BILL ANALYSIS
AB 64
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Date of Hearing: April 1, 2009
ASSEMBLY COMMITTEE ON UTILITIES AND COMMERCE
Felipe Fuentes, Chair
AB 64 (Krekorian) - As Amended: March 24, 2009
SUBJECT : Energy: renewable energy resources: generation and
transmission.
SUMMARY : Increases California's Renewables Portfolio Standard
(RPS) to require all retail sellers of electricity and all
Publicly Owned Utilities (POUs) to procure at least 33% of
electricity delivered to their retail customers from renewable
resources by 2020. The bill addresses numerous issues that may
facilitate compliance, and creates the Renewables Infrastructure
Authority (RIA) to site and finance renewable generation and
transmission.
EXISTING LAW :
1)Requires investor-owned utilities (IOUs) and certain other
retail sellers to achieve a 20 % RPS by 2010 and establishes a
process and standards for renewable procurement.
2)Provides that publicly-owned utilities (POUs) are not subject
to the same detailed process and standards as IOUs, but are
required to implement and enforce their own RPS programs.
3)Defines eligible renewable technologies to include biomass,
solar thermal, photovoltaic, wind, geothermal, renewable fuel
cells, small hydroelectric (30 megawatts (MW) or less),
digester gas, municipal solid waste conversion, landfill gas,
ocean wave, ocean thermal, and tidal current. Provides that
eligible renewable resources that are located outside of
California may count toward the California RPS if the
generator commences operation after January 1, 2005, and the
facility is directly connected to California's transmission
grid or the associated electricity is delivered to California.
4)Requires IOUs to submit annual renewable procurement plans to
the Public Utilities Commission (PUC).
5)Allows the PUC to authorize the use of Renewable Energy
Credits (RECs) from eligible renewable resources for retail
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sellers to meet their RPS obligations. Allows POUs to sell
RECs to retail sellers of electricity if the POU has
established a RPS that is comparable to the RPS of the IOUs
and is in compliance with that RPS.
6)Requires the PUC to establish a market cost for electricity,
the market price referent (MPR), in order to determine whether
renewable contracts exceed market costs.
7)Creates a cap on above-market costs of renewable electricity
each IOU is required to spend under the RPS. If the cost cap
is reached, IOUs are not required to sign any renewable
contract that exceeds the market cost of electricity.
8)Requires the PUC to develop flexible rules for compliance for
the RPS that allow a retail seller that cannot not meet its
annual targets to avoid penalties under certain conditions.
9)Requires the CEC to certify sufficient sites and related
facilities for the construction and operation of thermal
powerplants of 50 MW and larger.
10)Precludes an electrical corporation from constructing a line,
plant, or system without having first obtained a certificate
from the PUC that the present or future public convenience and
necessity require or will require such construction
(certificate of public convenience and necessity, or CPCN).
THIS BILL :
1)Requires retail sellers of electricity to procure at least 20%
of electricity delivered to retail customers from renewable
sources by 2010, 25% by 2015, and 33% by 2020.
2)Requires POUs to comply with the same RPS mandates as retail
sellers, requires the POUs to meet specified public notice and
reporting requirements, and grants the California Air
Resources Board (CARB) the authority to issue penalties on the
POU if they fail to meet the RPS mandates.
3)Provides that the code sections governing California's current
RPS shall sunset in 2011 and recasts these provisions in new
sections along with the changes noted in this analysis.
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4)States the intent of the Legislature that the RPS shall
accomplish the following objectives:
a) Reduce emissions of greenhouse gases.
b) Reduce in-state consumption of nonrenewable fuels in
order to improve public health.
c) Stimulate sustainable economic development.
d) Decrease California's reliance on imported sources of
energy.
e) Increasing fuel diversity.
5)Provides that electricity from an out-of-state renewable
facilities is not eligible for the California RPS unless the
electricity is scheduled into California simultaneous to its
generation.
6)Requires that a utility's renewable procurement plan asses the
viability of proposed renewable products based on the
developer's experience, the feasibility of the technology, and
risk of delay of construction.
7)Allows a retail seller or POU to use RECs from any renewable
facility in the Western Electricity Coordinating Council
(WECC) territory toward its RPS obligation, but provides that
a retail seller or POUs may meet no more than 10% of its PRS
obligation using RECs from facilities that do not deliver
their electricity into California.
8)Replaces the current Market Price Referent calculation and
instead requires the PUC to develop a benchmark price for
renewable electricity, which will be used to determine if an
individual contract is above general market values of
electricity, that takes into account the price of all fixed
price contracts, the value of deliverability characteristics
of different contracts, the value of carbon reductions from
renewable resources, and the value of any other emission
reductions.
9)Requires the PUC to establish a cost cap for total above
market costs (costs that exceeded the benchmark price)
expended by each IOU. Provides that the cap shall not exceed
an unspecified percentage of the IOUs revenue requirement. If
the cost cap is exceeded the IOU shall be allowed to limit
renewable procurement to renewable resources that can be
procured below the benchmark price.
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10)Provides that the PUC MAY waive existing penalty provisions
for non-compliance with the 20% RPS mandate if the PUC finds
that the retail seller has made "commercially reasonable
efforts to procure eligible renewable energy recourses."
11)Eliminates the requirement that the PUC create flexible rules
of compliance for renewable procurement requirement beyond
20%.
12)Requires the PUC to expand an existing feed-in-tariff program
for generation units smaller than 1.5 MW to include all
renewable generation up to 5 MW.
13)Requires the PUC to provide a preference for energy resources
that come from a California supplier in developing the IOUs'
procurement plans.
14)Creates the Renewable Infrastructure Authority (RIA) with the
powers to establish, finance, purchase, lease, own, operate,
acquire, or construct generating facilities that are eligible
renewable energy resources and other projects that further the
state's renewable energy goals.
a) Provides the RIA to be governed by a 9-member board,
consisting of the secretaries and chairs of state agencies
that affect electricity planning, siting, regulating and/or
constructing.
b) Requires the RIA to certify all sites and related
facilities for all renewable generation facilities with a
minimum generating capacity of 5 megawatts (MW).
c) Permits the RIA to identify suitable zones for renewable
energy generation, conduct studies, perform as the lead
agency for California Environmental Quality Act (CEQA)
compliance for all generation projects proposed in the
designation zone, and issue a proposed decision for siting
the facility within 180 days after the date the generator's
application was deemed complete.
d) Permits the RIA to request proposals from qualified
participating parties to develop generation facilities, and
if after 45 days the RIA determines it is necessary and
feasible, the RIA shall exercise its authority to build,
own, and operate generation facilities as part of a
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least-cost electrical supply policy.
e) On or after January 1, 2011, provides the RIA with
exclusive power to certify all electric transmission lines,
remote resource interconnection lines, electric
transmission facilities, and facilities appurtenant
thereto, and related facilities in the state.
i) Exempts facilities for which the PUC has issued a
CPCN.
ii) Exempts electric transmission lines that connect
generation facilities to the high-voltage transmission
grid that are under the siting authority of the CEC
(gen-tie lines).
f) Permits the RIA to identify suitable sites for the
construction of electric transmission lines, on its own
motion or a motion by the CEC, or by an applicant who plans
to construct an electric transmission line within the
state, and allows the RIA to conduct studies, perform as
the lead agency for CEQA compliance, use bond authority,
and request proposals from qualified participating parties.
g) Requires the RIA, by January 1, 2011, and annually
thereafter, and in consultation with the CEC and CAISO, to
develop a Renewables Investment Plan that shall take into
account the state's electric generation and transmission
needs over the next decade, and outlines a strategy for
cost-effective investments, and requires all investments
made by the RIA to be consistent with the strategy outlined
in the Renewables Investment Plan.
15)Permits the RIA to issue bonds in an amount not to exceed
$6.4 billion to finance activities associated with renewable
energy generation projects.
16)Precludes the RIA from financing or approving any new
program, enterprise, or project on or after December 31, 2020.
FISCAL EFFECT : Unknown.
COMMENTS : According to the authors, the purpose of this bill
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is to increase the amount of electricity procured from renewable
generation sources to reduce greenhouse gas emissions, improve
public health and air quality, stimulate economic development by
encouraging innovation in energy technologies and creating new
employment opportunities in California, and increase fuel
diversity to promote greater stability and predictability in
electricity process for consumers. In addition, this bill is
intended to provide developers with an over-arching authority
that includes the number of disparate and often conflicting
state agencies to establish consistency, cohesion, and a single
point of contact.
Background : In 2002, the Legislature approved SB 1078 (Sher),
Chapter 516, Statutes of 2002, which created the RPS. Under SB
1078, all retail sellers of electricity were required to
increase their renewable procurement each year by at least 1% of
total sales, so that 20% of their sales are from renewable
energy sources by December 31, 2017. This goal was accelerated
to 20% renewable power by 2010 by SB 107 (Simitian), Chapter
464, Statutes of 2006.
The PUC reports that, for 2007, the IOUs have achieved varying
levels of progress toward the 20% goal: PG&E = 11.4%; SCE
=15.7%; SDG&E = 5.2%. While each IOU added renewable resources
in 2007, the percentage of renewables compared to the rest of
the portfolio declined from 2006 due to total load growth. All
agencies and stakeholders agree that the IOUs will not meet the
2010 deadline. However, the PUC reported in October 2008 that
the IOUs should be in compliance in or around 2013.
1) Eligible Resources : Current law defines renewable
electricity as electricity that comes from biomass, solar
thermal, photovoltaic, wind, geothermal, fuel cells using
renewable fuels, small hydroelectric generation of 30 MW or
less, digester gas, municipal solid waste conversion, landfill
gas, ocean wave, ocean thermal, or tidal current can count
toward a retail seller's RPS. To count toward a retail
seller's RPS obligation, the facility must meet several other
requirements including that the facility be located in
California or deliver its electricity to California.
The definition of "delivered" in current law was written to
allow an out-of-state renewable generator that wants to serve
California load to comply with California Independent System
Operator (CAISO) rules that require out-of-state electricity to
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be scheduled into California at specific times and amounts.
Since renewable resources like wind and solar are intermittent,
they cannot be scheduled at specific times and amounts. The
intent of the language was for the renewable energy to come to
California at some point and then offset the need for fossil
fuel generation within California. However, the CEC, which sets
the eligibility rules, interpreted the statutory language to
allow for transactions where the renewable electricity never
comes to California to count toward the RPS.
The definitions of renewable resources are generally accepted
except the definition of what types and size of hydroelectricity
facilities can count toward the RPS. Current law provides that a
hydroelectric facility must have a capacity of 30 MW or less and
must meet other specified streamflow standards to count toward
the RPS.<1> Most of the POUs would like to have this definition
changed to increase the allowable capacity to 50 MW.
Additionally, PG&E has requested that small hydroelectric
facilities in British Columbia count toward its RPS obligation
if the facilities comply with British Columbia's environmental
standards but not California standards.
AB 64 changes the current definition of "delivered" so that the
renewable energy from an out-of-state facility must be scheduled
into California at the same time it was produced by the
out-of-state facility. Additionally, AB 64 changes specific
restrictions on the use of municipal solid waste so that
electricity from new solid waste conversion facilities may count
toward the RPS if the facility meets specific environmental
standards.
2) Renewable Energy Credits : A Renewable Energy Credit (REC)
represents the renewable attributes of renewable generation. A
REC can remain bundled with the associated energy. In that
case, the utility buys the renewable power and uses the RECs to
meet its RPS obligation and uses the associated electricity to
meet its own load. RECs can also be traded separate from the
underlying electricity (tradable RECs or tRECs). In this case,
one retail seller purchases the tREC and applies it toward its
RPS obligation and another retail seller purchases the
associated electricity to meet its own load. The second retail
---------------------------
<1> Current law also allows all electric generation that is the
result of efficiency improvements to existing hydroelectric
facilities to count toward the RPS, regardless of the size of
the original output of the facility.
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seller cannot count that electricity toward its own RPS
obligations.
California law allows the use of tRECs to meet RPS obligations,
but the tRECs must come from a facility that meets all of the
requirements to be an eligible renewable resource. The tREC must
come from a facility that is located in state or from an
out-of-state facility that is built after 2005 and delivers the
associated electricity into California. While current law allows
for tRECs, it also requires the PUC to develop specific rules on
tREC eligibility before retail sellers can count tRECs toward
their RPS obligations. A decision to implement the tREC rules is
pending at the PUC.
Most retail sellers and some renewable generators have advocated
for broader use of RECs. The retail sellers and the Clean Power
Campaign state that the RPS should not limit the use of RECs or
put restriction on the geographic location or deliverability of
the associated renewable resource. They believe this broad REC
market would give retail sellers more procurement options and
could reduce the cost of complying with the RPS.
A number of environmental groups, the Coalition of Utilities
Employees, the Large Solar Association, and California Wind
Energy Association have all advocated for a very limited
allowance for out-of-state RECs. They fear that a wide-open REC
market will lead to "paper compliance with the RPS" and will not
result in the construction of any renewable generation within
California.
The determination of what the allowance of non-delivered
out-of-state RECs will be comes down to the question of what are
the goals of the RPS program. The author and the intent language
state that the goals of AB 64 are: 1) reduction of greenhouse
gases, 2) increased air quality and public health in California
through the reduction of fossil fuel generation within
California, 3) increased fuel diversity and reduced reliance on
imported energy, and 4) economic development within California.
A renewable facility constructed in California would meet all
four of these goals.
A wind farm in Oregon that sells its RECs to a California retail
seller meets the first goal since it generally offsets the need
for electricity from a carbon emitting resource. This Oregon REC
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transaction only meets the second and third goal if the
transaction also requires that electricity is delivered into
California since that electricity will offset the need for
in-state generation. The wind farm in Oregon does not help meet
the fourth goal.
AB 64 allows for a limited amount of non-delivered tRECs to
count toward the California RPS. The bill provides that a retail
seller or POU can use tRECs from out-of-state renewable
generation that is not delivered into California to meet up to
10% of their RPS obligation.
3) Cost containment : Current law limits the amount of renewable
electricity an IOU is required to acquire under the RPS,
regardless of the annual RPS targets that apply to the IOU. The
limit is based on the valuation of how much has been spent on
renewable procurement that exceeds the forecasted market price
of electricity.
The PUC determines the forecasted market price of electricity on
an annual basis based on the estimated cost of running a natural
gas fired power plant plus the cost of carbon emissions from a
natural gas facility. The market price is referred to as the
market price referent (MPR). The cost estimates also include
adders that increase the value for electricity that is delivered
at times of peak demand when electricity is generally more
expensive. These adders have the impact of creating a higher MPR
for solar which generates more electricity during peak demand
time than wind, which is generated mostly at night.
An IOU must purchase renewable electricity even when the
contract cost exceeds the MPR. However, an IOU is required to
acquire this higher-cost renewable electricity only to the
extent that the above-market costs are less than the cost cap.
If the above-market costs exceed the cost cap, then the IOUs are
not required to sign any additional contracts that exceed the
MPR. However, if there are suitable contracts with costs less
than the MPR the IOU would still be required to procure power
under those contracts.
The MPR was intended to be tool a to identify any approved
above-market costs of a specific renewable contract. Some
renewable developers and most environmental groups believe that
the MPR has actually become the de-facto price of renewable
power and that they are forced to bid into the IOUs procurement
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requests at the MPR. If this is the case, the MPR could limit
the number of developers willing to bid into the RPS since the
MPR can be lower than the actual generation costs. The limited
amount of publicly available data from the IOUs procurement
process does not completely support this position. The IOUs have
signed a number of contracts that exceed the MPR.
The cost cap itself was not established based on a determination
of the perceived reasonable cost of renewables, ratepayer
benefits, or tolerable ratepayer impacts. Instead, it was based
on the amount of funds that were to be collected for prior
renewable electricity grant program. Consequently, it is
possible that the cap was set at a level that makes achieving a
20% RPS or a 33% RPS impossible. While the current cost cap has
not been reached, the PUC testified at a hearing of the Select
Committee on Renewable resources that is likely that a
determination will be made in the next month that the cap has
been reached.
This cost cap process only applies to renewable contracts that
are signed through an annual Request for Proposal (RFP) process
conducted by the IOUs. The IOUs have signed bi-lateral
contracts that were negotiated outside of the RFP process that
exceed the MPR, but those above-market costs do not count
against the cost caps. ESPs are required to meet the RPS but
they have no cost cap.
Many renewable developers, the IOUs, TURN, and the Union of
Concerned Scientists have all stated that they believe some cost
containment mechanism is needed as part of the RPS so that the
program does not become a "renewables at any cost" program which
could lead to massive rate increases to fund renewable
procurement. These groups do not agree on what is the best form
of cost containment. The options include leaving the current
cost containment in place but increasing the cost caps to better
reflect the estimated cost of achieving a 33% RPS, eliminating
the MPR but then capping the amount of money each retail seller
is expected to spend on the total cost of renewable power (not
just the above-market costs), or creating an Alternative
Compliance Payment System (ACPs).
AB 64 modifies and renames the MPR process so that it takes into
account more factors and will not be based solely on natural
gas. The bill also sets the cost cap at an unspecified
percentage of the retail sellers' gross revenue. The intent of
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this provision is to determine how much impact renewable
electricity should have on a retail sellers' overall cost
structure and then set the cost cap at that level by basing it
on a percentage of overall revenue.
The authors had initially not specified the actually cost cap in
the introduced version of AB 64 in order to solicit input from
stakeholders on where the cap should be set. While a number of
impacted parties have not offered any input on where the cap
should be set, the groups that did all suggested 5% of the
retail gross revenue is the appropriate level. The committee
and the author may wish to consider amending the bill to remove
the unspecified cost cap and provide that the cap is set at 5%
of gross revenue.
4) Enforcement and Off Ramps : Current law requires the PUC to
enforce IOU and ESP compliance with the RPS. The PUC may fine
an IOU or an ESP that fails to meet its year-to-year RPS target.
The PUC has set the penalties at 5 cents per kilowatt hour by
which the retail seller falls short of its RPS target. The PUC
has capped the total amount of penalties that can be charged in
a year at $25 million. Current law does not direct the use of
these penalty monies, which will be deposited in the state
General Fund.
Current law also requires the PUC to develop rules of flexible
compliance that would allow retail sellers to avoid penalties
for non-compliance under certain conditions. The flexible
compliance rules allow retail sellers to miss RPS goals in one
year provided that it meets that goal within three years. This
means that a retail seller will not be penalized for failing to
meet the 20% by 2010 goal if it actually procures 20% of its
power from renewable resources by 2013.
A second flexible compliance rule allows the PUC to waive
penalties for a retail seller if the PUC finds that there was
insufficient transmission to meet the RPS goals and the retail
seller has made all reasonable efforts to ensure that the
necessary transmission would be available.
There is currently no penalty or enforcement mechanism in place
for POUs since there is no specific RPS mandate in statute for
the POUs. AB 64 provides that CARB may enforce penalties on the
POUs if they fail to meet their RPS targets.
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AB 64 replaces the existing rules for flexible compliance and
instead allows the PUC to waive all penalties for failing to
meet the 20% RPS requirement if the PUC finds that retail seller
made "a commercially reasonable effort to procure eligible
renewable resources" in an amount sufficient to meet its RPS
obligations. AB 64 provides that the PUC may fine retail sellers
for failure to meet the 2015 target of 25% renewable resources
and the 2020 target of 33% renewable resources but does not
provide for any flexibility to waive or delay those penalties.
While AB 64 allows for the imposition of penalties on both POUs
and retail sellers, the bill provides that different agencies
impose the fines. This could lead to an uneven application of
penalties if the PUC and CARB do not act in concert.
5) Publicly Owned Utilities : Current law does not require POUs
to meet the same RPS that other electricity providers are
required to meet. Rather, current law directs each publicly
owned utility to put in place and enforce its own RPS and allows
each publicly owned utility to define the electricity sources
that it counts as renewable. No state agency enforces POU
compliance or places penalties on a publicly owned utility that
fails to meet the renewable energy goals it has set for itself.
AB 64 requires the POUs to meet the 33% RPS by 2020 requirement.
The bill also increases public accountability for POUs by
requiring that the RPS be established in a public meeting and by
requiring the POUs to report some additional information on
their renewable procurement to their customers and to the CEC.
Most of the POUs do not object to creating a specific POU RPS
mandate. They have argued that requiring a state agency to
impose penalties is both unfair and unnecessary. The POUs argue
that all penalty costs would simply result in a rate increase
for their customers and would not result in helping that POU
actually procure renewable resources. Additionally, the POUs
believe that since their boards are directly accountable to
voters, their voters would remove the board members from office
if the POU was not in compliance with the RPS.
Trinity Public Utilities District argues that because it serves
customers using only electricity from a large hydroelectric
facility and it has contractual access to that same resource to
meet all of their load growth, an RPS requirement for them would
be costly and counterproductive. They have asked to be
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specifically exempted from the bill.
6) Feed-in-tariffs : California's RPS was designed to force
renewable generators to compete against each other by bidding
into an IOU solicitation for renewable resources. This
competition should allow the utilities to pick the best
available technologies and the best price. However, the
competitive process in place can be too expensive for smaller
generators to participate. These smaller generators can provide
benefits to the electricity grid by placing their renewable
generation closer to load centers and thus alleviating the need
for additional transmission. A number of parties have suggested
that the best way to promote the construction of these small
distributed generation resources is through a feed-in-tariff
that provides the generators a set price for their generation.
This set price means they would not have to negotiate an
individual contract with a utility and instead would simply
interconnect with the utility and the utility must take their
output. The CEC has recommended that the Legislature pursue a
feed-in-tariff for renewable generation under 20 MW in capacity
to promote the development of these smaller generators and the
PUC recently released a staff proposal to expand their current
feed-in-tariff program so that is encompasses more resources.
AB 64 contains a feed-in-tariff for generation units smaller
than 5 MW in capacity. While 47 of approved contracts from the
IOUs renewable solicitations are for generation units under 20
MW in capacity, less than 3.5% of all expected capacity from the
current renewable contracts is associated with generation units
under 5 MW.
While there appears to be broad support for feed-in-tariffs
there is no consensus on the size of the allowable generation in
the program or the price a generator should be paid. Given the
magnitude of the debate, every party that has commented on the
feed-in-tariff provisions in the bill have asked that the
language be removed and the issue be addressed in a separate
bill.
7) Multi-jurisdictional utilities : Two IOUs that serve
electricity customers in California also serve customers in
other states. In fact, for both Sierra Pacific and PacifiCorp
the vast majority of their customers are located outside of
California. Currently law requires these companies to meet a 20%
RPS by 2010 for their California load, but provides for a number
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of exceptions for where the generation units can be located and
how it is procured to account for the multi-state nature of
these companies. PacifiCorp has expressed concern that AB 64
does not carry these exceptions forward for the 33% RPS goal.
Without these exceptions they believe compliance with the 33%
mandate will be impossible.
8) Siting transmission and generation: Current law provides the
CEC authority to site electric generation facilities with a
capacity of greater than 50 MW. As part of the CEQA compliance,
other state agencies provide input, such as the Coastal
Commission and/or the Department of Fish and Game. Most
renewable generators are less than 50 MW, and therefore, are
approved and sited by local jurisdictions. Any needed
transmission must be included in the utilities' transmission
plans and included in the CAISO transmission plan. Prior to
building any needed transmission, the PUC must issue a CPCN
(which can take 3 to 4 years), and the transmission owner must
request cost-recovery for the transmission line from the Federal
Energy Regulatory Commission (FERC).
Some developers have had their projects delayed by a state
agency. In San Luis Obispo, a large solar project has been
indefinitely delayed due to a Department of Fish and Game field
office review. Others state that local jurisdictions don't
often possess the experience or the resources to expeditiously
site electric generation facilities.
In 2006, the PUC recommended that solutions be developed that
would allow cost recovery mechanisms to mitigate transmission
owners' risk and renewable developers' "transmission financing
hurdles and uncertainties." The PUC also recommended
streamlining the permitting process, and evaluating the
interconnection process and its coordination with procurement
and transmission expansion.
AB 64 establishes the RIA to provide a comprehensive and
integrative process to facilitate integrating increasing amounts
of electricity generated by renewable sources into the state's
energy portfolio. The RIA provides the authority to plan for,
site, and if needed, finance generation facilities. It also
sites all in-state transmission facilities.
With regard to generation, AB 64 provides RIA with siting
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authority for all renewable energy generation facilities greater
than 5 MW. Any facility proposing to locate in a designated
renewable energy designation zone will fall under the RIA's
programmatic environmental impact report and can use the RIA's
report to comply with CEQA. The RIA, after designating an
application complete, must render a decision on the siting of
the facility within 180 days.
By allowing the RIA to designate a renewable energy designation
zone by a motion by the CEC, the authors intend to build upon
the established Renewable Energy Transmission Initiative (RETI)
process that was initiated at the staff level by contractors
through the CEC and PUC. The RETI identifies optimal renewable
energy designation zones and the transmission corridors
necessary to access the renewable generation.
AB 64 provides the RIA with siting authority for transmission.
According to the PUC 2008 RPS report, in order to attain a 33%
renewable energy portfolio by 2020, the state needs 7 new major
transmission lines (15,900 MW) at a cost of $6.4 billion.
Developers site a lack of reasonably priced financing as an
impediment to facilitating the RPS. AB 64 provides RIA with
bonding authority of $6.4 billion to fund or guarantee renewable
energy generation and/or transmission projects, if deemed
feasible and in order to encourage in-state development of
renewable generation facilities.
A common concern with transmission siting has been coordination
with the federal government, and encouraging the federal
agencies to work on California applications. AB 64 permits the
chief executive officer to designate a liaison to the federal
government to facilitate when necessary the ability for the RIA
to site generation and transmission.
Some parties are concerned that the RIA powers are too broad,
including the powers of eminent domain and siting authority over
local jurisdictions. The Sierra Club is concerned about the
expedited 6-month siting process for renewable facilities that
are located within a renewable energy designation zone. The
Sierra Club recommends that any authority to permit transmission
should be subject to the Garamendi Principles, which require
considering upgrading existing transmission lines and building
on existing rights of way prior to constructing new transmission
lines using new corridors.
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Some renewable developers are concerned that because the RIA has
authority to purchase, lease, own, operate, or construct
renewable generation, the RIA may compete with viable
businesses. The Clean Power Campaign encourages existing state,
local, and federal entities to work and communicate with each
other.
The Sierra Club strongly endorses the use of public bonds to
finance renewable energy generation facilities. However, it
recommends involving the CEC to provide guidance on how to get
the most benefits from bonds, and that the CEC work with the
State Treasurer and bond authority.
9) Another state agency? AB 64 transfers certain
responsibilities from the CEC and PUC to the RIA. The RIA Board
of Directors is comprised of the Secretaries of the Resources
and Environmental Protection agencies, the Chairs of the Energy
and Public Utilities commissions, the President of the Board of
the California Independent System Operator, and others. The RIA
Board is provided overarching authority over the regulations
that govern the departments under the agencies if it deems a
project as a statewide priority. The Board could conceivably
weigh the concerns of the different state agencies and determine
either a compromise, or render a decision that would encompass
overarching statewide needs.
The PUC states that the PUC has existing constitutional
authority that provides only the PUC jurisdiction over
transmission siting and approval. The PUC regulates the
investor-owned utilities, which comprise about 74% of
California's ratepayers. The PUC ensures that public
convenience would be achieved by the utility building its own
generation and/or transmission. The PUC states that its staff
plays a leading role in the RETI process to prioritize renewable
energy zones. However, the PUC does not site generation
facilities, just only transmission facilities. The transmission
owners must apply to the Federal Energy Regulatory Commission to
recover costs.
If all comprehensive planning and siting functions were
transferred to the PUC, the PUC's role would be greatly expanded
and possibly create concern over the PUC's regulatory and
rate-recovery role over the investor-owned utilities. In
addition, the PUC is an appointed body with tremendous latitude.
Although the Legislature has constitutional authority over the
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PUC, the PUC has issued decisions that may contradict
legislative directives or statutory requirements. Nevertheless,
AB 64 retains the PUC's issuance of an IOU's certificate of
public convenience and necessity for IOU-owned generation and
transmission. The RIA would be the lead agency for siting
purposes.
If the CEC's role was expanded to include planning and siting
for all generation facilities over 5 MW, the generator could
still be stymied by other state departments. This may not
improve the current process, or alleviate some of the
impediments currently experienced by having numerous disparate
agencies having to provide certification.
Most letters in opposition pose overarching concerns with
establishing yet another state agency.
10) Technical Amendments : The Committee and the Author may want
to consider the following technical amendments to AB 64:
1) On page 24, line 6, and on line 15, after "digester
gas," insert "municipal solid waste conversion,". This
phrase was inadvertently removed from the current
definition of eligible renewable resource when it the
definition was redrafted into a new code section.
2) On page 23, line 34, after "use" insert "and that meets
the requirements of Section 953". This change insures that
the AB 64 is consistent with existing law that provides
that conduit hydro electric facilities meet all eligibility
requirements.
3) On page 37, line 21, after "retail sellers" insert "and
local publicly owned electric utilities". This clarifies
that the current system to track RECs should be used by
both the IOUs and the POUs.
4) On page 28, line 26, replace "combustion" with
"conversion"
5) On page 34, line 3, strike "and other retail sellers".
This particular section only applies to IOUs and does not
apply to other retail sellers.
6) On page 33, line 35, delete "annual". This is
contradictory to other provision of the bill since the bill
replaces annual procurement targets with new targets on
specified years.
REGISTERED SUPPORT / OPPOSITION :
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Support
American Federation of State, County and Municipal Employees
(AFSCME)
Clean Power Campaign (if amended)
Environment California (if amended)
First Solar (if amended)
National Parks Conservation Association
Northern California Power Agency (NCPA) (if amended)
Oakland City Council
Sierra Club California (if amended)
Solar Alliance (if amended)
Southern California Public Power Authority (SCPPA) (if amended)
Opposition
Alliance for Retail Energy Markets (AReM)
BP America Inc. (unless amended)
California Chamber of Commerce
California Coalition of Utility Employees (CUE) (unless amended)
California Farm Bureau Federation (unless amended)
California Manufacturers & Technology Association (CMTA)
California Public Utility Commission (CPUC) (unless amended)
California State Association of Electrical Workers (unless
amended)
California State Pipe Trades Council (unless amended)
Imperial Irrigation District (IID) (unless amended)
Pacific Gas and Electric Company (PG&E) (unless amended)
Sempra Energy (unless amended)
Southern California Edison (SCE)
Trinity Public Utility District (TPUD) (unless amended)
Western States Council of Sheet Metal Workers (unless amended)
Western States Petroleum Association (WSPA) (unless amended)
Analysis Prepared by : Edward Randolph and Gina Adams / U. &
C. / (916) 319-2083