BILL ANALYSIS
SB 14
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Date of Hearing: June 29, 2009
ASSEMBLY COMMITTEE ON UTILITIES AND COMMERCE
Felipe Fuentes, Chair
SB 14 (Simitian) - As Amended: June 23, 2009
SENATE VOTE : 21-16.
SUBJECT : Renewable Portfolio Standard
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. Makes changes to current renewable
procurement rules and procedures for siting 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 POUs are not subject to the same detailed
procurement 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 MW or less), digester gas,
municipal solid waste conversion, landfill gas, ocean wave,
ocean thermal, and tidal current.
4)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.
5)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
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contract that exceeds the market cost of electricity.
6)Requires PUC to develop flexible rules for compliance for the
RPS that allows a retail seller that cannot not meet its
annual targets to delay compliance for up to three years and
avoid penalties under certain conditions.
7)Requires the California Energy Commission (CEC) to certify
electric generation facilities for the construction and
operation of thermal powerplants of 50 MW and larger.
8)Precludes an electrical corporation from constructing a line,
plant, or system without having first obtained a permit from
PUC that the present or future public convenience and
necessity require or will require such construction, (a
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 2012, 23% by 2014, 26% by 2016, 30% by 2018, 33% by
2020.
2)Modifies the definition of eligible renewable resources under
the RPS as follows:
a. For renewable resources located outside of
California, the electricity from the resources must be
scheduled into California at the same time it is produced
by the renewable facility.
b. The renewable facility must commence initial
operation after January 1, 2010, or the electricity from
the facility that commenced operation prior to January 1,
2010, was sold to a retail seller prior to May 31, 2009.
3)Allows retail sellers and POUs to count the renewable output
from renewable facilities that do not comply with the
definitions of eligible renewable resources toward the RPS if
the retail seller or POU had executed a contract prior to May
31, 2009, to procure resources from a facility that met the
requirements of a renewable resource prior to passage of this
bill.
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4)Eliminates current rules that allow retail sellers to postpone
compliance with annual RPS targets for up to three years in
the future. Replaces those rules with provisions that allow
the PUC to grant a retail seller the ability to delay
compliance for up to two years if the PUC makes specific
findings that there is insufficient transmission to meet the
RPS or there were unforeseen delays in permitting or
interconnecting projects. The findings must consider whether
the retail seller made all reasonable efforts to construct new
transmission and made prudent decisions in procuring
resources. The retail seller must also show that it has made
all reasonable efforts to procure distributed generation
resources and to procure RECs.
5)Requires all retail sellers to procure renewable resources
beyond the specified targets to account for the risk that some
planned resources will not being developed. The margin of the
over-procurement shall be set at the same level for all retail
sellers.
6)Requires renewable procurement plans prepared by IOUs and
approve by the PUC to include a process to consider the
viability of proposed projects when ranking project bids.
7)Provides that the Market Price Referent (MPR) shall be used to
determine above-market costs of renewable electricity. The MPR
shall be set based on the value of different generation
products within a utility's portfolio and the value of current
and anticipated environmental compliance costs.
8)Provides that an IOU does not have to procure additional
renewable resources in a particular year if the total
above-market cost of the renewable electricity procured under
the RPS program or bilateral contracts for that year exceeds
6% of the IOUs total bundled electricity sales.
9)Requires the PUC to adopt mechanisms to limit the influence
the MPR has on how sellers price their renewable proposals and
buyers select their contracts.
10)Creates a mechanism to allow the PUC to approve an IOU
application to own its own renewable generation and then
recover in rates the cost of that generation plus a reasonable
rate of return, if the PUC finds the renewable generating
facility has a reasonable cost and provides a comparable value
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to ratepayers as compared to other solicitations for eligible
renewable resource. Caps the total amount of renewable
generation an IOU can own at 8.5% of the IOU's total load.
11)Allows retail sellers and POUs to use RECs from out-of-state
renewable resources that do not deliver electricity into
California (undelivered RECs) toward their RPS obligations,
but caps the total amount of undelivered RECs at 20% of the
retail seller's or POU's renewable procurement targets.
12)Provides that retail sellers and POUs can count all
undelivered RECs from contracts executed by the retail seller
or POU prior to May 31, 2009.
13)Requires the PUC to approve an application to build new
transmission lines that are reasonably necessary to develop
renewable resources within one year of the filing of a
completed application, if the new transmission line does not
threaten substantial harm to the environment that necessitates
a longer time for review under the California Environmental
Quality Act (CEQA).
14)Clarifies that an IOU shall be allowed to recover in rates
the costs of constructing transmission lines that will
primarily deliver electricity generated within a competitive
renewable energy zone identified by the Renewable Energy
Transmission Initiative (RETI) or the transmission line is
needed to deliver electricity that is to be generated by
generation facilities in an area where at least 50% of the
generation capacity is from renewable resources.
15)Requires the California Independent System Operator (CalISO)
to adjust its market structure to achieve, in the most cost
effective manner, the 33 percent RPS threshold by 2020,
develop annual statewide transmission plans, seek proposals
from and propose transmission projects to POUs that can be
jointly owned, and eliminate barriers over transmission lines
in its control area.
16)Requires the Department of Fish and Game (DFG) to establish
an internal division for the purpose of performing planning
and streamlined environmental compliance services with a
priority given to the building of eligible renewable energy
resources.
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17)Requires the PUC to prepare, on an annual basis, reports to
the Legislature containing information on the status of
meeting the RPS, possibilities of retail sellers exceeding
caps on above-market costs, overall cost of the RPS
compliance, and the status of permitting and siting renewable
facilities.
18)Requires POUs to comply with the same RPS mandates as retail
sellers and to meet specified public notice and reporting
requirements. Provides that the POUs shall retain discretion
over specific renewable procurements decisions necessary to
meet the RPS mandates.
19)Requires the CEC to establish and enforce a 33% RPS for each
POU.
20)Requires the CEC in consultation with California Air Resource
Board (ARB) to adopt regulations for the enforcement of the
RPS on POUs. Provides that the ARB shall, until such time
there is a market mechanism to distribute emissions allowances
for greenhouse gasses, have the authority to impose penalties
on POUs for failure to comply with the RPS.
21)Clarifies that a public utility district receiving 100
percent of its electricity pursuant to a preference right
pursuant to the federal Trinity River Diversion Act of August
12, 1955 is in compliance with the renewable energy
procurement requirements of the RPS Program.
FISCAL EFFECT : Unknown
COMMENTS :
Background : In 2002, the Legislature approved SB 1078 (Sher),
Chapter 516, Statutes of 2002, which created the RPS. Under the
RPS, Investor Owned Utilities (IOUs) and competitive energy
service providers (ESPs) 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
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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.
This month the PUC completed a report with preliminary results
on analyzing the feasibility and costs of advancing the RPS
targets from 20% to 33% by 2020. According to the report,
"achieving 33% RPS by the year 2020 is highly ambitious, given
the magnitude of the infrastructure buildout required."
The report also looked at the costs of achieving a 33% RPS.
Under the PUC's analysis, the incremental cost of moving from
the current 20% RPS mandate to a 33% RPS would result in a 7.1%
increase in utility costs. The increased cost include the costs
of more expensive generation resources, new transmission, and
other resources that will be needed to provide back up
generation when renewable electricity is not available. The
cost increases assumes the utility will continue the same
balance of renewable technologies that they are perusing today,
which includes a large reliance on wind and solar energy. The
cost increases also assume the direct costs of building new
renewable facilities remains unchanged over time and do not take
into account potential decreases in technology costs overtime.
1) The New targets : SB 14 eliminates the requirement that retail
sellers procure 20% of their electricity by 2010 and instead
requires that following procurement targets:
a) 20% by 2012.
b) 23% by 2014.
c) 26% by 2016.
d) 30% by 2018.
e) 33% by 2020.
While this new procurement schedule acknowledges the reality
that no retail sellers will comply with the 20% by 2010 targets,
it also does not acknowledge the difficulty retail sellers will
have moving beyond 20% until several new transmission lines are
constructed. While two needed transmission lines should be
completed by 2013, the PUC estimates a total of 7 new lines will
need to be constructed, and those lines will likely take 5 to 10
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years to complete. Given these transmission limits, a
procurement schedule that requires slower renewable growth early
in the program and larger incremental increases as 2020
approaches may be more realistic. The committee and the author
may wish to consider amending the bill to provide for a
renewable growth pattern that better tracks transmission
development such as 20% by 2012, 23% by 2015, 28% by 2018 and
33% by 2020.
2) 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.
While the definition of renewable resources is generally
accepted, there is debate over 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. This change would allow the POUs to
continue to count some existing small hydroelectric facilities
to count toward their RPS obligations. However, it is unlikely
that the change would result in the construction of new
facilities that are larger than 30 MW but smaller than 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.
Another resource that currently cannot be counted as renewable
is conversion of solid waste, where solid waste is turned into a
gas that can then be used to produce electricity. Advocates for
solid waste conversion believe that these facilities can process
solid waste that cannot be recycled and thus prevent the waste
from entering landfills. Opponents of solid waste conversion
counting toward an RPS requirement are concerned that some of
the converted waste could actually be recycled and in most
---------------------------
<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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circumstances recycling has better environmental benefits than
conversion. Some opponents also believe that since most of the
material that will be converted was originally produced from oil
by-products (plastics) that the material being used is actually
a fossil fuel and not renewable.
Current law also allows for renewable generation to be owned by
retail sellers or for the retail sellers to contract to purchase
renewable electricity from merchant generators. Prior to 2008,
federal tax rules made utility ownership of renewable generation
economically unfeasible. However, new tax rules make IOUs
eligible for tax credits for owning renewable facilities. Even
with the changes in tax rules IOUs are reluctant to pursue
owning their own renewable generation under most circumstances
to do concerns over their ability to recover all costs of the
generation in rates. SB 14 includes a provision to clarify the
process in which IOUs can recover the cost of building their own
generation, but also caps the total amount of renewable
generation they can directly own.
3) Location, deliverability, and renewable energy credits : To
count toward a retail seller's RPS obligation, the renewable
facility must meet several requirements including that the
facility be located in California or deliver its electricity to
California. The definition of "deliver" in current law was
written to allow an out-of-state renewable generator that wants
to serve California load to comply with CalISO rules that
require out-of-state electricity to 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 as an eligible resource.
SB 14 potentially limits the amount of out-of-state generation
that can count toward the RPS by changing the definition of
"deliver." With the limited exception discussed under the
renewable energy credits section below, the new definition
requires that electricity from an out-of-state facility that is
not directly interconnected to a California control area must be
simultaneously scheduled into California. This means that the
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renewable electricity must come into California at the same time
it is produced or it cannot count toward the RPS. This new
definition prevents a utility from counting transactions toward
the RPS where it purchases wind generation from an out-of-state
generator but then sells that electricity to another
out-of-state entity and instead imports electricity from a
fossil fuel facility. However, the definition also makes it
almost impossible to purchase electricity from a solar or wind
facility that is located out-of-state, since these resources can
not be simultaneously scheduled into California.
A 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 electricity 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 seller cannot count that electricity toward its
own RPS obligations.
Current 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 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
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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.
SB 14 continues to allow for unlimited tRECs if they are
associated with an eligible renewable facility. The bill also
allows a retail seller to meet up to 20% of its RPS obligations
with tRECs from out-of-state facilities that cannot meet the new
delivery requirements established in SB 14. The end result of
the change in the delivery requirements and the tREC
requirements is that there is now a 20% cap on most forms of
out-of-state generation.
4) Cost containment : Current law provides that if the
above-market costs of renewable electricity exceed set limits an
IOU is not required to acquire any additional renewable
resources that are priced above the market price. The market
price is determined by the PUC based on forecasts of 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 MPR is not a cap on project costs. An IOU must purchase
renewable electricity even when contract costs exceed the MPR.
However, an IOU is required to acquire this higher-cost
renewable electricity only to the extent that sum total of all
the above-market costs from renewable procurement is less than
the a statutorily set 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 which cost less than the MPR the IOU would
still be required to procure power under those contracts.
The above-market cost cap 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 a
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
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been reached.
Over the past year, there has been significant debate over how
to best contain costs of renewable contracts under a mandatory
renewable procurement program. Parties have settled on two basic
approaches. The first is leave the structure of the current
system in place but alter the MPR so it is not based so heavily
on natural gas forecasts and then increase the caps on
above-market costs to reflect the actually expected costs of
complying with a 33% mandate. The second approach is to
eliminate the cap on the total cost of the RPS and instead
require the PUC to only look at the cost of the individual
renewable contracts a IOU signs and determine if that contract
offers a fair value to rate payers and is just and reasonable.
SB 14 takes the first approach by modifying 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 6% of
an IOU's annual total revenues. This new cost cap allows the
Legislature 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.
SB 14 also calculates the caps on above-market costs of
renewables on an annual basis instead of over the life of the
program as current law does. This means that if in one year the
IOU had reached its above-market cost for that year it would not
have to procure more renewable electricity for that year, but
could have to restart procurement the next year. It is not
clear how this annual cost cap would work with a multiyear
procurement process. Most renewable contracts are for 10 to 20
years in length. Often times, utilities do not actually begin
paying for electricity under a contract for several years after
the contract is completed since the renewable facility is not
yet constructed. Utilities may sign a number of large contracts
in one year and then only a few the next year. This all means
the triggers that would require utilities to procure more or
less renewable electricity may not come into play until several
years after an IOU must make the actual procurement decisions
and could result and less certainty and transparency for
projects bidding into the RPS. Since procurement trends do not
coincide well with an annual cap on costs, a cap based an
utility's revenue in the past year multiplied by 10 to use as a
10 year cap may be a more effective means of monitoring
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above-market costs .
Under current law, the cost cap is only applied to renewable
contracts signed under a competitive solicitation process. It
does not apply to any other efforts the IOUs took to procure
renewable electricity, including signing bi-lateral contracts
and purchasing electricity through standard offer contracts.
These rules have created loopholes that allow utilities to sign
a number of contracts that are not subject to the cost cap. The
loophole means that the actual total costs of the RPS are not
actually included in the mechanism intended to control above
market costs. SB 14 leaves this loophole in place. The committee
and the author may wish to clarify this by providing that the
calculations of total above-market costs shall include all
procurement activities that apply to a retail seller's RPS
obligations .
The caps on above-market costs in SB 14 only apply to the IOUs.
As drafted, SB 14 does not provide the same cost protections to
ESPs or the POUs. The committee and the author may wish to
consider amending the bill to provide a similar cap on
above-market costs for other retail sellers of electricity and
for POU's.
5) 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
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insufficient transmission to meet the RPS goals.
SB 14 provides that the PUC may grant a retail seller an
additional two years to meet compliance targets if the PUC
finds, after an evidentiary hearing, that there is inadequate
transmission capacity to meet the RPS or there were
unanticipated permitting delays for planned eligible renewable
electricity projects. The retail seller must also show that it
made reasonable efforts to procure cost effective distribute
generation resources and to procure RECs.
Under current law, there is no penalty or enforcement mechanism
for POUs since there is no specific RPS mandate for the POUs.
SB 14 provides that CARB may enforce penalties on the POUs if
they fail to meet their RPS targets.
6) 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 POU 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.
SB 14 requires most POUs to meet the 33% RPS by 2020
requirement. While the bill requires each POU to set its own
RPS, the bill also provides that the CEC shall establish a 33%
RPS for each POU and enforce the RPS upon the establishment of
the RPS standards. It also requires the CEC, in consultation
with CARB, to adopt regulations for the enforcement of the RPS
on POUs. CARB then has the authority to impose penalties on POUs
for failure to comply with the RPS
Most of the POUs do not object to creating a specific POU RPS
mandate. However they believe that they should be allowed to
make most of the procurement decision on their own and the
requiring the CEC to establish an RPS and regulations for
enforcement is unnecessary and hinders their local control. The
POUs have also 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.
7) Siting transmission and generation: Current law provides the
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CEC with theauthority to site electric thermal generation
facilities with a capacity of greater than 50 MW. As part of
compliance with the California Environmental Quality Act (CEQA),
other state agencies provide input, such as the Coastal
Commission and/or the Department of Fish and Game. A number of
renewable generators do not fall under CEC jurisdiction because
they are smaller than 50 MW or they do not use thermal
technologies, and therefore, are approved and sited by local
jurisdictions. Any major transmission lines needed to connect
renewable regions of the state with the high-voltage
transmission grid must be approved by the CalISO, the PUC, and
the Federal Energy Regulatory Commission (FERC). If a generator
or an IOU wants to develop a project on federal land, then the
project must also be approved by at least one federal agency.
Additionally, most POUs do not need approval from either the
CalISO or the PUC to construct new transmission lines; instead,
they follow their own local approval process
This complex approval process has delayed the development of a
number of proposed projects. There is evidence that even when
one state agency wants to streamline approval of a specific
process approval is almost always delayed once the agency has to
coordinate activates with other state agencies or with the
federal government.
Using funds from a grant from the CEC, a group composed of
representatives from renewable developers, utilities,
environmental groups, land owners, the PUC, and the CEC began
convening meetings over a year ago to develop long-term
development and transmission plans for renewable energy in
California. The group, know as the Renewable Energy Transmission
Initiative (RETI), has already identified a number of Clean
Renewable Energy Zones (CREZs) where there is large potential
for renewable development and has started the work of fine
tuning these zones and identifying specific transmission
corridors that could be developed to connect the CREZs to the
main transmission grid.
While the RETI process includes participation from a broad range
of interests including the CEC and the PUC, it is a stakeholder
driven process that has not been subject to state open meeting
laws. Consequently, it is likely that some parties that could be
affected by the development of CREZs or transmission corridors
have not had adequate opportunity to comment on the proceeding
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and that RETI has not developed a sufficient legal record to
allow transmission and generation permitting agencies to adopt
RETI recommendations without public review.
SB 14 tries to address the problems in permitting new renewable
generation and transmission by requiring:
1)The PUC to approve the application to construct a transmission
line within one year of filing if the line is needed to
provide transmission to achieve the goals of the RPS if the
transmission line does not threaten substantial harm to the
environment that necessitates a longer time for review under
the CEQA.
2)Requires the CalISO to undertake all feasible efforts to
cooperate with POUs and IOUs to develop statewide transmission
plans that incorporate POU plans and potential joint
transmission ownership plans between IOUs, POUs, and private
entities.
3)Requires the CEC to facilitate the development of annual
statewide transmission plans that incorporate POU transmission
plans and IOU plans.
4)Requires the CEC to facilitate the siting and approval of new
transmission lines that can be jointly owned by POUs, IOUs,
and merchant generators. This last provision could be read to
give the CEC authority to site transmission lines. The CEC
does not have this authority under current law and instead the
authority rests with the PUC or FERC. Without removing the
PUCs authority, this provision could actually create another
layer of complexity and delays to transmission siting. The
committee and the author may wish to consider removing this
new authority from the bill .
8) Transition Issues : SB 14 changes some of the current rules
regarding what resources are eligible and how resources can be
procured. Given the fact that these rule changes will impact
already committed investments needed to build renewable
resources, it is important that the transition from the current
rules to the new rules is carefully addressed.
A prior version of SB 14 addressed the transition from the
current procurement rules to the new rules by allowing the
current rules of procurement to continue to apply to procurement
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needed to meet the 20% RPS, and then applied the new rules to
all procurement beyond 20%.
The current version of SB 14 takes a more abrupt approach and
changes the eligible rules for all renewable resources effective
January 1, 2010, even for resources that are already under
contract. SB 14 does contain grandfather clauses that allow
utilities to continue to count renewable resources that are made
ineligible by SB 14 toward their RPS obligations if the utility
had signed a contract or procured actual electricity from the
facilities prior to the passage of this bill. The clauses,
however, appear to leave some gaps and could result in renewable
resources that are already serving California load today or are
under development to meet California's RPS being ruled
ineligible under the new RPS rules.
The PUC and Evolution Markets, a firm that runs markets for
trading of REC, have both expressed concerns that retroactive
nature of the transition clauses in the bill could hinder
renewable development if current investments in renewable energy
appears to not count toward California's RPS.
1)Technical amendments :
1) On page 10, line 13, strike "at least 20" and insert
"33", Strike line 15 and insert "by December 31, 2020."
2) On page 13, line 39, strike "The" and replace "sold to"
with "procured by"
3) Move definition of "delivered" located in the Public
Resources code into the 399.12 of the Public Utilities
Code.
4) On page 47, line 23, replace "may" with "shall"
5) On page 49, replace "may" with "shall"
6) On page 50, strike lines 9 through 25
7) On page 66, line 32, replace "report prepared pursuant
to Section 910" with "reports prepared under SB 14."
8) On page 65, strike lines 1 - 28.
REGISTERED SUPPORT / OPPOSITION :
Support
California Public Utilities Commission (CPUC) (if amended)
California State Association of Electrical Workers
SB 14
Page Q
California State Pipe Trades Council
California Wind Energy Association (CalWEA) (if amended)
Coalition of California Utility Employees
Natural Resources Defense Council (NRDC) (if amended)
Planning and Conservation League (if amended)
TURN (if amended)
Union of Concerned Scientists (UCS) (if amended)
Western States Council of Sheet Metal Workers
Opposition
California Biomass Energy Alliance
California Manufacturers & Technology Association (CMTA)
City of Roseville
Clean Power Campaign
Covanta Energy
Evolution Markets, Inc. (unless amended)
Independent Energy Producers
Pacific Power (unless amended)
Renewable Alliance
Terra-Gen Power
Western States Petroleum Association (WSPA) (unless amended)
Analysis Prepared by : Edward Randolph / U. & C. / (916)
319-2083