BILL ANALYSIS Ó
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|SENATE RULES COMMITTEE | AB 1637|
|Office of Senate Floor Analyses | |
|(916) 651-1520 Fax: (916) | |
|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
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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.
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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
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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
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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:
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| SGIP Incentives for Generation Technologies |
| (25 percent of program budget) |
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|--------------+--------------+--------------+--------------+--------------+--------------+--------------|
| | 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 |
|--------------+--------------+--------------+--------------+--------------+--------------+--------------|
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|Fuel cell | $0.60 | $1.20 | $0.50 | $1.10 | $0.40 | $1 |
|electric only | | | | | | |
|--------------+--------------+--------------+--------------+--------------+--------------+--------------|
| | | | | | | |
--------------------------------------------------------------------------------------------------------
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| SGIP Incentives for Storage Technologies |
| (75 percent of program budget) |
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|Large Scale - 10 kW | Step 1 | Step 2 | Step 3 | Step 4 | Step 5 |
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|Without Investment Tax |$0.50/Wh|$0.45/Wh|$0.40/Wh|$0.35/Wh|$0.30/Wh|
| Credit (ITC)| | | | | |
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| With ITC|$0.36/Wh|$0.31/Wh|$0.26/Wh|$0.21/Wh|$0.16/Wh|
| | | | | | |
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|Small Scale - <10 kW | | | | | |
|-----------------------+--------+--------+--------+--------+--------|
| Energy storage |$0.50/Wh|$0.45/Wh|$0.40/Wh|$0.35/Wh|$0.30/Wh|
| | | | | | |
| | | | | | |
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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)
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Page 14
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.
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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
AB 1637
Page 16
8/22/16 10:03:57
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