |
          |electric only |              |              |              |              |              |              |
          |--------------+--------------+--------------+--------------+--------------+--------------+--------------|
          |              |              |              |              |              |              |              |
           -------------------------------------------------------------------------------------------------------- 
           ------------------------------------------------------------------- 
          |             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 |$0.50/Wh|$0.45/Wh|$0.40/Wh|$0.35/Wh|$0.30/Wh|
          |           Credit (ITC)|        |        |        |        |        |
           -------------------------------------------------------------------- 
          |               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)  







                                                                    AB 1637  
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          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.










                                                                    AB 1637  
                                                                    Page  15



          FISCAL EFFECT:   Appropriation:    No          Fiscal  
          Com.:YesLocal:   No


          Unknown with recent amendments.


          SUPPORT:   (Verified  8/19/16)




          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

          Prepared by:Jay Dickenson / E., U., & C. / (916) 651-4107







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          8/22/16 10:03:57


                                   ****  END  ****