BILL ANALYSIS Ó
SENATE COMMITTEE ON ENVIRONMENTAL QUALITY
Senator Wieckowski, Chair
2015 - 2016 Regular
Bill No: AB 1530
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|Author: |Levine and Gordon |
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|Version: |4/26/2016 |Hearing |6/29/2016 |
| | |Date: | |
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|Urgency: |No |Fiscal: |Yes |
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|Consultant:|Rebecca Newhouse |
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SUBJECT: Electricity: distributed generation.
ANALYSIS:
Existing law:
1) Establishes certain costs to be recovered from customers of
investor-owned utilities (IOUs) on a nonbypassable basis, such
as public purpose programs including rate assistance for
low-income customers, energy efficiency, and the Electric
Program Investment Charges (EPIC), bond repayments, and nuclear
decommission costs.
2) Provides incentives for self-generation. (Public Utilities
Code §379.6)
3) Requires retail sellers of electricity to increase purchases of
renewable energy such that at least 50% of retail sales are
procured from renewable energy resources by December 31, 2030.
(PUC §399.11 et seq.)
4) Requires each IOU, by July 1, 2015, to submit to the California
Public Utilities Commission (CPUC) a distribution resources
plan proposal to identify optimal locations for the deployment
of distributed resources. (PUC §769)
5) Directs the California 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
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permitting requirements. (Health and Safety Code §41514.9)
This bill:
1) Establishes the category "clean distributed energy resource"
(clean DER) to mean a facility of 15 megawatts (MW) or less,
located on a customer's premises that generates electricity, or
electricity and useful heat, and sized to meet the customer's
onsite demand, and that meets, for each year of eligibility,
one of the following criteria:
a) A greenhouse gas (GHG) emissions standard equivalent to,
or less than, 379 kilograms of CO2 equivalents per
megawatt-hour (kgCO2e/MWh) and complies with oxides of
nitrogen (NOx), carbon monoxide, and volatile organic
compound emissions standards adopted by ARB, as specified.
b) Is a renewable energy resource under the RPS and will not
otherwise be addressed in the CPUC's implementation of the
distributed resource planning process or revision of the
rules regarding net energy metering.
2) Directs CPUC to require the three largest IOUs to:
a) Collect nonbypassable charges from any customer served by
clean DER based only on the actual metered consumption of
electricity delivered to the customer through the IOU's
transmission or distribution grid, and prohibits shifting of
costs to customers in a different customer class.
b) Adjust reserve capacity for standby service for clean DER
customers, as specified.
3) Requires CPUC to suspend the eligibility of new customers to
receive the above rate program on December 31, 2020.
4) Requires the California Energy Resources Conservation and
Development Commission (CEC), in consultation with the CPUC, to
report on impacts of these provisions in the integrated energy
policy report filed on or before November 1, 2017, and November
1, 2019.
Background
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1) Nonbypassable charges. Nonbypassable charges are fees that all
customers pay to recover fixed charges or program costs of the
IOU. CPUC, pursuant to statute, authorizes IOUs to recover
certain fixed program costs from charges that are paid by all
customers in an IOU service territory, regardless of the source
of a given customer's electricity. The largest component of
nonbypassable charges affected is the public purpose program
charge, which includes the California Alternative Rates for
Energy program (CARE), which funds state-mandated low-income
assistance, energy efficiency programs, and the electric
program investment charge (EPIC), that funds energy
technologies and research. Smaller components are the
Department of Water Resources (DWR) bond charges, which
recovers the cost of bonds issued to finance power purchased by
DWR during the energy crisis, and nuclear decommissioning,
which provides for the funds required for site restoration when
the nuclear power plants are removed from service. These
charges are volumetric, meaning they are based on the amount of
electricity used by the customer, usually expressed in dollar
per kilowatt-hour ($/KWh).
Exemptions. Generally, a customer or customer group may be
granted an exemption from nonbypassable charges when the IOU
did not incur costs related to the particular category of
nonbypassable charge on behalf of that customer or customer
group.
Some customer generation is exempt from nonbypassable charges
through existing programs designed to encourage certain
customer behavior, such as adoption of renewable technology.
For example, customers who participate in the net
energy-metering program (NEM) pay electric utility
nonbypassable charges only on the electricity they receive from
the grid. The NEM program allows a customer who installs small
solar, wind, biogas and fuel cell generation facilities (up to
1MW) that serve all or a portion of onsite generation needs, to
receive a financial credit for power generated by their onsite
system and fed back to the utility. The credit is used to
offset the customer's electricity bill. NEM eligibility (and
therefore exemption from nonbypassable charges) for fuel cells
using fossil natural gas expires at the end of this year.
2) Distributed generation. Distributed Generation (DG) generally
refers to smaller-scale electricity generation on-site or
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generation located closer to population centers or other high
demand areas. DG can be produced with renewable or
non-renewable fuel sources; examples include small wind
turbines, rooftop solar, internal combustion engines, gas
turbines and fuel cells.
Traditional methods of electric generation and supply relies on
centralized electricity production from a few large-scale
generating stations located far from load centers, and
distributing that electricity through an extensive transmission
and distribution network. Systems based on DG employ numerous,
small plants and can provide power onsite with little reliance
on the distribution and transmission grid.
Renewable DG receives several types of incentives. In addition
to bill credits for net electricity exported to the grid, NEM
customers are exempt from nonbypassable charges, as noted
above, and standby charges, costs associated with
interconnection application fees, studies and distribution
upgrades.
DG also receives incentive payments through the California
Solar Initiative (limited to solar photovoltaic DG) and the
Self-Generation Incentive Program (SGIP).
Self-Generation Incentive Program. SGIP was authorized by the
legislature in 2000, and established by the CPUC in 2001 to
reduce peak demand in response to the energy crisis. The
program was modified by SB 412 (Kehoe, Chapter 182, Statutes of
2009) to include reduction of GHG emissions as a focus of the
program, in addition to other goals of the program, including
improving efficiency and reliability of the distribution and
transmission system, and reducing peak demand and ratepayer
costs. SB 412 directed the CPUC, in consultation with ARB, to
identify distributed energy resources that contribute to
greenhouse gas reduction goals and to set appropriate incentive
levels to encourage their adoption. Pursuant to SB 412, CPUC
set the GHG emissions level for eligible DG in 2011 at or below
379 kgCO2e/MWh. This value was based on the AB 32 Scoping Plan
estimate of the average emissions of natural gas
fired-electricity generation from 2002 to 2004 and adjusted
downward by CPUC by 20% to account for the RPS (which has since
increased to a 33% renewable energy procurement requirement by
2020, and a 50% procurement mandate by 2050), and adjusted for
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avoided line losses.
DG technologies provided incentives under SGIP include
renewable technologies, such as wind and biogas-fueled
generation, and non-renewable, natural gas-fueled electricity
generation, including combined heat and power (CHP) fuel cells,
electric-only fuel cells, gas turbines, internal combustion
engines, and microturbines. CHP refers to the production of
electricity and heat from a single fuel source and increases
efficiencies of systems that run on natural gas by capturing
waste heat for conversion of useful thermal energy.
SB 861 (Budget and Fiscal Review Committee, Chapter 35,
Statutes of 2014) extended SGIP until 2021 and required CPUC to
update, by July 2015, the GHG emissions factor for avoided GHG
emissions based on ARB's most recent data on GHG emissions from
electricity sales in IOU service areas and estimates of GHG
emissions over the useful life of the distributed generation
technology.
In November of 2015, CPUC lowered the GHG emissions ceiling for
DG eligible for SGIP incentives to a 10-year average emissions
rate of 350 kgCO2e/MWh.
Since the start of the program, about $3.7 billion has been
allocated for incentive payments to renewable and non-renewable
DG. This year, over $77 million is authorized for SGIP
incentives to eligible DG resources.
3) Emissions impacts of distributed generation. The electricity
sector and environmental impacts of DG are dependent on where
the distributed generation is deployed in relation to the
distribution system, how the technology operates (e.g.,
intermittent or baseload resource) and, for non-renewable
technologies, the efficiency, type of fuel, and emissions
specifications of DG compared to the characteristics of the
electricity the distributed generation is displacing. As all
these factors may vary greatly, estimating potential
environmental impacts and benefits of this type of electrical
generation is not a straightforward analysis.
For the SGIP program, CPUC contracts with a third-party
consulting firm, Itron, to perform annual impact evaluations of
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the program to quantify the energy, demand, and environmental
impacts. The report calculates emission impacts of the
technologies under SGIP as the difference between the emissions
generated by SGIP systems and baseline emissions that would
have occurred in the absence of the program.
The April 2015 Itron Report assessed SGIP impacts from the
beginning of the program until 2013, and found that after 2011
(at which point GHG emissions reductions became a goal of the
program), there was a shift from a net increase in GHG
emissions from non-renewable DG under the program, to a
marginal net reduction in net GHG emissions in 2012, and
increased GHG emissions reductions in 2013 (a GHG emissions
reduction of 12,000 metric tons CO2e/MWh). These non-renewable
SGIP projects include CHP fuel cells, electric-only fuel cells,
gas turbines, internal combustion engines, and microturbines,
operating on natural gas.
For comparison, renewable SGIP resources (wind and
biogas-fueled DG) in 2013 were estimated to result in net GHG
reductions of 150,000 metric tons of CO2e/MWh (3.5 times more
GHG emission reductions than the non-renewable SGIP projects).
As expected, GHG emissions reductions vary substantially for
different non-renewable distributed generation technologies.
According to the report (which assigns a net GHG emissions
reductions a negative "GHG impact" score), "CHP fuel cells and
gas turbines have a higher emissions rate than the electrical
power plants that they avoid...but are able to overcome this
deficit by recovering useful heat for heating... and
cooling...services. The result is a negative emissions
impact...relative to the conventional energy services baseline.
Electric-only fuel cells do not recover useful heat but have a
lower emissions rate than the electric power plants they
avoid.... Internal combustion engines and microturbines had
high emissions rates and did not recover sufficient useful heat
to achieve negative GHG impacts."
Criteria air pollutant reductions. Like GHG emissions,
criteria air pollutant emissions are proportional to the amount
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of fuel consumed for a specific technology. Depending on the
type of technology, criteria air pollutant emissions from DG
can vary greatly. For example, diesel generators (not included
under SGIP or this bill) are one of the dirtier forms of
distributed generation and have some of the most significant
emissions of toxic and criteria air pollutants compared to
other types of electricity generation. In contrast, fuel
cells, which do not use a combustion process, have one of the
lowest emissions levels of NOx and PM10 emissions for
non-renewable electrical generation.
According to the April 2015 Impact Evaluation report, for
non-renewable SGIP distributed generation, "All technologies
supplied with non-renewable fuel decreased NOx and PM10
emissions. SO2 emissions from technologies supplied with
non-renewable fuel were marginal. These results indicate that
non- renewable SGIP technologies with high electrical
efficiencies and low air pollutant emissions (e.g., fuel cells)
generate fewer emissions than the conventional energy services
baseline. In addition, SGIP technologies with lower electrical
efficiencies but which recovered useful waste heat reduce
criteria air pollutants overall."
The report also notes, "The 2013 impacts evaluation marks the
first attempt at quantifying the NOx, PM10, and SO2 impacts of
the SGIP. While the analysis methodology presented here is
sound, there is room for improvement. Emissions data from the
California Air Resources Board and local air quality municipal
districts should be leveraged to obtain more accurate estimates
of emissions rates from distributed energy resources and
boilers."
4) Local air district permitting and ARB certification. Air
permitting requirements for DG vary throughout California due
to regional differences in air quality and also depend on the
type of DG technology. Air districts in regions designated as
non-attainment under the federal and state Clean Air Acts may
require distributed generation projects to install
best-available control technology and to offset their emission
of criteria pollutants. However, local air districts do not
require air permits for DG that does not emit air pollution or
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whose emissions are below air district permitting thresholds,
which vary depending on the air district.
To address regulatory gaps in local air district permitting of
DG, SB 1298 (Bowen and Peace, Chapter 741, Statutes of 2000)
directed ARB to develop an air pollution control certification
program for distributed generation technologies that are exempt
from local air permitting requirements by January 2003 and
requires that those standards reflect the best performance
achieved in practice by existing electrical generation
technologies. The current regulation, amended in 2006,
requires all DG running on fossil fuel to meet emissions
standards for NOx, carbon monoxide, and volatile organic
compounds (VOCs). The NOx standard is set at 0.07 lbs/MWh,
approximately equivalent to a NOx emissions factor for a new,
central-station baseload natural gas powerplant.
Comments
1) Purpose of Bill. According to the author, "Clean onsite
distributed energy resources allow for cleaner, lower cost,
more reliable energy generation. On-site distributed generation
technologies offer a clean energy choice that provides air
quality benefits by reducing emissions of high criteria air
pollutants and greenhouse gases. Clean DG reduces the need for
energy generation that emits higher levels of greenhouse gases
that contribute to climate change and higher levels of criteria
air pollutants that contribute to smog formation. These
technologies are primed to help California reach its clean
energy goals. They are part of the solution, and are ready to
be deployed now to meet the state's growing demand while
providing critical environmental, economic and social
benefits."
2) Emissions impacts of non-renewable distributed generation. The
environmental benefits of DG depend on a variety of factors,
including technology, fuel type, as well as where and when the
technology is dispatched. For zero-emission distributed
generation, the analysis of GHG emissions and criteria air
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pollutant benefits is more straightforward. For the most part,
any grid electricity displaced by these resources results in
avoided GHG emissions and criteria air pollutants.
For non-renewable DG, the emissions impact depends on the
emissions rate of the technology, and the type of generation
the DG is displacing. In the short-term, this analysis of
avoided GHG emissions looks at avoided resources on the margin
that would have otherwise needed to operate to meet electricity
needs. According to the CPUC, this short-term "operating
margin effect" for displaced energy is likely some fraction of
existing combined cycle natural gas power plants (with an
average emissions factor of 382 kgCO2e/MWh) and simple cycle
combustion turbines (also known as peaker plants, with average
emissions of 544 kgCO2/MWh ).
In the long-term, the emissions impact of distributed
generation would depend on the avoided resources that would
otherwise need to be built to meet electricity needs. In
general, due to the RPS requirement, these avoided resources
will likely be some increasing fraction of renewable resources
as well as newer, more efficient natural gas generation.
Because of various scenarios, and the different types of
non-renewable technologies, there is uncertainty in terms of
the extent of avoided emissions with non-renewable DG.
Although the average emissions intensity of the electrical grid
is not necessarily representative of the energy displaced by
distributed generation, it is notable that PG&E and Southern
California Edison have grid emissions intensities of 179 and
259 kgCO2e/MWh-both significantly lower than the emissions
limit in AB 1530 (379 kgCO2e/MWh).
3) Static GHG emissions standard based on outdated assumptions.
AB 1530 defines distributed generation at or below a GHG
emissions intensity of 379 kgCO2e/MWh as a "clean distributed
energy resource" and exempts this type of generation from
nonbypassable charges. According to the CPUC, the original
SGIP standard of 379 kgCO2e/MWh established in 2011was based on
average natural gas power plant emissions from 2002 to 2004 and
adjusted downward by 20% to account for the RPS. The average
power plants emissions data used to generate the emissions
factor that currently establishes eligibility for clean DER in
this bill is now over a decade old, and does not reflect the
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lower emission rate of newer, more modern gas-fired generation.
Additionally, by 2014, the three largest IOUs had all procured
over 20% of their RPS requirement (with San Diego Gas &
Electric over 36%). As this standard is not based on current
data, it appears to be somewhat arbitrary, and therefore does
not ensure qualifying distributed generation is "clean."
Additionally, although the bill sunsets eligibility for new DG
to qualify for nonbypassable charge exemption under this bill,
DG meeting the definition of clean DER and installed before
December 31, 2020 (unless the sunset is extended or repealed),
will be exempt from paying the nonbypassable charges for the
entire useful life of the technology, which could be 10 to 20
years from now. At that point, the grid will likely be
substantially cleaner. However, under this bill incentives will
continue to be provided to what will effectively look like
dirty generation relative to a grid made up of 50% or greater
renewable energy resources.
4) More than a reauthorization. Proponents of AB 1530 argue that
the bill extends the "no use, no fee" policy that NEM
customers, including fuel cells using natural gas, qualify for.
Under the NEM tariff, DG customers only pay nonbypassable
charges on electricity they receive from an IOU. NEM was
recently extended for renewable DG (without the 1MW cap), but
the eligibility for fossil natural gas fuel cell distributed
generation sunsets at the end of this year. However, there are
several notable differences between AB 1530 and a
reauthorization of the nonbypassable charges exemption.
Whereas the NEM policy limits non-renewable customer
participation to natural gas fuel cells (until the end of
2016), under AB 1530, fuel cells, as well as other
non-renewable DG technologies including gas turbines, internal
combustion engines, and microturbines, may qualify.
Additionally, the exemption from nonbypassable charges would
apply for generation up to fifteen times the current
eligibility limit for NEM fuel cell customers. This is a
significant expansion (1MW can power 600 to 700 homes, whereas
15MW can power around 10,000 homes).
5) RPS. Under the RPS, load-serving entities, including IOUs, are
required to meet 50% of their load from renewable energy
resources by December 31, 2030. Customer generation, itself
exempt from RPS requirements, decreases the load of the
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load-serving entity, and ultimately reduces the renewable
resource generation IOUs need to procure to meet the 50% RPS
requirement. To the extent the exemption from nonbypassable
charges results in a large number of customers that install
clean DER at or near the 15MW limit, the corresponding
reduction in electrical load may significantly reduce renewable
energy procurement by IOUs.
6) Commitments to natural gas. This bill captures both renewable
and non-renewable "clean distributed energy resources," but
because renewable distributed generation can take advantage of
other, potentially more generous incentives, the primary
beneficiaries of this bill would be non-renewable technologies
using fossil natural gas.
Methane (CH4) is the principal component of natural gas.
Methane is 84 times more powerful as a global warming pollutant
than CO2 on a 20-year time scale. Atmospheric methane
concentrations have been increasing as a result of human
activities related to agriculture, fossil fuel extraction and
distribution, and waste generation and processing.
A growing body of evidence suggests that national and state
estimates of methane emissions from the natural gas sector have
been significantly underestimated. Studies suggest that U.S.
methane emissions from all sources are likely anywhere from 25
to 75% higher than EPA estimates, and they note the discrepancy
may in large part be due to a small number of very large leaks
from the natural gas production and distribution system.
Additionally, several recent analyses of atmospheric
measurements in state suggest that actual California methane
emissions may be 30 to 70% higher than estimated in ARB's
emission inventory. The Short-Lived Climate Pollutant draft
strategy notes that several efforts are underway at the CEC and
ARB to improve emissions monitoring to help identify sources of
fugitive methane emissions and reduce them, including from oil
and gas operations. Although the state has worked to reduce
fugitive methane emissions from various sources over recent
years, including new efforts to reduce fugitive leaks from
natural gas infrastructure in the state, 91% of the natural gas
used in California is imported.
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Providing incentives for distributed technologies requiring
long-term natural gas contracts, although potentially more
efficient than centralized natural gas powerplants, may run
contrary to the RPS, and other policies, that are working to
decarbonize the state's electricity sector and meet ambitious
climate goals.
7) Amendment. As the bill was originally amended to address the
issue of clean DER and nonbypassable charges at the end of last
year, the dates in the bill determining the applicability of
the nonbypassable and standby charge requirements in the bill
for new clean DER customers should be pushed out a year. For
example, the bill currently appears to operate retroactively,
with the new nonbypassable and standby charge requirements of
this bill applying to clean DER installed after January 1,
2016.
Related/Prior Legislation
AB 674 (Mullin, 2015) contained similar provisions to AB 1530. AB
674 was held on the Assembly Appropriations suspense file.
AB 2441 (Mullin, 2014) was similar to AB 1530. The bill was held
in the Senate Rules Committee.
AB 2649 (Mullin, 2014) was similar to AB 1530, but was amended to
a different subject matter and held on the Senate Appropriations
Committee Suspense file.
AB 365 (Mullin, 2013) contained similar provisions to AB 1530. The
bill was held in the Senate Rules Committee.
DOUBLE REFERRAL:
This measure was heard in Senate Energy, Utilities and
Communications Committee on April 19, 2016, and passed out of
committee with a vote of 6-4.
SOURCE: TechNet
SUPPORT:
Association of California Water Agencies
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Bloom Energy
Capstone
Caterpiller
DE Solutions
Doosan Fuel Cell America
EtaGen
LG
National Fuel Cell Research Center
NLine Energy, Inc.
Sierra Nevada Brewing Company
Silicon Valley Leadership Group
Solar Turbines
Tecogen
OPPOSITION:
California State Association of Electrical Workers
California State Pipe Trades Council
California Manufacturers and Technology Association
Coalition of California Utility Employees
Natural Resources Defense Council
Pacific Gas and Electric Company
San Diego Gas and Electric Company
San Francisco Public Utilities Commission
Sierra Club California
Southern California Edison
The Utility Reform Network
Western States Council of Sheet Metal Workers
ARGUMENTS IN
SUPPORT: Supporters state that AB 1530 extends existing
state law that expires at the end of this year that protects
customers from having to
pay utility fees assessed on clean energy generated onsite by the
customer.
Supporters note that without AB 1530, customers who choose to
invest their own
capital to install clean, onsite electricity generation
technologies will have to pay a
number of utility-imposed fees on electricity they generate and
consume on-site.
They add that these charges would create an economic disincentive
for customers
to deploy new, innovative and clean technologies that will benefit
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all Californians.
Supporters also state that on-site distributed generation
technologies offer a clean
energy choice that provides air quality benefits by reducing
emissions of high
criteria air pollutants and GHGs, and that clean DG reduces the
need for energy
generation that emits higher levels of GHGs that contribute to
climate change and
smog formation.
ARGUMENTS IN
OPPOSITION: Opponents say that AB 1530 creates
exemptions from nonbypassable charges, including those established
to ensure
customers pay their fair share for public purpose programs such as
low-income
ratepayer assistance, and energy efficiency, for customers who
install non-
renewable, fossil fuel self-generation. The opponents argue that
these exemptions
would result in an unfair cost shift from participating customers
to non
-participating customers. Southern California Edison states the
reliability,
infrastructure, and other ratepayer benefits purposed by the
bill's proponents are
questionable, and even if actualized, have no nexus to the
exemptions being
sought. The California State Association of Electrical Workers,
Coalition of
California Utility Employees, California State Pipe Trades Council
and Western
States Council of Sheet Metal Workers also argue that AB 1530 not
only conflicts
with the state's energy policy of the last 15 years, which has
been focused on
reducing reliance on fossil fuels, but is directly contrary to the
50% RPS
requirement and SB 350 (de León). The Natural Resources Defense
Council opposes the bill, unless the bill is amended to reinstate
a prior provision of the bill which required the emissions
threshold to ratchet down over time, pursuant to the appropriate
determination by the ARB.
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