BILL ANALYSIS Ó
AB 674
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Date of Hearing: April 27, 2015
ASSEMBLY COMMITTEE ON NATURAL RESOURCES
Das Williams, Chair
AB 674
(Mullin) - As Amended April 16, 2015
SUBJECT: Electricity: distributed generation
SUMMARY: Exempts customer load served by "clean distributed
energy resources," as defined, from nonbypassable charges
imposed on investor-owned utility (IOU) customers, which fund
public purpose programs (including low-income assistance and
energy efficiency), energy crisis contracts, and nuclear
decommissioning costs.
EXISTING LAW:
1)Requires every investor-owned utility (IOU) customer to pay
nonbypassable system benefits charges to fund programs
including rate assistance for low-income customers, energy
efficiency, and the Electric Program Investment Charge (EPIC).
Those charges also include the costs of bond repayments from
the energy crisis and nuclear decommissioning costs.
2)Requires each IOU, not later than July 1, 2015, to submit to
the Public Utilities Commission (PUC) a distribution resources
plan proposal to identify optimal locations for the deployment
of distributed resources, including renewable generation
resources, energy efficiency, energy storage, electric
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vehicles, and demand response technologies.
3)Requires the PUC to develop a standard contract or tariff,
which may include net energy metering (NEM), for eligible
customer-generators with a renewable electrical generation
facility that is a customer of a large IOU no later than
December 31, 2015. NEM is generally limited to 1 megawatt
(MW).
THIS BILL:
1)Defines "clean distributed energy resource" as a generation
facility located on the customer site, up to 20 MW, sized to
meet the customer's electrical demand, and that either:
a) Uses non-renewable fuel (e.g., natural gas) and
produces emissions of greenhouse gases (GHG) less than
levels specified by the PUC for eligibility in the Self
Generation Incentive Program and produces de minimis
emissions of oxides of nitrogen (NOx) and sulfur oxides
(SOx).
b) Is an eligible renewable energy resource pursuant to
the Renewables Portfolio Standard (RPS) that will not
otherwise be addressed in the PUC's implementation of a
distribution resources plan or net energy metering.
2)Requires the PUC, to the extent authorized by federal law and
by July 1, 2016, to require electrical corporations to modify
rate plans for those customers served by clean distributed
energy resources installed after January 1, 2016:
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a) Nonbypassable charges are based on actual metered
consumption of electricity delivered to the customer
through the electrical corporation's transmission or
distribution system. All other charges are to be
assessed at the same rate as other customers who do not
use clean distributed energy resources.
b) Initial reservation capacity based on a minimum of
12 months of the clean distributed energy resource
generation technology's historical operation, the number,
size, and outage diversity of the clean distributed
energy resource, and the annual average reduction of
customer load that could occur during an outage.
c) Electrical corporations are allowed to:
i. Adjust customer standby demand charges
after an initial 12-month period to reflect the
customer's actual standby demand, averaged over the
previous 12 months.
ii. Modify the reservation capacity once
every 12 months to reflect the customer's actual
average annual reservation capacity based on the
same criteria used to establish the initial
reservation capacity.
d) Calculation of actual average annual reservation
capacity excludes the customer's electrical demand served
by the electrical corporation within 24 hours following
an outage of the clean distributed energy resource
resulting from any event on the electrical corporation's
transmission or distribution grid that is outside of the
customer's control that requires the customer to reduce
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onsite generation.
3)Requires the California Energy Commission (CEC) to provide a
report to the Legislature on the impacts of these provisions,
including the impacts on avoided transmission and distribution
costs, avoided energy losses, wholesale electricity market
prices, electricity costs to ratepayers, air quality,
emissions of greenhouse gases, job creation, energy
reliability, and the extent to which the incentives contribute
to achieving the state's distributed generation and combined
heat and power goals.
FISCAL EFFECT: Unknown
COMMENTS:
1)Background. IOUs are required to collect nonbypassable
charges to fund common system benefits and costs. The largest
component of the charges affected by this bill is the public
purpose program charge, which funds state-mandated low-income
assistance, energy efficiency programs, and EPIC, which funds
energy technologies and research. Smaller components are the
Department of Water Resources (DWR) bond charge, 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 IOUs' nuclear power plants are removed from service.
Some customer generation is exempt from nonbypassable charges
through existing programs, depending on the install date,
technology, and size. For example, solar projects eligible
for NEM pay nonbypassable charges only on net consumption,
though NEM is only applicable up to 1 MW in most cases. There
is no such existing exemption for the renewable and
non-renewable projects up to 20MW included in this bill.
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2)Purpose of the bill. According to the author:
California is a leader in clean energy policy, with ambitious
goals to improve air quality, efficiency, reliability, and the
economy. Clean onsite distributed generation of electricity
("DG") is valuable as an alternative to traditional centralized
power plants. With California's energy demand expected to
double by 2050, deployment of distributed generation
technologies is an important piece of meeting the State's
energy, climate, and public health goals.
Unfortunately, customers who choose to invest their own capital
to install clean DG technologies must pay a number of
utility-imposed fees on the electricity they generate and
consume onsite. These charges are equivalent to accessing an
additional 75 to 100% sales tax on clean DG equipment. The fees
make the installation of clean DG prohibitively expensive and
economically infeasible for residential, commercial, and
industrial customers in California.
This bill would require customers with clean onsite generation
technologies to pay all applicable utility imposed fees based
only on electricity purchased from the grid. They will continue
to pay standby charges for transmission, distribution, and grid
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maintenance, and they will continue to pay commodity costs for
the electricity they use. This policy will enable more
customers to invest their own capital to purchase clean, onsite
electricity generation technologies that improve air quality,
reduce energy costs for ratepayers, improve energy reliability,
and reduce California's reliance on centralized, fossil-fueled
power plants.
The primary effect of this bill is to give similar benefits as
NEM to projects that may not be eligible for NEM, such as very
large and/or gas-fueled projects. Installation of distributed
generation may provide system benefits, including emission
benefits, but this is highly variable and dependent on
location, technology, and in-use performance. Customer
generation is exempt from the RPS, reduces IOUs' RPS
procurement, and displaces grid sources, which vary in their
emissions rates between the IOUs, but are increasingly low
carbon over time due to RPS and other policies. To the extent
this bill supports customers making long-term commitments to
natural gas, the author and the committee may wish to consider
whether that is consistent with the state's long term climate
and energy goals.
3)GHG standard does not assure significant GHG benefits. This
bill requires non-renewable technologies to produce GHG
emissions less than the emission factor set by the PUC for
purposes of eligibility for the Self Generation Incentive
Program (SGIP). The PUC set the SGIP GHG emission factor in
2011 using 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% to account for the RPS (which has since
been increased to 33%, with pending bills to increase to 50%),
and added 7.8% to adjust for avoided line losses. The
resulting emissions rate (379 kilograms per megawatthour) is
comparable, though in some cases higher, than recently
permitted combined-cycle natural gas power plants.
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The data and assumptions that the PUC used were outdated in
2011 and they have grown more outdated since. The natural gas
plant data that the PUC used is now over 10 years old and more
recent data is 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 distributed
generation projects as the natural gas fleet becomes more
efficient and renewable energy increases to meet the 33% RPS
and beyond.
Last year, when the Legislature extended SGIP through 2020, it
directed the PUC to update the GHG emissions factor by July 1,
2015, based on the most recent data available to ARB for GHG
emissions for each IOU as well as current estimates of GHG
emissions over the useful life of the distributed energy
resource, including consideration of the effects of the RPS.
The purpose of this update is to account for newer,
IOU-specific data on GHG emissions and compare emissions of a
project over its useful life to the emissions of the IOU where
the project is located.
Because the updated SGIP GHG emission factor is unknown at
this time and is applicable only to projects installed in the
2015-2020 timeframe under SGIP, it is not a suitable standard
for this bill, which applies to a much broader range of
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projects in perpetuity.
To assure that eligible projects reflect a genuine GHG
emissions improvement over the long run, the author and the
committee may wish to consider amending the current language
(on page 4, lines 38-40) as follows:
(A) Produces emissions of greenhouse gases that are less
than the levels established by the commission pursuant to
paragraph (2) of subdivision (b) of Section 379.6 the
average emissions rate for delivered electricity reported
by the electrical corporation for the service territory in
which the project is located for the calendar year prior to
the year the facility is installed.
To provide an ongoing mechanism to evaluate emissions
performance of eligible projects, the author and the committee
may wish to consider including the following provision:
A clean distributed energy resource shall provide relevant
data to the commission and the State Air Resources Board,
upon request, and shall be subject to onsite inspection to
verify equipment operation and performance, including
capacity, thermal output, and usage to verify criteria air
pollutant and greenhouse gas emissions performance.
REGISTERED SUPPORT / OPPOSITION:
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Support
Advanced Energy Economy
Audubon California
Bloom Energy
California Large Energy Consumers Association
Capstone Turbine Corporation
Center for Sustainable Energy
Cummins, Inc.
DE Solutions, Inc.
Doosan Fuel Cell America
EtaGen, Inc.
HRL Laboratories, LLC
Holt of California
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Inland Empire Foods, Inc.
National Energy Solutions
Park Bellevue Tower Community Association
Pasteurization Technology Group
Peterson CAT
Qualcomm
Regatta Solutions, Inc.
Sierra Nevada Brewing Co.
Solar Turbines
TechNet
Tecogen, Inc.
Western Energy Systems
Opposition
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Pacific Gas and Electric Company
San Diego Gas & Electric Company
Southern California Edison
The Utility Reform Network
Analysis Prepared by:Lawrence Lingbloom / NAT. RES. / (916)
319-2092