BILL ANALYSIS Ó
SBX1 2
Page 1
Date of Hearing: March 3, 2011
ASSEMBLY COMMITTEE ON UTILITIES AND COMMERCE
Steven Bradford, Chair
SB 2 X1 (Simitian) - As Introduced: February 1, 2011
SENATE VOTE : 26-11
SUBJECT : California Renewable Portfolio Standard.
SUMMARY : Increases California's renewables portfolio standard º
(RPS) to require all retail sellers of electricity and all º
publicly owned utilities (POUs) to procure at least 33% of º
electricity delivered to their retail customers from renewable º
resources by 2020. Specifically, this bill :
1)Requires all retail sellers of electricity and all POUs to º
procure renewable energy resources with the following targets:
a) 20% by December 31, 2013;
b) 25% by December 31, 2016; and,
c) 33% by December 31, 2020, and each year thereafter.
2)Authorizes the California Public Utilities Commission (CPUC) º
to waive enforcement and allow retail sellers to delay º
compliance with the renewable procurement requirement if the º
retail seller demonstrates that any of the following º
conditions are beyond its control and will prevent timely º
compliance:
a) Inadequate transmission capacity for delivery of º
sufficient renewable energy;
b) Unanticipated permitting, interconnection or other º
related delays for renewable energy projects or an º
insufficient supply of eligible renewable energy resources º
available to the retail seller; or,
c) Unanticipated curtailment of renewable energy necessary º
to address the needs of a balancing authority.
3)Revises eligibility conditions to allow various electricity º
products from eligible renewable energy resources located º
SBX1 2
Page 2
within the Western Electricity Coordinating Council º
transmission network service territory and differentiates the º
products based on the following three categories of renewable º
energy products:
a) Products that have the first point of interconnection º
with a California balancing authority or other criteria º
primarily scheduled to serve California load at not less º
than the following procurement targets:
i) 50% by December 31, 2013;
ii) 65% by December 31, 2016; and,
iii) 75% thereafter.
b) Firmed and shaped renewable energy products providing º
incremental electricity and scheduled into a California º
balancing authority; or,
c) Renewable energy products that do not meet either º
condition above, including unbundled renewable energy º
credits at not more than the following procurement targets:
i) 25% by December 31, 2013;
ii) 15% by December 31, 2016; and,
iii) 10% thereafter.
4)Requires the CPUC to adopt a process for the rank ordering and º
selection of least-cost and best-fit eligible renewable energy º
resources.
5)Requires the CPUC to adopt rules that permit retail sellers to º
accumulate excess procurement of more-than-10-year contracts º
in one compliance period to be applied to any subsequent º
compliance period.
6)Sets aside 25% of the 33% renewable market for IOU-owned º
generation by requiring the CPUC to approve an application by º
an IOU to construct, own and operate a renewable energy º
facility until IOU-owned renewable facilities equal 8.25% of º
the IOU's anticipated 2020 retail sales.
SBX1 2
Page 3
7)Requires the CPUC to establish a cost limit for each IOU º
according to specified criteria.
8)Prescribes factors that the CPUC must consider when º
establishing a feed-in tariff for electricity generated from a º
renewable generating facility that is less than 3 megawatts º
(MW).
9)Requires the CPUC to determine the effective load carrying º
capacity of wind and solar energy resources on the grid and º
use those values in establishing the contribution of wind and º
solar energy toward meeting resource adequacy requirements.
10)Requires the California Energy Commission (CEC) to refer the º
failure of a POU to comply with the RPS to the Air Resources º
Board, which may impose penalties and requires the penalties º
to be expended for reducing emissions of air pollution or º
greenhouse gases within the same geographic area as the local º
publicly owned electric utility.
11)Appropriates $322,000 from the CPUC Utilities Reimbursement º
Account to the CPUC for additional staffing related to º
transmission lines.
EXISTING LAW requires IOUs and certain other retail sellers to º
achieve a 20% RPS by 2010 and establishes a process and º
standards for renewable procurement.
FISCAL EFFECT : Unknown.
COMMENTS : This bill was introduced as part of a budget package º
introduced in the first extraordinary session that is intended º
to address a fiscal emergency under the State Constitution, º
Article IV, Section 10 (f).
1) Overview : Over the past few years, there have been a few º
attempts to increase the RPS. The original reason for the RPS º
was to diversify the state's generation sources. The California º
Air Resources Board (CARB) is implementing a similar program º
with the intent to reduce greenhouse gases. The author and º
members of the Legislature have convened numerous stakeholder º
meetings to try to reconcile divergent concerns over some º
significant barriers. Some of the most unsurpassable º
impediments have included cost containment, transmission and º
siting constraints, the location of eligible generation and º
SBX1 2
Page 4
whether it is in-state or out-of-state, and how much flexibility º
the utilities will be granted given anticipated or unanticipated º
circumstances.
The utilities' ability to comply with an increased RPS differs º
based on geographic attributes of their service territories. º
While San Diego Gas and Electric (SDG&E) is relatively º
transmission-constricted, any increase in its RPS would need to º
be both in-basin and reliant on significant transmission º
investment. Southern California Edison (SCE) service territory º
is replete with sunshine and windy passes, however, to access º
the huge quantity of renewable energy an increased RPS demands º
also requires investment in transmission infrastructure. º
Pacific Gas and Electric Company (PG&E) in Northern California, º
as a gift of geography, just happens to be endowed with a clean º
and relatively dispatchable watershed in its backyard (RPS º
eligibility only includes hydroelectric facilities under 30 MW). º
Nevertheless, even PG&E needs transmission upgrades to increase º
its generation portfolio to 33% renewables.
2) Groundhog Day : In 2002, the Legislature approved SB 1078 º
(Sher), Chapter 516, Statutes of 2002, which created RPS. Under º
RPS, IOUs and competitive energy service providers (ESPs) of º
electricity were required to increase their renewable º
procurement each year by at least 1% of total sales, so that 20% º
of their sales are from renewable energy sources by December 31, º
2017. This goal was accelerated to 20% renewable power by 2010 º
by SB 107 (Simitian), Chapter 464, Statutes of 2006.
In 2008, SB 14 (Simitian) and AB 64 (Krekorian) proposed to º
increase the RPS to 33% by 2020. Each bill took a different º
approach, but was similar in overarching goals. AB 64 was º
dropped, and the Governor vetoed SB 14. The Governor stated º
that, although he supports the intent of increasing the RPS to º
33% by 2020, the provisions in SB 14 would make achieving that º
goal difficult and too costly. The Governor's veto message º
added that an RPS should provide a streamlined regulatory º
processes and compliance flexibility that facilitates the timely º
construction of in-state resources. The Governor stated that he º
remains ready to sign legislation that codifies a workable 33% º
RPS mandate.
Instead of signing SB 14, the Governor issued an executive order º
(S-21-09) with the same RPS goals and directed the CARB to adopt º
regulations using its authority for greenhouse gas reduction º
SBX1 2
Page 5
efforts provided by AB 32 (Nunez), Chapter 488, Statutes of º
2006. The executive order referred to the standard as the º
Renewable Electricity Standard (RES). The CARB was expected to º
complete the regulations implementing the 33% RES by July 31, º
2010. (The CARB authority to impose penalties for º
non-compliance of RES continues to be questioned. Although CARB º
estimates that the RES may reduce greenhouse gas emission from º
California's electricity sector by about 12 to 13 million metric º
tons of carbon dioxide equivalents
(MMT CO2) per year by 2020, actual emission reductions may not º
be realized due to dirtier-burning gas-fired quick-start º
generation needed to firm and shape the intermittent º
renewables.)
In 2009, SB 722 (Simitian) also attempted to increase the RPS to º
33% by 2020. That bill passed both houses; however, due to the º
legislative calendar, the Senate adjourned before it could vote º
on concurrence. This year, SB 23 (Simitian) is virtually º
identical to this bill and was introduced in the regular º
session.
3) The Utilities' Report Card : The CPUC reports that since the º
RPS statute took effect in 2003, 1,702 MW of actual capacity has º
come on-line. The IOUs, which provide service to about º
three-fourths of California utility customers, served 15% of º
their 2009 retail electricity sales with renewable power, with º
the breakdown as follows:
Pacific Gas and Electric (PG&E) 14.4%;
Southern California Edison (SCE) 17.4%; and,
San Diego Gas & Electric (SDG&E) 10.5%.
The CPUC has approved 181 contracts for about 14,000 MW of new º
and existing eligible renewable energy capacity, with another º
4,000 MW of contracts under review. The 2009 bids alone would º
meet half of IOUs' 33% target. However, contracting continues º
due to anticipated challenges of bringing all of that generation º
online.
The CPUC expects to see an even greater increase in 2010; º
estimated to reach approximately 18% for the three largest IOUs. º
Utilities will file their 2010 compliance reports on March 1, º
2011, which should disclose actual percentages for 2010.
California has 46 local POUs which include municipal utilities, º
SBX1 2
Page 6
irrigation districts, and joint powers authorities. They º
collectively serve approximately 25% of California's retail º
electrical load.
The POUs are required to implement a RPS differently. SB 107 º
requires that the governing board of a local POU annually report º
the utility's status in implementing a RPS and progress toward º
attaining the standard to its customers. In addition, the º
governing board is require to report to the CEC the information º
that the governing board is required to annually report to their º
customers.
Most POUs have adopted a RPS target of 20% but the dates for º
achieving that goal varies greatly starting in 2010 for some and º
going out as far as 2020 for others. Some POUs (14) have º
already adopted a 33% (or more) by 2020 target.
Compliance data through 2009 and reported by the CEC in November º
2010 show that the POUs' RPS deliveries range from zero to 61%. º
Collectively those data show:
Northern California Power Authority20%;
Sacramento Municipal Utility District21%;
L.A. Department of Water & Power14%; and,
Southern California Power Authority2% - 20%.
4) Why Feed-in tariffs : This bill requires the CPUC to º
consider specific findings when developing the feed-in tariff º
for renewable facilities that are less than 3 MW in size. º
Feed-in tariffs requires the utility to purchase all electricity º
produced by eligible renewable generation and is located within º
the service territory of that utility.
Feed-in tariffs may have been pre-empted by federal law in º
certain circumstances. On July 15, 2010, the Federal Energy º
Regulatory Commission (FERC) issued an order regarding the º
combined heat and power (CHP) feed-in-tariff program. FERC º
established that the rate established by the CPUC cannot exceed º
the avoided cost of the purchasing utility. Under state law, º
the price paid by an IOU for electricity purchased under this º
program is determined by the CPUC.
To find a way to comply with the FERC order while still º
requiring a "must-buy" program similar to a feed-in tariff. On º
December 16, 2010, the CPUC adopted the Renewable Auction º
SBX1 2
Page 7
Mechanism (RAM) decision. The RAM allows renewable distributed º
generation (DG) projects up to 20 MW on the system side of the º
meter to bid its electricity to the utility and the utility can º
select the least cost with the best fit with CPUC review and º
oversight.
5) Why aren't all renewables counted : The CPUC notes that it º
and the utilities are increasingly focused on tapping the º
wholesale DG market for renewables (under 20 MW in size) to º
allow for faster delivery schedules and interconnection at the º
distribution level, without the need for transmission upgrades º
(hence, the RAM). The California Solar Initiative (CSI) and º
SelfGeneration Incentive Program (SGIP) are in place to º
facilitate this mission. Nevertheless, the generation they º
finance do not count toward the utilities' RPS requirements. º
(Under the current feed-in tariff statute, each kWh purchased by º
the utility from the electric generation facility counts toward º
the IOUs' RPS obligations.)
The CSI and SGIP provide incentives to customers to install DG º
consisting of solar photovoltaic, small wind, fuelcells, or DG º
technologies the CPUC determines will support the state's goals º
for the reduction of greenhouse gas emissions. According to the º
CPUC, the CSI and SGIP indirectly contribute to the RPS by º
reducing electricity demand when serving customer load. º
Furthermore, the CPUC states that it provides the customer º
clean, renewable, carbonfree electricity.
The CSI Program has a budget of $3.35 billion over 10 years, and º
the goal is to reach 1,940 MW of installed solar capacity by the º
end of 2016. The goal includes 1,750 MW of capacity from the º
general market program, as well as 190 MW of capacity from the º
low-income programs. The general market program is the main º
incentive program component of the CSI and is administered º
through three program administrators: PG&E, SCE, and California º
Center for Sustainable Energy in SDG&E territory.
The SGIP incentive program has funded over 1,270 on-line º
projects and over 337 MW of rebated capacity. In 2008 alone, º
these projects delivered over 718,000 MWh of electricity to º
California's electricity grid, enough to power nearly 109,000 º
homes for a year. Thermal cogeneration systems (fuel cells, º
engines, and turbines) provided over 63% of the electricity. º
Photovoltaic projects were the second largest supplier at 27%.
SBX1 2
Page 8
6) How effective is "effective" : AB 380 (Nunez), Chapter 367, º
Statutes of 2005, requires the CPUC, in consultation with the º
CAISO, to establish resource adequacy requirements for all º
load-serving entities. AB 380 requires each load-serving entity º
to maintain physical generating capacity adequate to meet its º
load requirements including peak demand and planning and º
operating reserves, and meet the most recent minimum planning º
reserve and reliability criteria approved by the Western Systems º
Coordinating Council or the Western Electricity Coordinating º
Counsel.
Resource adequacy requires the load-serving entities to procure º
sufficient resources so that it is available to the when and º
where needed, in real time, to ensure the safe and reliable º
operation of the grid. Each load-serving entity is required to º
file with the CPUC demonstrating that they have procured º
sufficient capacity resources including reserves needed to serve º
its aggregate system load on a monthly basis. Each entity's º
system requirement is 100 percent of its total forecast load º
plus a 15% reserve, for a total of 115%. In addition, each º
load-serving entity is required to file with the CPUC º
demonstrating procurement of sufficient local resource-adequacy º
resources to meet their obligations in transmission-constrained º
local areas.
In a 2009 preceding the CPUC established the wind and solar load º
carrying capacity for the peak demand hours of the day. The CPUC º
established capacity value use production output data for º
January to determine a capacity value for January, February data º
for February capacity value, etc. This bill, by inserting the º
word "effective" in front of load carrying capacity, will likely º
require the CPUC to undertake a new proceeding to determine the º
contribution of wind and solar energy resources during peak º
demand hours. This allows some parties to argue that the CPUC º
should use annual data for an annual value. The result could º
lead to shortages in months when recorded production data º
indicates that capacity value is much lower than the annual º
Effective Load Carrying Capacity method's results.
Accurate counting of wind and solar production during the peak º
hours is critical for grid reliability. The CPUC should have the º
discretion to utilize the counting methodology that meets the º
need of California. If intermittent resources aren't available º
the CAISO may have to procure backstop resources (if available) º
which will result in duplicative capacity payments and º
SBX1 2
Page 9
unnecessary increased cost to ratepayers.
7) The meter is already running : Current law requires a º
limitation of the total costs of renewable energy at º
above-market prices (market-price referent, or MPR) for º
conventional energy. Although each IOU has statutorily º
prescribed above-market funds, all IOUs exhausted their funds in º
2009. The MPR is no longer used to evaluate whether a contract º
price is reasonable. Instead, the CPUC compares RPS contracts º
to costs of relevant technologies and utilities' other renewable º
opportunities, and allows the utilities to recover the costs in º
rates. According to the Division of Ratepayer Advocates (DRA), º
above-market funds through September 2010, amount to º
$6,007,377,760 or over $6 billion to date.
In June 2009, the CPUC published its 33% RPS Implementation º
Analysis Preliminary Results. The CPUC implies that º
electricity costs will increase significantly in 2020 compared º
to 2008, regardless of whether California mandates a 33% RPS or º
not. The CPUC calculated the cost impacts in differing º
scenarios.
Under the all-gas scenario (no more renewables after 2007), on º
the natural, average electricity costs per kilowatt-hour (kWh) º
are expected to increase 16.7% or by $49.2 billion from 2008 to º
2020. This increase results from the need to maintain and º
replace aging transmission and distribution infrastructure, º
anticipated investments in advanced metering infrastructure, and º
other smart-grid capabilities.
Under the 20% RPS reference case (current law) the average º
electricity costs per kWh increase would be 19.7% or $50.6 º
billion compared to 2008.
From the 20% to the 33% RPS case, the CPUC estimates a cost º
increase of 7.1%, or a total of $54.2 billion more by 2020. º
This increase included the costs associated with more expensive º
generation resources, new transmission, and other resources that º
will be needed to provide back-up generation when renewable º
electricity is not available. The estimate assumes the º
utilities will continue the same balance of renewable º
technologies, which includes a large reliance on wind and solar º
energy, and that the direct costs of building new renewable º
facilities remains unchanged over time and thus does not account º
for potential technology-related decreases in costs over time.
SBX1 2
Page 10
The high-distributed generation case is significantly higher º
than the 33% RPS reference case, with a 14.6% cost premium º
compared to the 20% RPS case, and a 7% cost premium compared to º
the 33% RPS reference case. This is due to the heavy reliance º
on solar PV resources, which are currently much costlier than º
wind and central station solar.
The CAISO, in its 2008 Report on Preliminary Renewable º
Transmission Plans, identified six 500 kV transmission lines º
that, if built and brought on-line by 2020, can help the state º
meet the 33% renewable standard in 2020 and for several years º
beyond. These potential transmission projects, intended to º
connect and deliver renewable resources to the grid, were º
estimated to cost a total of approximately $6.5 billion (+/- 50% º
accuracy) in 2008 dollars.
Since then, the CAISO performed a more rigorous analysis and º
determined that renewable generation development is "highly º
aligned" with CAISO approved transmission. In a December 2010 º
presentation, the CAISO identified 7 transmission upgrades that º
are under contract and/or in the CAISO interconnection queue. º
It also itemized a list of "other" CAISO grid upgrades. If all º
projects are completed by 2017, if fully utilized, they can meet º
the CAISO net short for the load-serving entities' forecasted º
retail sales under a 33% RPS. The CAISO did not provide a cost º
estimate for the transmission upgrades or the new transmission º
line needed for a high out-of-state scenario. The costs for the º
upgrades are currently being incurred by the transmission º
owners, mostly the IOUs, which are recovering the costs in º
rates.
The Division of Ratepayer Advocates (DRA) supports the RPS º
program, however, it is concerned that the "perceived urgency to º
comply with the RPS and continuing CPUC approval of high-priced º
contracts has created an inelastic demand and subsequently º
driven the renewable market to yield very high prices." DRA º
continues to state that the above-market funds intended to cover º
the costs of renewable energy that exceed the costs of º
comparable conventional generation, have failed as a º
cost-containment mechanism, having been fully allocated in 2009. º
The DRA states that the CPUC has approved nearly every º
renewable contract filed by the utilities, even when contracts º
rate poorly on a least-cost, best-fit criteria.
SBX1 2
Page 11
At the urging of this committee in last year's predecessor to º
this bill (SB 722), an amendment was included to require the º
CPUC to establish a limitation for each electrical corporation º
on the procurement expenditures for all eligible renewable º
energy resources used to comply with the RPS. In addition, the º
amendment prescribes factors on which the CPUC shall rely when º
establishing the cost limitations. Those amendments are both º
included in this bill. However, this bill does not include º
adequate provision to monitor the costs for direct access º
providers and to adjust the goals of the program if costs are º
too high.
8) How many departments does it take to? : This bill requires º
the CPUC to review and approve the IOUs' RPS contracts and º
costs. POU oversight and enforcement is bifurcated. The CEC is º
required to adopt regulations to enforce the RPS on the POUs. º
The CARB is allowed to impose penalties to enforce the RPS on º
the POUs. If CARB imposes penalties, this bill requires those º
penalties to be deposited into the Air Pollution Control Fund in º
the State Treasury. Upon appropriation by the Legislature, this º
bill requires the funds to be expended for reducing greenhouse º
gas emissions in the same geographic area as the POU.
Last year, this committee raised concerns about the POU º
penalties being deposited in the State Treasury. First, POUs º
are not investor-owned and do not have "shareholder" funds or º
different revenue streams to be tapped for penalties. º
Ratepayers will pay for all penalties. Second, once funds are º
deposited into the State Treasury, the department administering º
the fund will likely need around 10% - 15% of the funds for º
support. In addition, current law provides for the recovery of º
General Fund costs for statewide general administrative º
expenditures (Pro Rata) from special funds. Third, there is no º
indication that the CARB will choose projects that directly º
benefit the ratepayers who pay the penalty. As such, the value º
ratepayers are supposed to get back in "projects" may be less º
than what was paid in penalties.
9) Concerns about the bill : The opposition received by the º
committee has expressed broad concerns about the costs to comply º
with the programs and perceived barriers to compliance for ESPs. º
The most prominent concern is the restrictive "banking" º
provisions. In 2006, the CPUC allowed unlimited forward banking º
SBX1 2
Page 12
of surplus procurement. This bill restricts the ability for º
utilities to bank RPS-eligible energy deliveries from contracts º
that are shorter than 10 years. The Sacramento Municipal º
Utility District (SMUD), PG&E, and others have over-procured º
renewables due to either getting a good price or to "hedge" in º
anticipation of declining prices in out years. PG&E states that º
this limitation picks winners and losers by discriminating º
between existing generators who often sign shorter contract º
extensions and new developers seeking longer-term contracts to º
finance their projects.
This bill does not permit banking of generation earned prior to º
January 1, 2011. The ratepayers in the POU and SMUD territories º
that have adopted RPS goals prior to 2011 would be penalized º
because they could not carry forward their generation from prior º
years to meet the goals of future years. SMUD's actual º
renewable generation was above the 20% goals totaling about 561 º
GWh of surplus through 2010. SMUD's practice has been to apply º
excess procurement in one year first in the following year, so º
there is no excess procurement over one year old. SMUD º
estimates the cost of its early compliance at up to $50 million, º
which would be spread across its ratepayer base. SMUD estimates º
a 1% electricity rate increase to SMUD customers would be º
assessed to generate approximately $12.5 million annually, º
exclusively due to this restriction.
Second, this bill limits the amount of renewable energy credits º
the utility may use to comply to just 10% after 2016. PG&E º
states that this limit does not provide procurement flexibility º
and proposes that the bill be modified to reflect the recent º
CPUC tradable renewable energy credit decision (D.11-01-025) º
that limits procurement to no more than 25% of its annual RPS º
requirement. The Alliance for Retail Energy Markets and other º
direct-access participants are concerned that the bill would º
impose higher than necessary costs by restricting the use of º
western state renewable resources that could provide more º
supply, increase competition, and lower costs to consumers.
PG&E and SMUD state that the requirement that the CPUC set º
procurement goals within each of the three compliance periods is º
unrealistic. The utilities state that development does not º
occur in regular intervals and tends to be "lumpy." Current law º
set a one-time goal of 20% by 2010 with flexible compliance out º
to 2013. However the utilities were also required to increase º
renewable generation equal to 1% of retail sales each year. º
SBX1 2
Page 13
This bill eliminates the annual goal and replaces it with the º
three compliance windows of an average of 20% between 2011 and º
2013, 25% by 2016, and 33% by 2020.
The POUs are concerned that the mandates of the first compliance º
period (an average of 20% renewables between 2011 and 2013) is º
too onerous. Instead they have requested amendments to extend º
the deadline and establish a flat mandate of 20% by 2014 in lieu º
of the first compliance period. Los Angeles Department of Water º
and Power (LADWP) requests that they be allowed to calculate an º
average over each of the compliance periods to equal the º
respective RPS target for the period.
The California Municipal Utilities Association is concerned that º
the bill would mandate RPS compliance, in detail, on the POUs º
for the first time. The POUs were called upon in 2002 to adopt º
RPS goals which reflected the program adopted by the Legislature º
for retail sellers. Most POUs then adopted a goal of 20% by º
2017 as originally called for. However, when the Legislature º
accelerated the 2017 deadline to 2010, some municipal utilities º
did not follow and retained their 2017 goals.
The Energy Service Providers are concerned about the bill's º
intent to require the utilities to engage in long-term º
contracts. Since deregulation of the electricity market in 1996 º
a certain number of businesses have procured electricity on the º
wholesale market and delivered that power directly to wholesale º
customers such as Safeway. They generally operate on short-term º
contracts (6 to 12 months in duration) and argue that they have º
limited access to renewable development which is largely tied-up º
in long-term commitments and therefore restricts their access to º
renewables.
REGISTERED SUPPORT / OPPOSITION :
Support
3Degrees
Abengoa Solar
AES
American Lung Association in California
American Wind Energy Association
Amonix
Applied Materials
SBX1 2
Page 14
BrightSource Energy
California Association of Sanitation Agencies (CASA)
California Biomass Energy Alliance (CBEA)
California Center for Sustainable Energy
California Interfaith Power & Light
California Labor Federation
California Municipal Utilities Association (CMUA) (if amended)
California State Association of Electrical Workers
California State Pipe Trades Council
California Wind Energy Association (CalWEA)
Calpine Corporation
Catholic Charities Diocese of Stockton
Clean power Campaign
CleanTech San Diego
Coalition of California Utility Employees (CCUE)
Division of Ratepayer Advocates (DRA)
Element Power
Energy Independence Now (EIN)
Environmental Defense Fund
Environmental Entrepreneurs (E2)
enXco
First Solar
FRV Renewables
FuelCell Energy
GE Energy
Horizon Wind Energy
Iberdrola Renewables
Independent Energy Producers Association
Infinia
Large-Scale Solar Association (LSA)
League of California Cities (if amended)
LS Power Development, LLC
Natural Resources Defense Council (NRDC)
NextEra Energy Resources
Northern California Power Agency (NCPA)
NRG
Oak Creek Energy Systems, Inc.
Ormat Technologies
Recurrent Energy Suntech
San Diego Gas and Electric (SDG&E)
San Joaquin Valley Regional Green Jobs Coalition
Sanitation Districts of Los Angeles County
Schott Solar
Sempra Energy Utilities
Sierra Club California
SBX1 2
Page 15
Solar Millennium
Southern California Edison
Southern California Gas Company
State Building and Construction Trades Council of California
SunPower
Terra-Gen Power
Tessera Solar
The Solar Alliance
Union of Concerned Scientists
Vestas-American Wind Technology, Inc.
Vote Solar
Western States Council of Sheet Metal Workers
Western Power Trading Forum (WPTF) (if amended)
Opposition
Air Liquide Industrial U.S. LP
Air Products and Chemicals, Inc.
Alliance for Retail Energy Markets (AReM)
Anheuser Busch
California Alliance for Choice in Energy Solutions
California Business Properties Association
California Grocers Association
California Large Energy Consumers Association (CLECA)
California League of Food Processors
California Manufacturers & Technology Association (CMTA)
California Retailers Association
California Steel Industries, Inc.
CalPortland Company
CEMEX California Cement
Chemical Industry Council of California
Direct Energy Services, LLC
Kinder Morgan Energy Partners
Lehigh Hanson
Linde
Mitsubishi Cement Corporation
National Cement Corporation
Pacific Gas and Electric Company (PG&E) (unless amended)
Praxair, Inc.
Schnitzer Steel Industries
School Project for Utility Rate Reduction
Specialty Minerals, Inc.
TXI Riverside Cement
Western States Petroleum Association
SBX1 2
Page 16
Analysis Prepared by : Gina Adams / U. & C. / (916) 319-2083