BILL ANALYSIS Ó
AB 1499
Page 1
Date of Hearing: May 1, 2014
ASSEMBLY COMMITTEE ON NATURAL RESOURCES
Wesley Chesbro, Chair
AB 1499 (Skinner) - As Amended: April 21, 2014
SUBJECT : Self-generation incentive program
SUMMARY : Extends funding and administration of the
Self-Generation Incentive Program (SGIP) for three years,
authorizing the Public Utilities Commission (PUC) to collect
$249 million more from utility customers to fund payments to
customer-owned distributed energy resource (DER) projects and
related expenses until 2019 pursuant to SGIP.
EXISTING LAW :
1)Authorizes the PUC to authorize investor-owned electric
utilities to collect up to $83 million per year from their
customers through distribution rates through 2014 to fund
SGIP.
2)Requires SGIP to be administered until 2016. Under the SGIP,
utilities provide ratepayer-funded rebates for eligible DER,
including wind, advanced energy storage, and natural gas or
renewable gas fuel cells and combined heat and power (CHP)
combustion projects.
3)Requires the PUC to administer a separate program for solar
technologies pursuant to the California Solar Initiative
(CSI).
4)Provides that eligibility is limited to DER that the PUC, in
consultation with the Air Resources Board (ARB), determines
will achieve reductions in greenhouse gas (GHG) emissions.
5)Requires fossil fuel combustion projects to meet specified
emission and efficiency standards.
6)Requires the PUC to ensure that distributed generation (DG)
resources are made available for all ratepayers.
7)Requires the PUC to provide a 20 percent higher payment for
installation of DG projects from a "California supplier,"
which is defined as any business entity that manufactures
AB 1499
Page 2
eligible DG resources in California and that meets either of
the following criteria:
a) The owners or policymaking officers are domiciled in
California and the permanent principal office, or place
of business from which the supplier's trade is directed
or managed, is located in California.
b) A state-licensed business that owns and operates a
manufacturing facility located in California that builds
or manufactures eligible DG resources, and employs
California residents, for five years prior to providing
eligible DG resources to a SGIP recipient.
8)Prohibits recovery of SGIP costs from customers participating
in the California Alternate Rates for Energy program, a
utility discount for low-income customers.
9)States the intent of the Legislature that SGIP increase
deployment of DG 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 GHG emissions, peak demand,
and ratepayer costs.
10)States the intent of the Legislature that the PUC provide for
an equitable distribution of the costs and benefits of the
program.
THIS BILL extends the PUC's authority to require collection of
funds to support SGIP through 2017 and requires SGIP to be
administered until 2019.
FISCAL EFFECT : $249 million through 2017 from utility
customers. Approximately seven percent of SGIP funds are
budgeted for administration by program administrators and the
PUC.
COMMENTS :
1)Author's statement .
Under current law, SGIP expires on December 31, 2014. With
continued authorization, SGIP seeks to help California meet
our goals for clean air, reduced GHG emissions, reduced
AB 1499
Page 3
electricity demand, and enhance markets for preferred
resources. SGIP is also the only incentive program for
energy storage projects, which play a critical role in
reducing the need for "peaker plants," increasing the
stability and reliability of our electrical system, and
delivering and integrating renewable energy resources.
2)SGIP history . On August 31, 2000, the final day of the
1999-2000 Legislative Session, AB 970 (Ducheny) was gutted and
amended. The bill included a variety of provisions quickly
cobbled together in an effort to respond to the emerging
energy crisis in San Diego, where San Diego Gas and Electric
was the first utility to expose its customers to unfrozen
rates under California's ill-fated experiment with electric
industry restructuring. Because the crisis was misunderstood
at the time to be the result of a physical supply shortage, AB
970's primary focus was to increase electric generation
supply, and most of the bill's provisions were related to
expediting the siting of power plants.
Buried on page 20 of the 22-page bill was a single sentence
requiring the PUC to adopt "(d)ifferential incentives for
renewable or super clean distributed generation resources"
within 180 days of the effective date of the bill. Aside from
the objective to "reduce demand for electricity and reduce
load during peak demand periods," no further definitions or
instructions were included in AB 970. The bill required the
"reasonable costs" of the PUC's action to be included in the
distribution revenue requirement of PUC-regulated utilities.
This provision was not even mentioned in the Senate or
Assembly bill analyses.
Pursuant to this provision of AB 970, the PUC established the
SGIP in 2001, offering customer rebates for renewable and
"super clean" DG. SGIP has been extended and/or modified by
at least six bills since then. Over the last 13 years, the
SGIP has offered rebates for installation of solar, wind, fuel
cell, and certain renewable and fossil fuel combustion
projects meeting specified emissions and efficiency standards.
In 2006, AB 2778 (Lieber) extended SGIP for wind and fuel
cells until 2012, but excluded combustion projects. In 2009,
SB 412 (Kehoe) extended SGIP collection through 2011, modified
eligibility to include fossil fuel projects that reduce GHG
AB 1499
Page 4
emissions, and required the PUC to administer the program
until 2016 (the additional time was allotted to spend a $200+
million surplus accumulated from prior years).
In response to a December 22, 2010 request from SGIP
administrators, the program was suspended by a PUC ruling
issued February 10, 2011, which froze applications received on
or after January 1, 2011. The reason for the suspension was
that a rush of awards and applications, mostly from a single
vendor (Bloom Energy), had nearly exhausted both the current
budget and the accumulated surplus, leaving less funding than
expected for future awards under SB 412. Later in 2011, the
PUC adopted a decision implementing SB 412 and reinstated the
program. At the same time, the PUC made "advanced energy
storage" (e.g., battery) systems eligible for SGIP incentives.
Notwithstanding the issues with the program and the SB 412
agreement to cap funding and sunset SGIP in 2016, in 2011 AB
1150 (V. Manuel Pérez) allowed the PUC to fund SGIP for an
additional three years. Under AB 1150, the PUC may authorize
the utilities to collect up to $83 million per year from their
customers through December 31, 2014. However, AB 1150
maintained the January 1, 2016 sunset on the program, at which
time the PUC must provide repayment of all unallocated funds
to reduce ratepayer costs.
3)Recent SGIP evaluation . The most recent evaluation of SGIP,
"2012 SGIP Impact Evaluation and Program Outlook," was
prepared by Itron under contract and published by the PUC on
February 7, 2014. Among the report's key findings are:
SGIP spent an average of $311 per metric ton of GHG
reductions through 2012.
Ratepayers paid $33 million in incentives for $7 million
in benefits (avoided costs) in 2012.
Of the completed SGIP projects, excluding photovoltaic
(PV) projects:
o 52 percent of the project capacity remains
operational.
o 8 percent of the project capacity has been
decommissioned.
o 14 percent of the project capacity is offline.
o 26 percent of the project capacity has unknown
status.
Assuming build-out of the queue of pending SGIP projects
AB 1499
Page 5
and continuation of the current program guidelines and
rules, GHG emission reductions and peak demand reductions
will grow.
There is insufficient independent information to
quantify market transformation impacts.
1)SGIP objectives and performance . According to the PUC, the
four goals of SGIP are:
Reduce peak demand
Reduce GHG emissions
Promote system reliability
Contribute to market transformation of DER
As the committee considers extending SGIP, members may wish to
consider how the program is performing with respect to the
four PUC goals, whether these four goals are the right goals,
and what adjustments may be necessary if the committee
determines that a further commitment of funds to the program
is justified.
Reduce peak demand:
According to the SGIP evaluation report, in 2012, ratepayers
paid $33 million in incentives for $7 million in benefits,
known as avoided costs. Since the report, the PUC provided
the committee with the following additional information
regarding peak demand performance since SB 412 was
implemented:
There is not currently adequate data available to
accurately calculate or predict peak demand savings for
projects funded and in the queue since D.11-09-015. The
current lack of data can be attributed to two factors:
a) There are simply too few systems installed
since D.11-09-015 that have been operating long enough
to provide a sufficient data set to accurately report
or predict peak demand savings.
b) There are currently data transfer issues
between the SGIP database administrator and the
program administrators. The database administrator is
in the process of adjusting the database so that it
may receive all data for all projects. As the
AB 1499
Page 6
database administrator and the PAs were not
anticipating the need to analyze this data until June
2014, the database infrastructure to receive certain
data necessary for this analysis is not in place at
this time.
The PUC reports that the data transfer issue will be resolved,
and additional data will be available later this year.
Reduce GHG emissions:
As a GHG reduction measure, SGIP would appear to fail the
cost-effectiveness test. Many of the projects funded have not
produced emission reductions. Of the projects that do produce
emission reductions, some only achieve reductions based on a
debatable analysis of their actual impact. In most cases, the
reductions have come at a very high cost - an average of $311
per metric ton for projects funded prior to the 2011 PUC
decision implementing SB 412 and $232/ton for projects funded
since SB 412 implementation. At the top of the range are
electric-only natural gas fuel cells, which have also received
the bulk of SGIP funds, at an average cost of $1,040/ton prior
to SB 412 implementation and $1,743/ton since SB 412
implementation.
For comparison, here are costs per metric ton provided by ARB
for measures adopted pursuant to AB 32:
a) Offset credit: $8-8.46 (prices on Intercontinental
Exchange Spot Market).
b) Allowance: $11.48 (price for 2014 vintage allowance
at February 2014 auction).
c) Low-carbon fuel standard credit: $48.
d) 33 percent Renewables Portfolio Standard (RPS):
$24.
e) Energy efficiency: -$109.
f) Refrigerant management: -$2.
The funds now dedicated to SGIP could achieve far greater GHG
reductions if spent on efficiency or any number of other
measures, or focused on DER projects with high GHG reduction
potential, such as the conversion of open dairy lagoons to
methane-capturing digester/generation projects.
Promote system reliability:
AB 1499
Page 7
Actual reliability of installed projects is largely unknown,
but survey information suggests that a large percentage of
SGIP-funded projects are either no longer operating or are
operating at less than their installed capacity. A PUC
investigation on CHP performance in 2010 found that CHP
projects experienced increased time spent not operating,
reductions in output when operating, and decreases in
electrical efficiency and thermal heat recovery over time.
The investigation further found that unexpected levels of
maintenance and economic complexity have dampened participant
satisfaction. It is unclear whether the current reliability
of SGIP projects are the same, better, or worse than what was
reported in 2010. The 2012 SGIP evaluation report could not
find operational information on 26 percent of the projects and
another 22 percent of the projects either were decommissioned
or offline.
Contribute to market transformation of DER:
Although "market transformation" is not mentioned in the SGIP
statute, much less defined, the PUC states that it is one of
the four principal goals of the program. In practice, market
transformation seems to be the unmeasurable X factor to
support the claim that SGIP benefits justify its costs to
ratepayers.
In the case of electric-only natural gas fuel cells, the PUC
reports that average cost has remained at an average of
$11/watt since 2004, and actually increased to $12/watt in
2011 and 2012, which suggests that SGIP has not contributed to
cost reductions:
1)Additional objectives .
Reduce ratepayer costs:
Although it is not among the four goals outlined by the PUC,
reducing ratepayer costs is in fact an explicit objective in
the statute [Section 379.6(a)(1) of the Public Utilities
Code]. It seems self-evident that the program has not
decreased ratepayer costs.
Information provided in the SGIP evaluation report indicates
that projects are located where vendors and customers want
AB 1499
Page 8
them, which is not necessarily where they could provide
ratepayer benefits, i.e., where there is high peak demand
coincident with the project's ability to reduce the sites need
for electricity from the grid, relieve transmission
congestion, or other ratepayer benefits.
According to information provided by the PUC, SGIP projects
are not required to schedule their operations. This means
that for purposes of reliability or grid management, grid
operators don't know whether the customer's load will be
relying on the SGIP project or the grid. This means that
ratepayers must pay for reserves to be available in the event
that unscheduled demand occurs.
Improve air quality:
Like GHGs, criteria pollutant emission performance appears
inconsistent and current data is not readily available.
According to a 2008 California Energy Commission report,
"(SGIP) installations have net emissions of air quality
pollutants including (volatile organic compounds), (oxides of
nitrogen/NOx) and (carbon monoxide)."
The report showed small increases in emissions for
non-renewable micro-turbines and gas turbines, and significant
increases in emissions for internal combustion engines. The
combined increases in GHG emissions attributable to
non-renewable combustion cogeneration projects offset all of
the GHG benefits achieved by PV funded by SGIP prior to the
CSI. In contrast, projects using renewable fuels, including
combustion, showed emissions benefits across the board.
In general, new DG turbines appear somewhat less efficient
than recently-built central-station power plants in terms of
direct electrical efficiency. However, DG in CHP
installations, where waste heat is recovered and put to use in
a way that saves natural gas, overall efficiency improves
significantly. Actual efficiency varies widely by system.
The best systems can achieve efficiencies between 80 and 90
percent. Minimum efficiency required for SGIP eligibility is
60 percent [total energy output (electricity plus heat)
divided by fuel input].
The NOx emission limit in the statute (0.07 lbs/MWhr)
approaches NOx emission levels achieved by new central-station
AB 1499
Page 9
power plants, although the central-station plants also must
obtain offsets from other stationary sources to mitigate the
NOx they do emit. However, this 0.07 NOx limit is based on
emission standards adopted by ARB more than 10 years ago and
the limit was placed in the SGIP statute in 2003 as an
incentive for early compliance with the ARB standards. More
than 10 years later, ARB's 2007 limit is now in effect, so
this provision reflects the standard for DG subject to ARB
certification, rather than a step forward.
1)GHG factor that determines SGIP eligibility is outdated .
Pursuant to SB 412, SGIP eligibility is limited to DER that
the PUC, in consultation with ARB, determines will reduce GHG
emissions. In its 2011 decision implementing SB 412, the PUC
used an estimate for avoided grid emissions to determine
eligibility. Essentially, the PUC used a figure from ARB for
average statewide emissions for existing natural gas power
plants, deducted 20 percent to account for the RPS (which has
since been increased to 33 percent), and added 7.8 percent to
adjust for avoided line losses.
The data and assumptions that the PUC used were outdated in
2011 and they are growing more and more outdated every day.
The natural gas plant data that the PUC used is now over 10
years old and more recent data is readily available from ARB
and U.S. EPA. In addition, using a statewide average doesn't
provide an accurate baseline because SGIP is not available in
many areas of the state served by publicly-owned utilities and
GHG emissions vary between utilities. Finally, GHG emissions
from the grid will continue to decline over the useful life of
SGIP projects as the natural gas fleet becomes more efficient
and renewable energy increases to meet the 33 percent RPS and
beyond. The result is that SGIP is funding projects now and,
if not corrected as part of an extension of the program, will
fund projects in the future that do not meet the statutory
requirement to reduce GHG emissions.
To address the need to update SGIP's GHG factor, the author
and the committee may wish to consider amending the bill to
require the PUC, on or before July 1, 2015, to update the
factor for avoided GHG emissions based on the most recent data
available to ARB for emissions from electricity sales in the
program administrators' service areas, as well as current
estimates of GHG emissions over the useful life of the DER,
including consideration of the effects of the RPS.
AB 1499
Page 10
2)Considering amount and cost of GHG emission reductions would
improve value of SGIP expenditures . When SGIP funds very
expensive technologies with minimal or no GHG benefits, the
result is extremely small and high-cost GHG reductions, as
evidenced by the data provided by SGIP evaluator Itron and
summarized in Comment 4 above. Though these technologies may
meet other SGIP objectives that justify their eligibility,
spending the majority of SGIP funds on technologies that
deliver minimal benefits at high cost is not a good value for
ratepayers when other DER technologies may deliver greater
benefits. To enable the PUC to address this going forward,
the author and the committee may wish to consider amending the
bill to require the PUC to consider relative amount and cost
of GHG emission reductions when allocating program funds
between eligible technologies.
3)Greater data transparency would improve evaluation of SGIP
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 a critical components of eligibility
and measuring the program's objectives, as well as explicit in
the "performance measures" added by this bill, the author and
the committee may wish to consider requiring recipients of
incentive funds to provide data to the PUC and ARB upon
request, 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.
4)California supplier bonus may be missing the mark . In 2008,
AB 2267 (Fuentes) added the "California supplier" provision to
the SGIP statute, requiring SGIP to provide a 20 percent bonus
on top of approved incentives to "California suppliers," as
defined. According to the PUC, since AB 2267 was enacted,
SGIP has provided $52 million to 14 companies registered as
"California suppliers." Bloom Energy has received nearly $39
million, or approximately 75 percent of the funds.
It's worth noting that the "California supplier" provision
does not clearly require the actual products receiving SGIP
funds to be manufactured in California, and the PUC and
program administrators don't check. So the provision appears
to support the perverse result that a company based in
AB 1499
Page 11
California can collect a bonus for expanding its manufacturing
out of state, while a company based outside California that
would like to manufacture in California must wait for five
years before it's eligible for the bonus.
To address this, the author and the committee may wish to
consider amending the bill to require eligible products to be
manufactured in California to receive the "California
supplier" bonus and eliminating the five-year waiting period
as a barrier to potential new manufacturers.
5)Related legislation . AB 1624 (Gordon), pending in this
committee, extends SGIP funding authorization for seven years,
requiring the PUC to allocate up to $83 million per year
through 2021 from utility allowance revenues, and requiring
the PUC to reduce annual funding by 10 percent in each of the
last four years (2018-2021), for a total authorization up to
$506 million.
6)Author's amendments . The author proposes to add the following
provisions, which are similar to provisions added to AB 1624
on April 21:
a) Clarify that eligible DER technologies must:
be capable of reducing demand from the grid by
offsetting onsite energy load, including peak demand;
be commercially available; safely utilizes the
existing transmission and distribution system; reduce
GHG emissions, and; improve air quality by reducing
criteria air pollutants.
b) Require the PUC to determine a capacity factor
for DG and energy storage systems.
c) Requires the PUC to evaluate SGIP based on
specified performance measures: GHG emission
reductions; criteria pollutant emission reductions
measured in terms of avoided emissions and emissions
credits secured for project approval; energy
reductions measured in energy value; reductions of
aggregate non-coincident customer peak demand;
capacity factor; value of avoided transmission and
distribution costs, and; ability to improve onsite
electricity reliability as compared to onsite
electricity reliability before the SGIP technology was
AB 1499
Page 12
placed in service.
d) Require the PUC to evaluate both of the
following:
i. The program's progress toward
reducing barriers to the adoption of DER,
including, but not limited to, interconnection
costs and the length of time to complete
interconnection.
ii. The program's effectiveness in
providing frequency regulation, voltage support,
demand reduction, peak shaving, ramp rate
control, and other wholesale ancillary and grid
reliability services.
REGISTERED SUPPORT / OPPOSITION :
Support
AT&T
Advanced Energy Economy
American Vanadium
Association of California Water Agencies
Bergey Wind Power
Bioenergy Association of California
Bloom Energy
California Association of Sanitation Agencies
California Energy Storage Alliance
California Manufacturers & Technology Association
California State University
Capstone Turbine Corporation
ClearEdge Power
CODA Energy
Direct Access Customer Coalition
EDF Renewable Development,
EnerVault
Environmental Defense Fund
EtaGen
EV Grid
Facebook
Fuel Cell and Hydrogen Energy Association
Fuel Cell Energy
Green Charge Networks
AB 1499
Page 13
Inland Empire Utilities Agency
LightSail Energy
OutBack Power Technologies
Parker Hannifin Corporation Global Energy Grid Tie Division
Powertree Services
Primus Power
Providence Health & Services
Rosendin Electric
SEEO
Sierra Club California
SolarCity
Solar Energy Industries Association
Stem
TechNet
West County Wastewater District
Yahoo!
Opposition
The Utility Reform Network (TURN)
Analysis Prepared by : Lawrence Lingbloom / NAT. RES. / (916)
319-2092