BILL ANALYSIS
AB 2006
Page 1
Date of Hearing: April 19, 2004
ASSEMBLY COMMITTEE ON UTILITIES AND COMMERCE
Sarah Reyes, Chair
AB 2006 (Nu?ez) - As Amended: April 12, 2004
SUBJECT : Electrical restructuring: Reliable Electric Service
Act of 2004.
SUMMARY : Establishes the Reliable Electric Services Act of
2004. This bill sets up requirements for establishing a core
and noncore model of electric service, cost recovery of
investments made by a utility or the utilities full costs of
contracting, utilities obligation to file an integrated resource
investment plan, generation resource selection, resource
adequacy for all load serving entities, and transmission
investment. Specifically, this bill :
Finds that:
1)An adequate and reliable supply of electricity is essential to
the health, safety, and welfare of all California consumers.
That safe, reliable, and affordable electric service is of
utmost importance to the consumers of this state and its
economy and that electrical corporations have an obligation to
provide their customers with reliable electric service at just
and reasonable rates.
2)California consumers will not receive reliable and affordable
electric service, nor will consumers avoid repetition of past
problems with excessive wholesale electricity prices; rolling
blackouts; and long term supply contracts that threaten
consumers with billions of dollars in above market electricity
costs, unless a durable framework is enacted to support
investment in needed resources.
Declares that:
1)In order to provide safe, reliable, and affordable electric
service to consumers, electrical corporations must provide
needed resources. Which includes cost effective energy
efficiency and demand reduction measures, utility procured
generation, new and repowered generation, co-generation,
renewable generation, transmission and distribution and an
adequately sized and well trained workforce in a manner that
AB 2006
Page 2
produces the best value for ratepayers.
2)In order to ensure that investments in resources are made in a
manner that produces the best value for ratepayers, electrical
corporations should prepare a long term resource plan for
California Public Utilities Commission (CPUC) review and
approval, that achieves a diversified portfolio of efficient,
cost effective supply and demand resources.
3)In order to ensure that the long term resource plan achieves a
diversified portfolio of efficient, cost effective supply and
demand resources, resource adequacy requirements shall be met
first through effective energy efficiency and other demand
reduction measures.
4)In order to ensure that a long term resource plan will result
in investments in resources sufficient to provide reliable
electric service to customers of an electrical corporation
without stranding costs or shifting costs, a stable and
predictable customer base is necessary and essential.
5)In order to attract sufficient capital to make investments in
needed resources, there must be assurance that reasonable
costs and investments, including a return of and on direct
investments, and payments made to third parties under contract
with an electrical corporation for non utility owned
generation, are recovered in rates.
6)Nothing in this bill alters or affects the outcome of
competitive procurement process conducted by an electrical
corporation pursuant to exiting law prior to January 1, 2005.
Definitions in this bill:
1)Electric service as defined in this bill includes providing
adequate, efficient resources, including cost effective energy
efficiency and demand response resources, utility owned and
procured generation, new and repowered generation,
co-generation, renewable generation, transmission and
distribution resources, billing and metering and employing an
adequately sized, well trained utility workforce.
2)Non utility generation as defined in this bill means
facilities for generation of electricity owned and operated by
an entity other than an electrical corporation or an affiliate
AB 2006
Page 3
of an electrical corporation.
Obligation to Serve:
1)Specifies an electrical corporation has an obligation to
provide the utility's customers with reliable electric service
at just and reasonable rates.
2)Specifies an electrical corporation has no obligation to
procure electricity or meet resource adequacy requirements for
any customer who elects to enter a direct transaction.
3)Specifies that no costs shall be incurred by the electrical
corporation as a result of it serving direct access (DA)
customers.
Cost Recovery:
1)Requires CPUC to authorize an electrical corporation to
provide efficient, cost effective resources, including cost
effective energy efficiency and demand response resouces,
utility owned and procured generation resources, new and
repowered resources, co-generation, and renewable generation
resources consistent with long term plans adopted by CPUC.
2)Requires CPUC after a public hearing to approve and maintain
just and reasonable rates sufficient to ensure that the
electrical corporation fully recovers the cost of investments
found reasonable by CPUC over the life of the resource.
Including costs reasonably incurred to operate and maintain
those resources on a timely basis.
3)Specifies cost recovery assurance for investment in resources
applies to 1) direct investment made by an electrical
corporation and 2) an electrical corporations full costs of
contracting for generation resources, including the cost of
collateral requirements and debt equivalence.
Long Term Resource Plan:
1)Requires an electrical corporation to prepare a long term
resource plan (LTRP) consistent with existing law to achieve a
diversified portfolio of efficient cost effective supply and
AB 2006
Page 4
demand resources. LTRP is to include demand and supply
forecasts for 5, 10, 15 year periods and is to reflect energy
efficiency programs approved by CPUC.
2)Requires CPUC, after a public hearing, to review and approve
an electrical corporations LTRP consistent with existing law,
including changes to LTRP that CPUC determines are necessary.
3)Specifies LTRP must provide for investments in practicable
cost effective energy efficiency and demand response
resources, including load management, that offer equivalent or
better system reliability, equivalent or better environmental
improvements, and equivalent or lower costs to ratepayers than
supply alternatives.
4)Specifies LTRP provide for investments in necessary generating
resources, which may include extensions, renewals or
renegotiations of contracts for existing generation resources
that may be new or repowered or co-generation projects.
5)Specifies LTRP may provide for investments in distributed
generation that would improve system reliability thereby
reducing or eliminating investments by the electrical
corporation in distribution facilities. The investments in
distributed generation can come from the electrical
corporation or third party and would result in:
a) Cost savings to ratepayers as a result of deferring or
eliminating utility distribution projects.
b) Reliability and operational characteristics to support
adequate service reliability to customers in the affected
area of the distributed generation.
c) A guarantee from third party distributed generation
operators that contract load reduction will be available
during all required time periods.
6)Requires the continuation of the self generation incentive
program to be administered for ultraclean distributed
generation as it existed on January 1, 2004.
7)Requires an electrical corporations LTRP to meet resource
adequacy needs through owning or contracting for sufficient
physical generation capacity to meet 100% of annual peak
AB 2006
Page 5
demand of electric load serviced by the electrical
corporation, including operating and planning reserve margins
as determined by CPUC. This does not include electrical load
of customers who entered DA.
Generation Resource Selection:
1)Specifies an electrical corporations approved procurement plan
achieve best value for ratepayers by considering price,
reliability, stability, efficiency, cost effectiveness, system
impacts, resource diversity, and risk.
2)Requires an electrical corporation to manage a diversified
portfolio of non utility generation under contract with the
utility, and utility owned generation, combining the potential
benefits of a competitive wholesale market including operating
efficiencies and lower prices, with the stability of cost of
service regulation resources.
3)Requires an electrical corporation to recommend to CPUC
approval of generation resources necessary to meet resource
adequacy requirements consistent with the following:
a) Non utility generation selected through a competitive
solicitation consistent with an electrical corporation
approved procurement plan.
b) Bilateral contracts, determined to be reasonably priced
relative to a CPUC developed market based benchmark, with
non utility generation consistent with an electrical
corporation approved procurement plan.
c) Utility owned generation filed by an electrical
corporation for a certificate of public convenience and
necessity consistent with its approved procurement plan and
determined by CPUC to be reasonably priced relative to a
CPUC developed market based benchmark.
Transmission:
1)Requires an electrical corporation to invest in new or
expanded transmission facilities and control systems that are
needed to ensure efficient use and reliable operation of the
grid.
AB 2006
Page 6
2)Specifies that California Independent System Operator (ISO)
determination of the need for transmission projects to meet
reliability standards shall be conclusive for the purposes of
CPUC's need determination.
Core/Noncore:
1)Establishes a core and noncore electric service model, under
which an electrical corporation is required to provide
electric service to all core customers with a maximum peak
demand of less than 500 kilowatts (kW) on a cost of service
basis, while noncore customers with a maximum peak demand of
at least 500 kW can elect to enter into direct transactions
with a nonutility electric service provider (ESP).
2)Specifies that under a properly constructed core and noncore
structure customers in the core portfolio should be
indifferent to whether a noncore customer purchases
electricity through DA.
3)Requires CPUC to prevent any cost shifting by noncore
customers purchasing electricity through DA to core customers.
4)Establishes a safe harbor of limited duration for noncore
customers to purchase electricity from an electrical
corporation through either paying the higher of incremental
costs of additional short term electricity procured or
generated to serve them or an applicable tariff rate.
5)Requires CPUC on or before December 31, 2005 to adopt rules
and regulations to implement a core and noncore model to
accomplish the following:
a) Core customers and noncore customers not electing direct
transactions to receive electric service from an electrical
corporation on a cost of service basis.
b) Process to allow noncore customers to elect to enter
into a direct transaction and requiring ESPs to be
responsible for meeting CPUC approved resource adequacy
requirements (RARs).
c) Requirement for noncore customers not electing direct
transactions to be subject to a five year rolling
commitment to an electrical corporation.
AB 2006
Page 7
d) Requirement for noncore customers to continue paying
historical costs associated with deregulation, long term
contracts signed by the Department of Water Resources
(DWR), and any utility undercollections.
6)Requires CPUC to defer new elections for direct transactions
subject to approval of a cost recovery mechanism that ensures
that new elections for direct transactions by noncore
customers will not result in the under recovery of any costs
attributable to those noncore customers.
7)Allows customers purchasing electricity through direct
transactions as of January 1, 2005 including customers with a
maximum peak demand of less than 500 kW to elect to continue
purchasing electricity through direct transactions or return
to service provided by an electrical corporation.
8)Specifies CPUC to ensure that no cost shifting or stranded
investments of long term electrical corporation resources
approved by CPUC are made as a result of implementation of
community choice aggregation.
Resource Adequacy:
1)Specifies that all load serving entities, including nonutility
ESPs and community choice aggregators are subject to the same
requirements for resource adequacy, resource diversity, the
renewable portfolio standard (RPS) as an electrical
corporation.
2)Specifies that ISO in consultation with CPUC to establish RARs
to ensure adequate physical generating capacity to meet peak
demand and planning and operating reserves. ISO shall
implement and enforce the requirements in a nondiscriminatory
manner.
3)Allows load serving entities to procure physical generating
capacity through a market based mechanism in order to meet
RARs in this bill.
4)Exempts local publicly owned electrical utilities from this
bill's RARs.
AB 2006
Page 8
EXISTING LAW:
1)Establishes that CEC has the exclusive power to certify all
thermal powerplant sites over 50 MW and related facilities in
the state, whether a new site and related facility or a change
or addition to an existing facility.
2)Establishes that CPUC is responsible to ensure that all
utility customers receive reliable service at just and
reasonable rates and giving CPUC the power to undertake all
necessary actions to properly regulate and supervise
California's investor-owned utilities (IOUs).
3)Establishes that the collection of rates for an IOU be deemed
reasonable and prudent. CPUC is responsible for determining
the inclusion of IOU assets into the rate base as long as they
are deemed used and useful.
4)Establishes a process to allow CPUC to make disallowances to
an IOU project as specified.
5)Requires CEC to develop an Integrated Energy Policy Report at
least every two years, to assess and forecast all aspects of
energy industry supply, production, transportation, delivery
and distribution, demand and prices.
6)Establishes a process whereby CPUC can approve long term
procurement plans filed by the IOUs. The plans are to include
price risk assessments, definition of electricity product,
duration of plan, and a competitive procurement process, an
incentive mechanism if one is proposed and upfront standards
and criteria to be known by the utility prior to execution of
any contract. Power purchase agreements pursuant to this
section are not subject to after the fact reasonableness
review by CPUC.
7)Specifies that the electrical corporations will create or
maintain a diversified procurement portfolio consisting of
both short and long-term electricity and electricity related
and demand reduction programs.
8)Establishes in statute specified charges for a IOUs historical
costs as a result of deregulation, undercollections, and DWR
AB 2006
Page 9
bond and power charges.
9)Suspends direct transactions until the state no longer
procures power and prohibits CPUC from raising rates for
customers below 130 percent of baseline.
FISCAL EFFECT : Unknown.
COMMENTS :
Pre Energy Crisis and Deregulation: Californians before the
energy crisis and the passage of
AB 1890 (Brulte) Chapter 854, Statutes of 1996 had received
stable and predictable electricity service through electrical
corporations under a cost of service regulatory system for
nearly a century. Energy policies at both the federal and state
level, including environmental laws, public policy and
regulatory decisions as well as growing concerns regarding the
efficiency of cost of service regulation prompted the march
toward deregulation and customer choice by the mid 1990s.
Federal policies requiring electrical corporations to purchase
electricity from Qualifying Facilities (QFs) using cogeneration
or renewable technology came about through the Public Utility
Regulatory Policies Act (PURPA) of 1978. Under PURPA the
utilities were required to interconnect with QFs and rates for
electricity purchases from QFs were not to exceed utility
"avoided costs". The purpose of this was to ensure that
ratepayers should be indifferent, from a costs standpoint, to
the use of QF power or utility generation since both should cost
the same. Over time for the utilities in California QF
contracts were cited as a principle reason for the higher than
average cost of electricity in the state.
The next major federal policy to affect California was the
passage of the Energy Policy Act of 1992 (EPAct92). The major
components of EPAct92 was to amend the Federal Power Act (FPA)
to give the Federal Energy Regulatory Commission (FERC)
authority to order utilities to provide interstate transmission
service to any jurisdictional supplier requesting such service.
The EPAct92 also amended the Public Utilities Holding Company
Act (PUCHA) to exempt independent power producers from most of
the provisions of PUCHA and to allow U.S. utility holding
companies to own interest in foreign utilities and vice versa.
AB 2006
Page 10
In California the events that led up to the passage of AB 1890
reflected the policies enacted by the federal government through
PURPA and EPAct92 but there were some key issues unique to
California that accelerated the push for electricity
deregulation. Leading up to deregulation California consumers
and businesses saw the costs of energy increase dramatically as
a result of costs associated with QF contracts, cost overruns in
constructing nuclear generation and newly enacted environmental
laws, which applied to utility generation construction during
the 1970s. Also by the 1980s the rates of all three utilities
were above the national average primarily as a result of
electric utilities heavy reliance on oil fired electric
generation during a time when the price of fossil fuels
skyrocketed.
By 1993 the Division of Strategic Planning in CPUC issued a
report titled California's Electric Service Industry:
Perspectives on the Past, Strategies for the Future , which laid
the foundation for the later CPUC decisions adopting the
wholesale restructuring of the electric industry in California.
The passage of EPAct92 and the growing clamor over cheaper
electricity through consumer choice prompted both regulators and
policymakers to throw caution to the winds and dive headlong
into a comprehensive market reform proposal with the belief that
cheaper power in abundant supply would be available. FERC did
their part in setting the stage with their passage of Order 888
and Order 889 in 1996. Both of these orders were the backstop
for the primary federal foundation for providing transmission
service, ancillary network support services and information
about the availability of these services to support both
wholesale and retail competition in the supply of generating
resources.
Declaring the energy regulation system "fragmented, outdated,
arcane, and unjustifiably complex," CPUC voted in December 1995
to open the state's electricity industry to competition. After
passing unanimously in both houses of the California
legislature, the final legislation was signed into law in 1996
by Republican Governor Pete Wilson, making California the first
state to deregulate electricity.
At the outset, deregulation in California worked well.
Wholesale prices were low, consumer rates were steady and the
new structure appeared to be working. But then, in the spring
and summer of 2000, a kind of "perfect storm" hit the energy
AB 2006
Page 11
market in California.
The Energy Crisis: The passage of AB 1890 and CPUCs Decision
95-12-063 adopting the restructuring of the state's electric
services industry ushered in a new of era of competition
regarding electricity service. All customers under this new
structure would be allowed to choose an electric service
provider other than an IOU for electric service. Electric rates
were cut by 10% via a rate reduction bond and frozen until 2002.
In 2000 San Diego Gas and Electric (SDG&E) had earned
sufficient profits to cover all of its stranded costs and no
longer was subject to the retail price caps set by AB 1890,
which were still kept in place for the other two utilities.
The passage of AB 1890 also authorized the creation of the
California Power Exchange (PX) to operate a statewide short term
market, and required utilities to obtain all their power from
it. PX developed a day ahead and a same day market where PX
accepted bids to sell electricity hour by hour and bids to
purchase hour by hour. Prices for each hour were determined on
a market clearing basis, with all buyers for a given hour paying
the same market clearing price and all sellers receiving the
same market clearing price. The market clearing price was the
lowest price that would provide enough electricity from accepted
sales bids to satisfy all the accepted purchase bids.
Under this system the utilities were allowed to recover costs
that were deemed stranded through the difference between the
price for the frozen utility rates and the price the utilities
purchased electricity in the PX. For the first two years, low
PX prices allowed utilities to collect their stranded costs
ahead of schedule.
AB 1890 also established ISO to control the prices and terms
under which electricity generators could move power across the
grid.
But in the summer of 2000, everything happened at once to start
the energy crisis.
Unusually hot weather during the summer of 2000 in conjunction
with low water levels in the Northwest cut importable
electricity to California. The price of wholesale electricity
sold in the PX started to escalate in 2000 reaching
unprecedented levels over the remainder of the year. In 2000
AB 2006
Page 12
from June to July wholesale electricity prices increased on
average 270 percent over the same period in 1999. Furthermore,
ISOs Stage 3 emergency notifications signaling rotating
blackouts during this time period increased from 1 in 2000 to 38
through May of 2001. During that time most of the notifications
by ISO regarding Stage 3 alerts occurred during the off peak
periods in California, where the state should have had an enough
power to meet system reliability.
The problems IOUs faced during this period was that high
wholesale power prices and the imposition of retail price caps
restricted recovery of these costs, which created severe
financial distress for them. In Pacific Gas and Electric's
(PG&Es) case the utility filed for Chapter 11 bankruptcy
protection on April 2001 because in their estimation they had
spent over $9 billion for wholesale power to service its
customers without any rate recovery from CPUC. Southern
California Edison (SCE) estimated that its unrecovered power
purchase costs during that time period amounted to $2.6 billion
and SDG&E said estimates for them was $447 million.
With the credit lines of the two largest utilities exhausted,
suppliers refused to sell electricity to creditless utilities,
which forced the state to step in with its line of credit and
assume responsibility for buying electricity in the spot market
to keep the lights on for utility customers.
As the crisis worsened into 2001, the state acted urgently to
negotiate long-term contracts (valued at $43 billion) with
generators and suppliers. Meanwhile-after intense media and
political pressure- FERC finally set a wholesale price cap and
must-offer obligations. These and other factors brought price
stability to the market.
Market Manipulation: During and after the energy crisis
regulators and policymakers firmly believed that the market was
being manipulated. Only later did it become known that
companies like Enron had used megawatt laundering schemes to
evade ISO price caps to sell back electricity at much higher
prices to California. Most recently a federal grand jury in San
Francisco charged Reliant Energy Services Inc. for plotting to
hide a multi-million dollar trading loss in June 2000 by
shutting off four of the company's five California power plants,
causing energy prices to rise, then bringing some of the plants
AB 2006
Page 13
online to take advantage of the higher hourly price rates. For
Reliant the scheme resulted in California ratepayers paying up
to $32 million more for electricity during the energy crisis.
Currently the California Attorney General along with the other
agencies are asking FERC to refund billions of dollars back to
California ratepayers for unjust and unreasonable prices charged
for electricity during the energy crisis. ISO estimates that
California ratepayers were overcharged nearly $6 billion during
this time period.
Post Energy Crisis:
Collapse of Deregulation and the State's Entry Into Power
Procurement: To avoid the dysfunctional spot market that
financially decimated IOUs and threatened catastrophic rate
increases, AB X1 1 (Keeley), Chapter 4, Statutes of 2001,
established a structure to permit the DWR to buy needed
electricity for IOU customers under long-term contracts. To
ensure the predictable revenue stream necessary for long-term
contracts, the issuance of ratepayer-backed revenue bonds, and
prevent cost-shifting from DA to bundled service customers, CPUC
was directed to suspend DA to prevent additional migration of
IOU customers.
After a seven-month delay, CPUC suspended DA on September 20,
2001. Between January and June 2001, the vast majority of
customers previously served by DA providers returned to IOU
service, benefiting from retail rates, which were lower and more
stable than market prices.
During the same time period many of those customers who came
back to bundled service as the wholesale market collapsed left
within months to go back to direct transactions as market
conditions improved and the state had procured $43 billion in
power on behalf of IOU customers resulting in a massive cost
shift to bundled ratepayers. An example of this was that from
July 1 to September 20 period, DA increased from approximately
2% to approximately 13% of the total IOU load.
The Consequences for IOU Customers Due to the Energy Crisis:
Since early 2001, the electricity rates set by CPUC for the
customers of the state's major IOUs have exceeded IOUs' ongoing
cost of service, far exceeding the rates of in-state municipal
utilities or any neighboring state, and ranking among the
AB 2006
Page 14
highest in the nation. In January, and again in March, 2001,
CPUC increased rates for the customers of SCE and PG&E a
combined average of 4 cents per kw hour. High-usage residential
customers and the vast majority of business customers who take
bundled service were hit especially hard. Also, the recent PG&E
bankruptcy settlement agreement between CPUC will saddle
ratepayers in PG&E with rates significantly higher than the
national average for the next 9 years.
Furthermore, CPUC in Decision 02-11-022 dedicated a share of IOU
rates to a loan program to defer DA customers' payment of DWR
and IOU procurement costs. In that decision CPUC capped the
payment for these costs applicable to DA customers at 2.7 cents
per kWh. CPUC majority reasoned such a cap was necessary to
maintain the viability of existing DA contracts and prevent jobs
and businesses from leaving the state. It was understood by
parties at that time the 2.7 cents wouldn't pay back what DA
customers owed for DWR power already delivered, or for DWR
operating costs, so a revenue shortfall or "under-collection"
resulted and a tracking account was established to monitor the
amount owed by DA customers. This amortization of DA costs
essentially resulted in a forced loan to be carried by bundled
ratepayers until such time that DA customers payed off the total
amount owed minus changes in the revenue requirement determined
annually by DWR.
Rate Reductions After the Energy Crisis: CPUC Energy Division
released a report on a core/noncore structure showing that
ratepayer costs associated with the energy crisis have gone down
due to the rate reduction for SCE and PG&E bankruptcy settlement
(another reduction may occur for PG&E if the dedicated rate
component is adopted) for the short term. Still even with these
current round of rate reductions over the long run rates will
not begin to decrease again until the end of DWR bond charges,
costs associated with PG&Es bankruptcy, long term DWR contracts,
and on going QF contract obligations.
Furthermore, existing law in AB x1 1 (Keeley) prohibits cost
shifting of any kind to customers below a 130 percent of
baseline, which means over the mid and long term absent any
legislative changes customers using more than 130 percent,
commercial, agricultural and large industrial customers will
bear a disproportionate share of the costs associated with the
energy crisis.
AB 2006
Page 15
Stabilizing Investor Owned Utilities: As a result of the state
utilizing its credit capacity to purchase electricity on behalf
of IOUs through the spot market and through long term power
contracts IOUs have an excess capacity of electricity until
2011. This excess capacity has resulted in IOUs at times
becoming net sellers of electricity to the market versus buyers.
Furthermore, CPUC has approved numerous decisions since the
energy crisis in order to stabilize the utilities through the
following decisions:
D. 02-08-071: Gave the utilities transitional procurement
authority to procure their forecasted on peak residual net
short (RNS) needs (under a low case scenerio) using multi
year contracts.
D. 02-08-071 (renewables): Approved 600 MW of renewable
energy resources under contracts ranging from 1 to 15 years
to assist the utilities in meeting their Renewable Portfolio
Standard (RPS) targets.
D. 02-10-062: Approved the utilities 2003 short term
procurement plans (though the actual power bought or
contracted may cover the utilities needs for up to five
years, which means as late as 2008).
[The above decisions implemented the provisions of AB 57
(Wright), Chapter 835, Statutes of 2002 to prohibit after
the fact reasonableness reviews for IOU power purchase
agreements, require utilities to file long term plans to
CPUC and establish a process to IOUs and CPUC to evaluate
and approve non utility power purchase agreements]
D. 03-08-066: Approved PG&E request to solicit offers to
procure up to 50% of its non baseload needs for 2004.
D. 03-12-059: Approved SCE's request to enter into a long
term Purchased Power Agreeement for the 1,054 MW
Mountainview project.
D. 03-12-062: Authorized the utilities to enter into
contracts with terms up to five years for transactions to
meet 2004 needs with delivery beginning 2004.
D. 04-01-050: Requires utilities to offer a new five year
AB 2006
Page 16
standard offer (SO) one contracts to pre-existing QFs whose
existing contract has either expired or will expire prior to
January 1, 2006.
What This Bill Seeks To Do: According to the author, "AB 2006
seeks to establish a solid framework for the state's power
industry, which should help encourage investment in new power
plants. Such investment has dried up in recent years, in part
due to regulatory uncertainty. We must replace the current
uncertainty in the regulatory environment in California with a
clear energy policy to make sure that we secure power when we
need it at prices we can afford".
Generation Resource Selection: Currently, in California more
than 6,500 MW of power plants have been permitted but not
constructed, because credit fundamentals of independent power
producers are weak. In fact most of the generators are seeking
to enter into long term contracts with an IOU because the
financial markets will only provide capital to projects that
have a clearly defined revenue stream over a longer period of
time (estimate is a minimum of 10 years).
Also, from a financial standpoint credit rating agencies like
Fitch point out that the pendulum is swinging back toward
utility self build or acquisition of power production assets as
a reaction by utilities and state regulators against weak credit
fundamentals of independent power producers and fears of
revocation of physical power supply contracts by bankrupt
generators.
On the issue of the viability of the independent generation
market the Energy Division at CPUC highlights the findings of a
2004 Standard & Poor's study which noted that:
"In less than 10 years, U.S. energy merchant companies have
gone from the cradle to the graveside, if not the grave
itself. In the past two years well over $100 billion of
energy merchant market capitalization has disappeared as
almost everything that could have gone wrong with the
nascent energy merchant industry did?Credit ratings for 12
companies owning more than 200,000 MW of generation
worldwide have fallen from investment grade (in most cases)
to low non investment grade levels."
This bill seeks to provide independent power producers (IPPs) an
AB 2006
Page 17
opportunity to compete for IOU capacity requirements.
Currently, numerous IPPs have generation that has been approved
by CEC that will not be constructed without a long term power
procurement agreement with an IOU. Some of IPPs and ESPs argue
that generation can be constructed through short term retail
contracts but this is contrary to the financial realities of the
market and information from credit rating agencies.
This bill specifies that each IOU in order to meet RARs shall
recommend to CPUC approval for generation through a competitive
solicitation process, bilateral contracts or utility
constructed. If IOU recommends to CPUC generation projects
through either a bilateral or utility constructed process then
CPUC must find that either the bilateral contract or the
Certificate of Public Convenience and Necessity (CPCN) for the
utility constructed generation facility be reasonably priced
relative to a market based benchmark that CPUC has already
adopted in the AB 57 process. This ensures that IOU and CPUC
are indifferent to the approval of generation through contracts
or a utility constructed process but only approve them if they
represent the "best value" for ratepayers.
Opponents argue that the language does not provide the assurance
necessary for IPPs to believe that the process for selecting
generation resources will not be biased toward utility
generation. They cite the inconsistencies in current regulatory
and utility practices like SCE's Mountainview project as reasons
why independent generators may not be have any incentives to
continue to invest in generation in the state.
Intrinsic value of utility owned generation. Some of the
arguments around this issue have been that regulators should
ignore the intrinsic value of utility generation and the
assumption that utility generation is better than non utilty
generation. Specifically, IPPs point out that the state should
compare each of these resources solely on the basis of cost and
value to the ratepayer.
There is clearly an intrinsic value from a policy perspective
and from a ratepayer perspective regarding utility generation.
The costs borne by ratepayers as a direct result of the energy
crisis is clear reminder that we should never place our
electricity dependency in the arms of the market. Only utility
generation is obligated to provide service through
cost-of-service rates for the life of the facility dedicated to
AB 2006
Page 18
ratepayers in the state. Furthermore, the intrinsic value of
utility generation over power purchase contracts is that legally
contracts can be broken as we saw during the energy crisis. As
a result of a contract being broken either intentionally or
unintentionally IOUs, being under an obligation to serve, must
continue providing electricity under cost based rates to those
customers regardless of where they came from.
Some IPPs point out that recent decisions made regarding
Mountainview and SDG&E grid reliability proposal were not fair
and open. Also, some of IPPs support the current AB 57 process
for 3rd party resource selection and say that any further
statutory changes are unnecessary. Furthermore, in recent
discussions a few IPPs supported a process for a guarantee of
each IOUs capacity needs (baseload or reserve) or a 3rd party
decision making entity to decide what an IOU will procure and
how they will procure for it.
The latter proposals to either set aside an IOUs capacity for
IPPs or to have a 3rd party decision maker determine resource
selection is counter to the century old regulatory compact
between regulated utilities and state public utilities
commissions. Under that compact an investor owned public
utility in California is granted 1) an exclusive retail
franchise to serve a specific geographic region; 2) an
opportunity to recover prudently incurred expenses; 3) an
opportunity to earn a reasonable return on investment; and 4)
powers of eminent domain. In return for these privileges, the
utility is subject to cost and price regulation by CPUC, and
required to provide safe and reliable service to all customers
in its service area on a nondiscriminatory basis.
Should CPUC be allowed to adjust an IOUs cost recovery subject
to the amount of risk is involved in power contracts? This bill
requires that the utilities full costs of either direct
investments or procured generation be approved by CPUC after
public hearing in which the costs are found reasonable,
including the costs associated with debt equivalence or
collateral requirements. The cost recovery is further spelled
out to say that it include a reasonable opportunity to fully
recover a reasonable return on investment over the life of the
resource.
The Utility Reform Network (TURN) points out that regarding the
construction of the cost recovery language in this bill should
AB 2006
Page 19
allow CPUC to take into account differing types of risk as it
relates to debt equivalence when approving an authorized return
on equity (ROE) for a PPA. From TURN's perspective this ensures
that CPUC continues to have the regulatory authority to adjust
ROE's depending on the circumstances of how PPA's are viewed by
the financial community and rating agencies as it applies to
each utility.
The dilemma over repowering continues to exist even though the
issue of prioritization is no longer in this bill: California
has over 15,000 MW of generation that was constructed prior to
1980. Some of this generation has been currently repowered but
most are still operating under ISO administered Reliability Must
Run (RMR) contracts which pay the full costs of the generators
(fixed costs plus fuel costs) in exchange for the generators
providing power when called upon. The costs to keep these
contracts serviced are directly passed down to ratepayers in
each IOU service territory amounting to millions of dollars each
year.
Prior to the energy crisis CPUC issued Decision 95-12-063 that
allowed IOUs to voluntarily divest at least 50% of their fossil
generation assets and provided them with incentives in the form
of granting an increase in the rate of return for their equity
component of up to 10 basis points for each 10% of fossil
generating capacity divested. As a result of this decision IOUs
divested a combined 20,187 MW and recouped $3.174 billion for
the sale of their assets. This was over $1 billion above the
book value for these generation facilities. Companies like
Dynegy, Reliant, Calpine, Mirant, Duke and others purchased the
generation divested. Afterwards, most if not all of the
divested generation purchased were eligible for RMR contracts
due to their location and local reliability requirements
established by ISO.
ISO and CEC concerned about the potential retirement of older
generation and its affect on grid reliability. Since the energy
crisis CEC and CPUC have been highlighting the need to have a
comprehensive review of thermal powerplants that need to be
redeveloped (i.e., repowered). In July 2003 CEC issued a staff
paper on Aging Natural Gas Power Plants in California . In the
paper the concerns were raised that a significant number of
older facilities may lack the reliability to be available when
needed as a result of age of the facility and or the need to
retrofit the facility with selective catalytic reduction (SCR)
AB 2006
Page 20
emission control equipment. Furthermore, about 30,000 MW of
dependable capacity is provided by in state natural gas power
plants with a capacity of 50 MW or greater. These facilities
play an important role in the operation of the electric system
by providing needed capacity to meet peak demand, and providing
swing capacity to meet annual electricity needs when imports or
hydroelectric resources are low. Over half of these facilities
were built before the 1960's and have high heat rates making
them 25-50 percent less efficient than plants coming on line.
How important should repowering be in an energy policy debate?
There is a growing concern by ISO that generators are going to
retire their older power plants due to difficulties in getting
financing or for other business reasons. If a growing number of
older facilities begin to be retired this will affect system
reliability because more than 15,000 MW of generation are
supplied by facilities constructed prior to 1980. Other options
that are available to reduce our exposure to the retirement of
older generation are through transmission infrastructure
improvements, clean distributed generation and/or greater demand
reduction and energy efficiency programs. The combination of
these actions would greatly reduce the costs IOUs and ratepayers
pay to keep mostly inefficient generation operating solely for
reliability reasons.
Generation resource selection proposed under the AB 57 process.
Currently, SDG&E has a grid reliability request proposal pending
at CPUC that includes a power purchase agreement with a 585 MW
gas-fired combined-cycle power plant under construction by
Calpine, in SDG&E's service area, that will interconnect with
SDG&E's electric system at the Miguel substation. SDG&E's is
also seeking approval of a 500 MW/base, 555 MW/peak combined
cycle natural gas-fired generation plant to be built by Sempra
Energy Resources and then turned over to SDG&E as a
utility-owned generation project.
The core/noncore model under this bill has five-year rolling
commitment requirement for noncore customers that may be too
long. As this bill is structured a noncore customer is required
to notify an IOU five years before it actually leaves the core
portfolio. There are few companies that would be able to
predict where they want to receive electrical service from that
far in advance. Is there a more realistic time frame that would
work with the realities of how businesses make decisions? Also,
if CPUC establishes an ongoing cost recovery mechanism won't
AB 2006
Page 21
this allow for potentially stranded costs to be recovered by the
core thereby eliminating the need to have such a long rolling
commitment to IOU?
Should there be time frame set for noncore customers seeking
safe harbor in the core portfolio? Under this bill there is no
time frame to leave other than the 5 year rolling commitment for
noncore customers who choose to go to IOU as a default provider.
This bill partially mitigates this question by specifying that
noncore customers under this scenario would be required to pay
the higher of spot or utility generation to service the noncore
or tariff rate.
Still even with the requirement that IOUs charge a different
rate to noncore customers there should be a timeframe
established to require them to make a choice between being a
core or noncore customer.
Any future payment of costs associated to provide electrical
service to noncore customers should not be amortized. As noted
in the background CPUC in 2002 amortized the costs of
electricity procured on behalf of customers who went to direct
transactions after taking safe harbor with an IOU. This "forced
loan" to ratepayers resulted in a customer responsibility
surcharge (CRS) that was set at 2.7 cents/kWh at a total
estimated cost of around $600 million to be paid off over a
number of years. This action to amortize CRS over number years
results in bundled ratepayers having to defer a potential rate
reduction until the payment of CRS is complete. To prevent this
in the future, this bill should prohibit the amortization of
payment costs as a result of procuring electricity on behalf of
noncore customers.
Opponents of the measure want the ability to aggregate lower
than the 500 kW threshold. Electric service providers and some
customer groups support aggregation lower than 500 kW, which
includes aggregation of multiple meters. The concerns regarding
adopting a structure of DA that supports aggregation below 500
kW would result in tremendous uncertainties regarding resource
planning as highlighted by CPUC Energy Division in there
core/noncore report. The report showed that if an uncapped
core/noncore structure were proposed for customers above 500 kW
it would result in a potential forecasting uncertainty of almost
25% of the utilities total load.
AB 2006
Page 22
This bill requires that an IOU either own or contract for
sufficient physical generating capacity to meet 100% of annual
peak demand. This requirement for 100% of peak demand is
similar to the position that ISO proposed in CPUC Long Term
Procurement Proceeding but the utilities argue that this super
reliability is not needed and would result in "insurance" costs
being borne by ratepayers. Some utilities like PG&E have
supported a more modest 90% threshold in the Long Term
Procurement Proceedings.
This bill should specify whether this capacity to meet resource
adequacy should be firm and whether ISO should schedule a day
ahead or month ahead and whether IOUs can utilize market
mechanisms to buy and trade resource capacity.
Should municipal utilities be subject to a resource adequacy
requirement? This bill exempts all local publicly owned
utilities (MUNIs) from having to meet the same RAR that an IOU
has to meet. This bill requires that ISO implement and enforce
resource adequacy for all load serving entities (LSE's) but
exempting MUNIs may cause a free rider problem due to the
possibility that some MUNIs may not have enough reserve capacity
to meet their needs and will lean on everyone else. Currently,
there are major transmission paths that cross the service
territories of MUNIs, which can result in those MUNIs drawing
electricity (without paying) from the grid and leaning on the
rest of the LSE's who procured the necessary resources to meet
their obligations.
Similar bill introduced on the issue of requiring MUNIs to meet
resource adequacy requirements. AB 2499 (Horton) as introduced
requires newly formed municipal utilities after 2001 to meet the
same resource adequacy requirements that apply to electrical
corporations. This bill is currently set to be heard on April
19th in the Assembly Utilities and Commerce Committee.
REGISTERED SUPPORT / OPPOSITION :
Support
Coalition of California Utilities Employees
Southern California Edison
Planning and Conversation League
Consumer Coalition of California
Congress of California Seniors
AB 2006
Page 23
California Labor Federation
California Farm Bureau
Sempra Energy (support if amended)
COMMUNITY ORGANIZATIONS
Access California Services
Asian American Resource Center
California Veterans Stand Down Foundation
Carson African American Empowerment Coalition
CEAC Veterans Employment Committee
Central City Association
CHARO Community Development Group
Community Financial Resource Center
Corona-Norco Family YMCA
Embracing Latina Leadership Alliances
Gateway Chambers Alliance
Human Services Association
Huntington Library, Art Collections and Botanical Gardens
Korean American Coalition, Orange County Chapter
Korean Youth & Community Center
Korean-American Federation of LA
La Casa de San Gabriel Community Center
La Puente Valley Regional Occupational Program
Los Angeles Eye Institute
Los Angeles Urban League, Pasadena Foothill Branch
Los Cerritos YMCA
Meals on Wheels West
Mojave Valley United Way
Mojave Valley United Way
National Coalition of Hispanic Organizations
National Council of Negro Women, Inc.,
North San Diego County NAACP
Orange County Chinese-American Chamber of Commerce
Pasadena NAACP
Pat Brown Institute of Public Affairs
Rubidoux Community Services District
Search To Involve Pilipino Americans
Southeast Community Development Corporation, Pasadena
Tavis Smiley Foundation
United Way of Corona-Morco
Ventura County Taxpayers Association, Visalia
Victor Valley Community Services Council
Victory Community Church, Pomona
AB 2006
Page 24
Watts/Willowbrook Boys & Girls Club
Westlake Village Homeowners Assoc.,
WRAP Family Services
Zona Seca, Lompoc
CONSUMER
Consumer Coalition of California Consumers First
ENVIRONMENTAL
Planning and Conservation League
San Gabriel Mountains Regional Conservancy
LABOR
California Labor Federation, AFL-CIO
Coalition of California Utility Employees
SENIORS
California Senior Action Network Congress of California Seniors
Congress of California Seniors
LOCAL GOVERNMENT
Cheryl Brothers, Fountain Valley City Council Member
City of Agoura Hills
City of Avalon
City of Compton
City of Fillmore
City of Lancaster
City of Port Hueneme
City of Thousand Oaks
City of Tulare
Frank C. Roberts, Mayor of the City of Lancaster
Las Virgenes Water District
San Gabriel Mountains Regional Conservancy
EDUCATION
Compton Community College District
Tulare Joint Union High School District
AB 2006
Page 25
BUSINESS ORGANIZATIONS
Allied Perceptions LLC
American Indian Chamber of Commerce of California
Antelope Valley Board of Trade
Antelope Valley Chamber of Commerce
Artesia Chamber of Commerce
Asian Business Assoc. of Orange County
Asian Business Association
Asian Business League of Southern California
Asian Pacific Islander Small Business Program
Barstow Area Chamber of Commerce
Bell Gardens Association of Merchants and Commerce
Bellflower Chamber of Commerce
Black Business and Professional Association, Inc.
Black Business Association
Black Chamber of Commerce of Orange County
California Black Chamber of Commerce
California City Economic Development Corporation
California DVBE Alliance
California Small Business Association
Carpinteria Valley Chamber of Commerce
Carson Chamber of Commerce
Carson Dominguez Business Council
Central City Association
Cerritos Chamber of Commerce
Chinese American Chamber of Commerce of Orange County
Chinese American Construction Professionals
Costa Mesa Chamber of Commerce
Cudahy Chamber of Commerce
East Los Angeles Chamber of Commerce
Elite Disabled Veterans Bus. Enterprise Network
ExPert, Inc.
Food Industry and Business Roundtable
Future America
Gateway Chambers Alliance
Greater Antelope Valley Economic Alliance
Greater Corona Hispanic Chamber of Commerce
Harbor Association of Industry and Commerce
Highland Area Chamber of Commerce
Inglewood/Airport Area Chamber of Commerce
Inland Valley Economic Development Corporation
Irvine Chamber of Commerce
Laguna Beach Chamber of Commerce
Lakewood Chamber of Commerce
AB 2006
Page 26
Latin Business Association
Lomita Chamber of Commerce
Long Beach Area Chamber of Commerce
Mammoth Lakes Chamber of Commerce
Maywood Chamber of Commerce
Monterey Park Chamber of Commerce
Moreno Valley Chamber of Commerce
Moreno Valley Hispanic Chamber of Commerce
National Center for American Indian Enterprise Development
National Korean American Grocers Association
Natl. Spa and Pool Institute, Region Nine
Orange County Chinese American Chamber of Commerce
Palos Verdes Peninsula Chamber of Commerce
Pomona Chamber of Commerce
Premiere Staffing Service, San Diego
Recycling Black Dollars
Rosemead Chamber of Commerce
San Bernardino Downtown Business Association
San Bernardino Downtown Business Association, Inc.
South Orange County Regional Chambers of Commerce
Southland Better Business Bureau
The Greater Hunting Park Area Chamber of Commerce
The Greater Tulare Chamber of Commerce
Tulare Improvement Program
Tulare Redevelopment Agency
Tulare-Kings Hispanic Chamber of
Turning Point of Central California
Valley Realty
West Covina Chamber of Commerce
Whittier Area Chamber of Commerce
INDEPENDENT BUSINESSES
Affaitati LLC, San Bernardino
African Village Weekend Cultural & Performing Arts Inc.
African Village Weekend Inc., Montclair
Alta Med Health Services, Los Angeles
Apex Computer Systems Inc., Cerritos
Arab American Business Magazine
Armijo Newspapers
Berryman & Henigar, Santa Ana
Cantamor Property Management, Inc., Downey
Central City Company, San Bernardino
Central Courier, Inc., Ventura
Chamber Business Services, Simi Valley
AB 2006
Page 27
Chapman Communications, Palmdale
Criss Air Inc.
Daley Enterprises, Tulare
Dave's Automotive & Eager's Karting, Visalia
Dickerson Employee Benefits, Los Angeles
Doctors Ambulance Services
Doty Bros., Norwalk
Farmdale Creamery
FCI Management Consultants, Commerce
Fleming Associates, Corona
Garcia Architects, Inc.
Gary L. McGavin, AIA, Redlands
Glaab & Associates, San Clemente
Goldmark Gallery & Portraiture, Corona
Graphic Press, City of Commerce
Hendry Telephone Products, Goleta
Herman Weissker, Inc., Bloomington
High Desert Industrial Security Services, Apple Valley
Holistic Healing for Youth, Redlands
Icon Design & Planning Studio, Los Angeles
Ikerd Company, Newport Beach
IMI Data Search, Inc., Thousand Oaks
Inland Action Inc., San Bernardino
Inland Valley Daily News
Inland Valley News
IW Group, Inc., Los Angeles
Jamco & Winnex, Inc., El Monte
Lane Engineers, Tulare
LT Real Estate, Development
McIntosh & Associations, Visalia
Merona Enterprises, Downey
Monte Vista Building Sites, Lancaster
Morris Communications, Los Angeles
Nakatomi & Associates
National Gypsum
One Source Distributors
Perera Construction & Design, Inc., Ontario
Premier Staffing Services
Quality Upholstering, Visalia
RBD Communications
Red Tipi, Hacienda Heights
Res Com Pest Control
Rockview Farms, Downey
Rockwell Scientific, Thousand Oaks
Seaside Graphics & Printing, Fountain Valley
AB 2006
Page 28
Sharon's Bookkeeping Service, Visalia
Sierra Wholesale Hardware, Inc., San Bernardino
Southwest Power, Inc., Santa Fe Springs
Sullivan International, Inc., Long Beach
The Korea Daily
The Korea Daily
Tidwell Excavating, Inc., Saticoy
Truline Golf, Visalia
Ty's Diesel Air & Electric, Tulare
US Battery Manufacturing Co.
USAA Realty
Waste Resources Inc., Gardena
Waters & Faubel Inc., Lake Forest
Wayne Card Insurance, Fountain Valley
Opposition
Independent Energy Producers
The Foundation for Taxpayer and Consumer Rights
California Wind Energy Association
La Paloma Generating Company
California Biomass Energy Alliance (oppose unless amended)
California Manufacturers and Technology Association (oppose
unless amended)
Duke Energy (oppose unless amended)
Western States Petroleum Association (oppose unless amended)
Alliance for Retail Energy Markets (oppose unless amended)
Strategic Energy (oppose unless amended)
The Utility Reform Network (oppose unless amended)
Silicon Valley Manufacturers Group (oppose unless amended)
APS Energy Services (oppose unless amended)
Calpine (oppose unless amended)
Economic Sciences Corp. (oppose unless amended)
Constellation Energy Group (oppose unless amended)
California Cogeneration Council (oppose unless amended)
Analysis Prepared by : Daniel Kim / U. & C. / (916) 319-2083